Oilfield Review. Sourceless Density. Routine Core Analysis. Multistage Stimulation. Hydraulic Fracture Design Software.

Transcription

1 Oilfield Review Summer 2013 Sourceless Density Routine Core Analysis Multistage Stimulation Hydraulic Fracture Design Software

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3 Core Analysis: Combining Expertise for Insight into the Reservoir Managing an asset to optimize oil or gas production requires knowing reservoir rock and fluid properties. For example, planning well locations relies on predictions of porosity and other rock properties from seismic surveys. Stimulation and completion designs depend on knowledge of geomechanical strength and permeability from logging and core measurements. Reservoir simulation demands data on a wide range of properties of the formation rocks and fluids on many scales to engineer field production. Evaluation of the rocks and the fluids within them is vital for reservoir development and management throughout the life of a field. While many reservoir properties can be evaluated remotely with seismic or logging studies, the most detailed and accurate measurements of rocks and fluids come from laboratory evaluations of core samples. The new Schlumberger Reservoir Laboratories organization focuses on the interrelationships of rock and fluid properties to help operators understand oil and gas assets. This organization comprises more than 25 laboratories globally and employs standardized procedures and equipment to support analysis of core data. This comprehensive integration of rock and fluid analysis services helps customers reduce risk in making reservoir development decisions. Combining both services in one organization expands the expertise at hand for execution of the experiments and interpretation of the results. One of the most obvious areas of rock-fluid interaction is in enhanced oil recovery (EOR) studies. To forecast improvements from miscible gas and chemical displacements, engineers require rock and fluid properties at reservoir conditions. EOR laboratory core floods use live reservoir fluids under reservoir conditions. Schlumberger has offered advanced fluids expertise, geomechanics and unconventional resource evaluation for years. In 2012, the company added several commercial conventional core analysis laboratories and established a laboratory hub in Houston. These laboratories provide routine and special core analysis capabilities, with a special emphasis on EOR evaluations for miscible gas and chemical flooding. Throughout its history, Schlumberger has used its breadth and depth of knowledge of the subsurface to develop logging tools, logging-while-drilling techniques, fracturing techniques and other services that require understanding of rock-fluid interactions. The new commercial core analysis capabilities build on this long history of rock studies. As a company, we have always answered questions about reservoirs through petrophysical analysis. Now, we extend this tradition to routine core analysis, answering basic questions about a formation: Does the formation contain fluids? Are hydrocarbons present? Can they flow through the formation? (See Core Truth in Formation Evaluation, page 16). The answers come from measurements of porosity, saturation and permeability. These properties are a part of any petrophysical study of a reservoir. In addition, core measurements provide a means to calibrate log interpretations of electrical properties and nuclear magnetic resonance responses to obtain downhole estimates of porosity and saturations. The petrography and sedimentology of the reservoir core can also be evaluated in detail. Reservoir engineering relies on dynamic flow simulations, and core analysis is fundamental to this activity. Multiphase properties relative permeability and capillary pressure come from measurements made in a special core analysis laboratory. Other flow studies conducted in these laboratories are designed to evaluate EOR processes and assess formation damage caused by a variety of sources. Core analysis is often referred to as the ground truth of rock properties. In the laboratory, we can measure properties more precisely and accurately than through remote sensing. But it is also necessary to understand that laboratory measurements may not be reflective of field conditions. Field conditions can be simulated to a greater or lesser degree, but some alterations to the rock caused by drilling and retrieval are difficult to reverse. To get the full picture, it is necessary to integrate the information from all sources laboratory and field. With the wide range of expertise found in Schlumberger, we can provide the necessary perspective. The future of core analysis is bright. We are commercializing our digital core analysis effort with services ranging from whole core to nanoscale imaging and flow simulation. Additional innovative services will be introduced in coming years. Mark A. Andersen Core Physics Domain Head Schlumberger Reservoir Laboratories Houston, Texas, USA Mark A. Andersen, Schlumberger Domain Head for Core Physics in Houston, joined the company in He spent 11 years as an Oilfield Review editor and executive editor before returning to his roots in core analysis to help build a new business for Schlumberger. He began his career in 1981 as a researcher in rock properties at Amoco Research Center in Tulsa. He subsequently spent several years in Stavanger, where he managed the Amoco Norway external research program and wrote Petroleum Research in North Sea Chalk. Mark is the author of many technical papers, including 23 articles for Oilfield Review. He earned a BS degree in engineering physics from the University of Oklahoma at Norman, USA, and MS and PhD degrees in physics from The Johns Hopkins University in Baltimore, Maryland, USA. 1

4 Schlumberger Oilfield Review Executive Editor Lisa Stewart Senior Editors Tony Smithson Matt Varhaug Rick von Flatern 1 Core Analysis: Combined Expertise for Insight into the Reservoir Editorial contributed by Mark A. Andersen, Core Physics Domain Head, Schlumberger Reservoir Laboratories Editor Richard Nolen-Hoeksema Contributing Editors Ginger Oppenheimer Rana Rottenberg Design/Production Herring Design Mike Messinger Illustration Chris Lockwood Tom McNeff Mike Messinger George Stewart 4 Formation Density from a Cloud, While Drilling A recently introduced formation density tool uses a pulsed neutron generator to induce gamma rays in a formation and compute bulk density. The LWD tool that houses the new measurement system is the first to offer a compact logging suite comparable to a triple-combo service, but without the use of radioisotopic sources. Printing RR Donnelley Wetmore Plant Curtis Weeks 16 Core Truth in Formation Evaluation Oil and gas companies obtain physical samples of subsurface formations through coring. Careful testing of these samples allows operators to determine if the rock contains fluid-filled pores, if those pores contain hydrocarbons and if those hydrocarbons are producible. Routine core analysis helps operators answer these questions and more. On the cover: Core analysis is an essential building block of formation evaluation. Most E&P companies rely on the specialized equipment and expertise of a core analysis laboratory to evaluate their core samples. Here, a core specialist removes a core plug from a solvent distillation and extraction device used to clean the core and measure the volume of any fluids contained therein. A computed tomography scan of a core (inset) shows changes in density indicative of variations in mineralogy or porosity. About Oilfield Review Oilfield Review, a Schlumberger journal, communicates technical advances in finding and producing hydrocarbons to customers, employees and other oilfield professionals. Contributors to articles include industry professionals and experts from around the world; those listed with only geographic location are employees of Schlumberger or its affiliates. Oilfield Review is published quarterly and printed in the USA. Visit for electronic copies of articles in English, Spanish, Chinese and Russian Schlumberger. All rights reserved. Reproductions without permission are strictly prohibited. For a comprehensive dictionary of oilfield terms, see the Schlumberger Oilfield Glossary at 2

5 Summer 2013 Volume 25 Number 2 ISSN Multistage Stimulation in Liquid-Rich Unconventional Formations To optimize the economics of producing oil from liquid-rich shales, service companies are refining the completion technology that has made possible the profitable exploitation of these tight formations. Operators are now able to take advantage of new completion tools and systems, which are designed to significantly improve the efficiency and effectiveness of stimulating low-permeability formations. Advisory Panel Hani Elshahawi Shell Exploration and Production Houston, Texas, USA Gretchen M. Gillis Aramco Services Company Houston, Texas Roland Hamp Woodside Energy Ltd. Perth, Australia Dilip M. Kale ONGC Energy Centre Delhi, India 34 Stimulation Design for Unconventional Resources Taking advantage of the combination of horizontal drilling and hydraulic fracturing technologies, operators are able to access ultralow-permeability reservoirs that contain oil and gas. A systematic, engineered completion design approach using a comprehensive workflow management software system is helping make hydrocarbon extraction from unconventional reservoirs more effective. GG GG GG GG GG GG od Stage 15 Stage 14 Stage 13 Stage 12 Stage 11 Stage 10 Stage 9 Stage 8 George King Apache Corporation Houston, Texas Andrew Lodge Premier Oil plc London, England GG Stage 7 G Stage 6 47 Contributors 49 New Books and Coming in Oilfield Review 51 Defining Hydraulic Fracturing: Elements of Hydraulic Fracturing This is the tenth in a series of introductory articles describing basic concepts of the E&P industry. Editorial correspondence Oilfield Review 5599 San Felipe Houston, TX United States (1) Fax: (1) editoroilfieldreview@slb.com Subscriptions Customer subscriptions can be obtained through any Schlumberger sales office. Paid subscriptions are available from Oilfield Review Services Pear Tree Cottage, Kelsall Road Ashton Hayes, Chester CH3 8BH United Kingdom subscriptions@oilfieldreview.com Distribution inquiries Matt Varhaug Oilfield Review 5599 San Felipe Houston, TX United States (1) DistributionOR@slb.com 3

6 Formation Density from a Cloud, While Drilling Environmental, health and security concerns have encouraged service companies to search for alternatives to the traditional logging sources relied on for formation density measurements. Scientists recently developed a reliable LWD measurement that uses a pulsed neutron generator similar to those that have been deployed in wireline logging tools for decades. Françoise Allioli Valentin Cretoiu Marie-Laure Mauborgne Clamart, France Mike Evans Sugar Land, Texas, USA Roger Griffiths Petaling Jaya, Malaysia Fabien Haranger Christian Stoller Princeton, New Jersey, USA Doug Murray Abu Dhabi, UAE Nicole Reichel Stavanger, Norway Oilfield Review Summer 2013: 25, no. 2. Copyright 2013 Schlumberger. For help in preparation of this article, thanks to Doug Aitken, Sugar Land, Texas. EcoScope and NeoScope are marks of Schlumberger. Formation density logs first appeared in the mid- 1950s. Henri Doll, a Schlumberger research scientist who is credited with the development of the density measurement and many other petrophysical measurements in use today, received a patent for the concept in The formation density tool he helped design uses a radioisotopic source that emits gamma rays and then counts the gamma rays that return to the tool after passing through the formation. Recently, a new technique has been introduced that eliminates the traditional gamma ray source in logging-whiledrilling (LWD) applications. Density tools were originally referred to as gamma-gamma density (GGD) devices because gamma rays were emitted from a logging source and then returning gamma rays that passed through the formation were counted by the tool. 1 The hardware and the electronics used in counting those returning gamma rays have undergone evolutionary changes over the past half century, yet the source has remained a fundamental requirement for formation density logging. Traditional wireline and LWD formation density tools use a cesium [ 137 Cs] gamma ray source. 2 To gain a statistically precise measurement, a 63-gigabequerel (GBq) or higher source strength is normally used. 3 Density tools are not the only tools that use sources for petrophysical measurements. Traditional thermal neutron porosity measurements rely on americium beryllium [ 241 AmBe] sources to generate the neutrons used in the measurement. Service companies go to great lengths to minimize the risks associated with the use of sources; these devices must be handled carefully to avoid health, security and environmental concerns. 4 In a number of locations throughout the world, the use of traditional source material is being discouraged or even banned. In response, service companies have sought to develop alternatives to tools that require sources. 5 Increasingly, pulsed neutron generators (PNGs) are replacing 241 AmBe neutron sources in both LWD and wireline applications. 6 PNGs produce high-energy, fast neutrons using a charged particle accelerator. Inelastic collisions between these fast neutrons and the nuclei of a variety of atoms found in formation fluids and minerals can put those nuclei in an excited state. Typically, the nuclei return to ground state by emitting one or more gamma rays. These gamma rays form a cloud that can act as a distributed source in the formation. The gamma rays undergo attenuation as they travel through the formation. As in the case of a radioisotopic source, the attenuation of these gamma rays depends mainly on the electron density of the materials making up the formation. Scientists have developed a technique that takes advantage of the distributed gamma ray cloud to compute formation density, although they first had to develop a method that accurately modeled gamma ray transport from the formation to one or more detectors on a tool. The resultant bulk density measurement is similar to that 4 Oilfield Review

7 from a GGD tool, but it comes from the neutroninduced gamma rays. The density derived from this technique is referred to as a sourceless neutron gamma density (SNGD) measurement. 7 This article presents the SNGD measurement theory and discusses some of the advantages of a sourceless LWD density tool. Field results validate this new technique. 1. In this article, a source refers to a radioisotopic device used in petrophysical logging tools that emits ionizing radiation. 2. The radioisotope 137 Cs has a half-life of years and emits gamma rays with an average energy level of 662 kev. 3. A becquerel (Bq) is the activity of a quantity of radioactive material in which one nucleus decays per second. Prior to the adoption of Bq as a standard SI unit of measurement, radioactivity was expressed in curies (Ci), which was the radioactivity of 1 g of the radium isotope 226 Ra. 1 GBq = Ci. As Low as Reasonably Achievable Traditional sources used for petrophysical analysis are protected and isolated while being transported to and from drilling rigs and are stored in shields that protect personnel from exposure. Pressure vessels that house the radioactive elements are made from materials designed to protect sources from mechanical damage and 4. Evans M, Allioli F, Cretoiu V, Haranger F, Laporte N, Mauborgne M-L, Nicoletti L, Reichel N, Stoller C, Tarrius M and Griffiths R: Sourceless Neutron-Gamma Density (SNGD): A Radioisotope-Free Bulk Density Measurement: Physics, Principles, Environmental Effects, and Applications, paper SPE , presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, October 8 10, Reichel N, Evans M, Allioli F, Mauborgne M-L, Nicoletti L, Haranger F, Laporte N, Stoller C, Cretoiu V, El Hehiawy E and Rabrei R: Neutron-Gamma Density (NGD): Principles, Field Test Results and Log Quality Control corrosion in the harsh wellbore environment. While inserting a source into a logging tool, workers follow strict safety practices to eliminate potential for exposure. When the tool is lowered below the rig floor, the potential for human exposure goes with it. Sources must be handled carefully, but when established safety precautions are followed, there is little risk of exposure. of a Radioisotope-Free Bulk Density Measurement, Transactions of the SPWLA 53rd Annual Logging Symposium, Cartagena, Colombia, June 16 20, 2012, paper GGG. 6. For more on pulsed neutron generators: Adolph B, Stoller C, Archer M, Codazzi D, el-halawani T, Perciot P, Weller G, Evans M, Grant J, Griffiths R, Hartman D, Sirkin G, Ichikawa M, Scott G, Tribe I and White D: No More Waiting: Formation Evaluation While Drilling, Oilfield Review 17, no. 3 (Autumn 2005): The term sourceless indicates that this measurement does not use radioisotopic sources. Summer

8 Pulsed Neutron Generator Main power n p+ On-off switch Deuterium 2H Controls Tritium 3H > Pulsed neutron generator (PNG). PNGs are self-contained particle accelerators that produce neutrons using a fusion reaction. A high voltage potential accelerates ionized deuterium and tritium isotopes of hydrogen toward a target doped with tritium (top). The fusion reaction (bottom) results in the production of a 4 He nucleus and a neutron. The reaction energy is transferred into the kinetic energy of the two particles and is converted into heat when the particles are stopped in matter. The neutrons leave the reaction with very high speed, having kinetic energy of approximately 14 MeV of the total 17.6 MeV released. When the main power is disconnected, the PNG produces no neutrons. In the early days of the nuclear age, which coincided with the development of many of the tools used in petrophysical analysis, radiation safety practices focused on time, distance and shielding: Minimize exposure time, keep maximum reasonable distance from radiation sources and maintain barriers (shielding) between people and material. These principles are still applied today for working with traditional sources, and exposure limits have been established to ensure the safety and health of workers who routinely handle these materials. Workers are also closely monitored to determine exposure levels. Observations of the long-term effects of radiation on humans resulting from surface detonation of nuclear devices, however, led scientists to develop a new methodology for dealing with human exposure. As low as reasonably achievable (ALARA) has emerged as the standard for regulators. The goal of ALARA is to eliminate exposure whenever and wherever possible, which has driven service companies to investigate alternatives to traditional sources such as 137 Cs and 241 AmBe. A PNG is one example of an alternative to traditional sources. 8 A PNG is a miniature particle generator. Deuterium [ 2 H] and tritium [ 3 H] are accelerated into a tritium-doped target, and high-energy (approximately 14 MeV) neutrons are released (above). When not electrically energized, PNGs do not emit external radiation. Scientists and engineers developed the first PNGs in the 1950s. These devices have since been adopted for many Ion source Helium 4He Neutron n n Target + n n n n p+ p+ n p+ + + High-voltage supply Kinetic energy E (17.6 MeV) downhole applications, including neutron porosity tools, cased hole formation evaluation tools and capture and inelastic spectroscopy services. PNGs have emerged as a viable alternative to 241 AmBe sources. For LWD operations, turbine generators have been developed to supply the downhole electrical power needed to operate PNGs. This advance has allowed design engineers to incorporate PNGs in services such as the EcoScope multifunction logging-while-drilling service and the NeoScope tool. 9 Attempts to replace 137 Cs sources used in GGD tools used for formation density, considered by many geoscientists to be one of the most critical parameters for the quantitative determination of formation porosity, have not met with similar success until recently. Scientists have been unable to replace 137 Cs-dependent measurements for a number of reasons. For example, there is no comparable electronic gamma ray generator, and replacing other sources was deemed a higher priority. The half-life of 241 AmBe is 432 years, much longer than the approximately 30-year half-life of 137 Cs. The activity of an 241 AmBe source is higher and also more difficult to shield. 10 If an LWD logging tool becomes stuck in a well, operators must ensure that the source will remain in place, intact and isolated for hundreds or even thousands of years. The shorter half-life of 137 Cs and its lower radiotoxicity do not remove the risk, but, compared to 241 AmBe, there is a reduced potential for long-term consequences. 11 As a way to mitigate risk associated with 241 AmBe sources, some operators have opted to use PNG-based wireline and LWD neutron porosity tools exclusively rather than tools with a traditional source. Additionally, the prospect that some countries may mandate the elimination of traditional sources entirely is a concern to both operators and service companies. Another reason for the delay in replacing density sources is that bulk density resulting from the GGD measurement is a fairly straightforward petrophysical parameter that has been accepted by the interpretation community for decades. Replacing GGD tools with SNGD tools adds a greater level of complexity and introduces some differences in measurement physics. 12 As a consequence, scientists have invested considerable time and resources in understanding the physics involved in using induced gamma rays for density measurements. In 2005, scientists and engineers at Schlumberger introduced the algorithms needed to compute an SNGD measurement. They were able to demonstrate that a sourceless density measurement that replicated traditional formation density measurements could be produced. Seven years later, they launched the first commercial PNG-based LWD gamma density tool in the oil and gas industry. This tool delivers a high-quality bulk density measurement comparable to that of traditional GGD tools. Because the technique uses a PNG in place of a traditional source, the tool complies with ALARA objectives For more on radioactive sources used in logging tools: Aitken JD, Adolph R, Evans M, Wijeyesekera N, McGowan R and Mackay D: Radiation Sources in Drilling Tools: Comprehensive Risk Analysis in the Design, Development and Operation of LWD Tools, paper SPE 73896, presented at the SPE International Conference on Health, Safety and Environment in Oil and Gas Exploration and Production, Kuala Lumpur, March 20 22, Japan Oil, Gas and Metals National Corporation (JOGMEC), formerly Japan National Oil Corporation (JNOC), and Schlumberger collaborated on a research project to develop LWD technology that reduces the need for traditional chemical sources. Designed around the pulsed neutron generator (PNG), NeoScope and EcoScope services use technology that resulted from this collaboration. The PNG and the comprehensive suite of measurements in a single collar are key components of the NeoScope and EcoScope services that deliver game-changing LWD technology. 10. Sources that emit gamma rays can be shielded using lead, although lead is not an effective shield for neutrons. Shields for neutron sources generally contain polyethylene. 11. Aitken et al, reference In some regions, operators consider the anhydrite measurement a validation of proper tool calibration. This value a density of 2.98 g/cm 3 is outside the quoted formation density range of the SNGD measurement. 13. The PNG used in the NeoScope tool contains a small amount 1.6 Ci of tritium, a radioisotope of hydrogen. The half-life of tritium is 12.3 years. Tritium is also used in conjunction with phosphorous in luminous watch dials and exit signs in buildings. 6 Oilfield Review

9 PNG-Based Measurements Other Measurements Neutron-gamma density Neutron porosity Spectroscopy Sigma Array resistivity Dual ultrasonic caliper Annular pressure while drilling Temperature Azimuthal gamma ray Near-bit inclination Three-axis shock and vibration Near epithermal detector Short-spacing gamma ray detector Far thermal neutron detectors Pulsed neutron generator Neutron flux detector Long-spacing gamma ray detector Near thermal neutron detectors > NeoScope LWD logging tool and its capabilities. Engineers designed the NeoScope tool (bottom) with several collocated petrophysical measurements on a single 7.6-m [25-ft] collar. The table (top) summarizes the tool s capabilities. More Than Just Density The scientists who developed the SNGD model worked with engineers to include this new design concept in the NeoScope sourceless formation evaluation while drilling service. Six petrophysical measurements are incorporated in the NeoScope platform SNGD, neutron porosity, elemental capture spectroscopy, sigma, resistivity and azimuthal natural gamma ray and they are collocated on a single, relatively short collar (above). The NeoScope LWD tool is generally located close to the bit, giving well placement engineers early and precise geosteering data. Near-bit positioning allows the tool to make measurements when drilling fluid invasion is still minimal, which further simplifies data interpretation and modeling. This is especially important for sigma measurements. The NeoScope tool also contains sensors to measure hole size, annular pressure and temperature, near-bit borehole inclination and triaxial shock and vibration. In addition to collocated measurements close to the bit, the NeoScope tool design has other benefits; the SNGD measurement has a greater depth of investigation (DOI) than traditional GGD tools have and is less dependent on wellbore wall contact for accurate measurements. Even a small standoff for the GGD tools may result in compromised measurements, and hole rugosity has always been problematic for traditional density tools (right). The SNGD measurement is collocated with the other neutron-based measurements and resistivity measurements. Conventional logging strings often have separate tools for each measurement. Collocating the sensors reduces the effects of irregular tool movement that can cause misalignment of depth reference points. Collocation also simplifies interpretation because the sensors are simultaneously measuring the same formation volume under identical static and dynamic conditions. The NeoScope service measures neutronbased petrophysical properties, along with bulk density. Most wireline and historical neutron porosity data come from tools that use 241 AmBe sources; the NeoScope service provides a comparable thermal neutron measurement. Formation hydrogen index (HI), the basis of neutron porosity computation, is also an output of the tool. The neutron count rates in near and far helium-3 detectors are used to determine HI and thermal neutron porosity. Compared with traditional thermal neutron porosity, this PNG-based HI is less sensitive to environmental conditions. Fraction of response GGD data SNGD data Sigma another output available from the NeoScope tool is the macroscopic thermal neutron capture cross section of the formation. Sigma is a measurement of the formation s ability to capture, or absorb, thermal neutrons, and the measurement can provide resistivity-independent fluid saturation in the presence of saline formation water. High-energy, fast neutrons are emitted by the tool, slowed by collisions with the nuclei of elements in the formation primarily hydrogen and then absorbed by receptive atoms and molecules. After these neutrons are absorbed, capture gamma rays are generated, which are counted by the detectors. The rate at which thermal neu- Borehole Plan View SNGD measurement volume Azimuthal density Depth of investigation Depth into formation, in. > Greater DOI of the SNGD measurement. Traditional GGD measurements, such as from LWD azimuthal density tools, read only a few inches into the formation (left, red) and have a narrow measurement aperture (right). Hole rugosity may negatively impact the quality of the measurement. Although the SNGD (green) has a greater DOI, which results in a measurement that is less sensitive to rugosity and standoff, it does not have an azimuthal component. Summer

10 Formation Detectors Nuclear source Gamma ray Incident gamma ray Compton Scattering Scattered gamma ray e > Compton scattering of gamma rays. For traditional density tools (left), gamma rays are emitted by a source and then interact with the formation in three main ways. Compton scattering (right) is the primary interaction related to bulk density measurements. Pair production and photoelectric effect (not shown) are the other two interactions. For most well logging situations, the amount of Compton scattering is related to the electron density of the atoms that make up the minerals and fluids in the formation. Electron density is directly related to bulk density. The formation bulk density is computed from the number of gamma rays that make their way from the source, through the formation and back to the detectors. Higher density results in fewer returning gamma rays compared with measurements in lower density formations. Neutron energy, ev Electronic source Traditional source Neutron energy leaving source Average thermal energy ev Inelastic region High energy Intermediate energy Epithermal energy Neutrons with thermal energy Time, μs Capture gamma ray emitted > Life of a neutron. Both electronic and traditional sources emit high-energy, fast neutrons. Neutrons from the PNG electronic source used in the NeoScope tool have an initial kinetic energy of about 14 MeV but in a few microseconds reach thermal energy level (approximately ev). During those first few microseconds, before neutron kinetic energy falls below about 1 MeV, the neutrons experience inelastic collisions that produce gamma rays. These are the gamma rays used for SNGD processing. After several microseconds, the neutrons reach thermal energy level and are eventually captured. The capturing atoms generate gamma rays to return to ground state. trons are captured depends on the capture cross section sigma of the element absorbing them. The capture cross section of chlorine, which is the strongest neutron absorber of common elements encountered in well logging, is higher than that of oil or gas. If the porosity and formation water salinity are known, the water saturation can be determined from sigma. Because the measurement is acquired near the bit, it is possible to determine sigma in the absence of mud filtrate invasion. This establishes a reliable baseline for comparison with future cased hole sigma logs. An added benefit of water saturation computed from sigma data occurs when logging in high-angle wells. When high-angle and horizontal wells cross or approach bedding planes with resistivity contrasts, the resistivity measurements often exhibit anomalous readings. Because sigma data are not similarly affected at bed boundaries, saturation measurements computed from sigma may be more accurate than traditional computations that are based on Archie s equation. Missing from the SNGD measurement is the photoelectric factor (PEF) measurement. Conventional density tools include this lithology indicator for inferring the rock matrix a crucial input for computing density porosity. Although the PEF measurement is not available with the new technique, the NeoScope tool provides neutron capture spectroscopy, which delivers formation elemental composition information. These data offer petrophysicists a more reliable and accurate lithology determination than do PEF measurements. The primary drivers for development of a sourceless density tool have been environmental and security concerns. In some areas of the world, regulations prevent drillers from reentering a reservoir in which a traditional source has been left behind in a stuck drilling assembly. Because PNGs are inactive and cannot produce neutrons when circulation ceases, operators are often permitted to drill sidetrack wells very near a wellbore in which a sourceless tool has been lost. 14 The radioisotope-free nature of the NeoScope service is also attractive in unconventional plays because many of these are located near population centers, where the public may be wary of traditional sources. There are no traditional sources with the NeoScope service, completely eliminating their transportation and handling at the wellsite. The NeoScope service provides real-time natural gamma ray images to steer the well, triple combo data for petrophysical analysis and spectroscopic lithology information to accurately evaluate reservoir quality, but avoids raising public concern regarding the presence of radioactive sources. 8 Oilfield Review

11 It s Not Simple The physics of formation density measurements with GGD tools is relatively straightforward. As the 137 Cs in a typical logging source decays, it emits about gamma rays/s (GR/s). These GRs interact with the electrons of atoms in the formation in a variety of ways but primarily by Compton scattering (previous page, top). 15 These interactions result in most of the GRs being absorbed by the formation, but a few travel back to detectors in the tool located a fixed distance from the source. Formation density measurements are computed from the number of gamma rays traveling from the source to the detectors. From the original pool of GRs emitted by the source, a small fraction of the scattered gamma rays a few hundred to more than 10,000 GR/s will make it to the detectors. High-density rocks with little porosity result in fewer GRs returning to the tool than occurs in porous rocks filled with water, oil or gas. Gamma ray output can also vary from source to source. To compensate for differences in individual sources and detector efficiencies, each tool is calibrated to a fixed reference so the tool delivers the correct downhole density value. As previously noted, engineers have successfully developed tools that replace the 241 AmBe source with PNG-based tools for both neutron porosity and capture spectroscopy. The pursuit of a high-quality, radioisotope-free density measurement has been more elusive because of the lack of electronic gamma ray emitters analogous to PNGs to replace 137 Cs. To overcome this hurdle, Schlumberger scientists adapted some of the principles used for neutron-based measurements, such as spectroscopy and sigma, to develop the SNGD measurement. PNGs generate high-energy neutrons in short bursts. Neutrons leave the tool and interact with the various elements of the formation rocks and fluids. The interactions that have the greatest effect are predominantly elastic collisions with hydrogen nuclei (previous page, bottom). With successive collisions, the initial high-energy neutrons slow down and reach thermal energy level. 16 Thermal neutron porosity tools count the number of thermal neutrons that arrive back at the tool; from this count rate, the traditional thermal neutron porosity is computed. 17 Not all the collisions are elastic. Immediately after the initial burst of neutrons from the PNG, but before the neutrons reach thermal level, inelastic collisions occur between the fast neutrons and atomic nuclei in the formation (above right). Inelastic collisions cause some atomic nuclei to become excited and emit one or more Inelastic Neutron Scattering Neutron Capture Slow neutron n Inelastic gamma rays Excited nucleus > Neutron interactions. The neutron interactions relevant to petrophysical logging can be separated into three categories: Inelastic scatter (top), elastic scatter (not shown) and capture (bottom). Inelastic gamma rays are generated by the interaction of a fast neutron typically with energy greater than 1 MeV with a nucleus. The interaction lifts the nucleus into an excited state, the neutron emerges with less energy and one or more gamma rays are emitted. Also counted among the inelastic gamma rays are those following a high-energy nuclear reaction, such as a reaction in which the neutron knocks out a particle such as an alpha particle, a proton or a second neutron from the nucleus. In elastic scattering, the neutron bounces off the nucleus without pushing it into an excited state. The only energy loss is from the kinetic energy imparted to the nucleus on which the scattering occurs. Elastic scattering from hydrogen, the essential mechanism underlying the neutron porosity measurement, is a result of the collision between particles of equal mass neutron and proton which causes maximum energy loss. The neutron capture reaction, in which a neutron can be absorbed by a nucleus, dominates at low neutron energy. This leaves the absorbing nucleus in an excited state and the resulting deexcitation is accompanied by the emission of gamma rays. 14. In 1999, the US Nuclear Regulatory Commission (NRC) modified existing regulations to exempt PNGs from well abandonment procedures applied to radioisotopic sources. For more: NRC: Regulatory Analysis of Energy Compensation Sources for Well Logging and Other Regulatory Clarifications Changes to 10 CRF Part 39, Office of Nuclear Materials Safety and Safeguards (December 1999), ML0036/ML pdf (accessed April 29, 2013). 15. Compton scattering occurs when a gamma ray collides with an electron, transferring part of its energy to the electron, while itself being scattered. The gamma ray continues at a reduced energy. The degree of Compton n n Excited nucleus Capture gamma ray scattering depends on the electron density of the target material. As the electron density increases, there is more attenuation of gamma ray energy. 16. PNGs emit fast neutrons with a kinetic energy level of about 14 MeV. Thermal neutrons have a kinetic energy of about ev at room temperature. 17. Weller G, Griffiths R, Stoller C, Allioli F, Berheide M, Evans M, Labous L, Dion D and Perciot P: A New Integrated LWD Platform Brings Next-Generation Formation Evaluation Services, Transactions of the SPWLA 46th Annual Logging Symposium, New Orleans, June 26 29, 2005, paper H. Summer

12 GRs as they return to ground state. Scientists are able to use the energy spectrum of inelastic GRs to identify elements such as carbon, oxygen, silicon, calcium, iron and sulfur. Engineers use the volumetric yields of these elements to compute lithology, and this is the basis of neutron spectroscopy measurements. The energy spectrum of inelastic gamma rays is also the basis of carbon/oxygen ratio tools, which are used to identify hydrocarbonbearing zones in cased holes. During the short period of inelastic collisions, a GR cloud forms (below). This artificially generated cloud emits around 10 8 GR/s, about two orders of magnitude lower than the number emitted by a typical 137 Cs source. Scientists have determined, however, that there are sufficient GRs produced to function in a manner similar to that of a traditional source. The GR cloud is short-lived because the neutrons that create it collide with other nuclei, rapidly slow to thermal level and are subsequently captured. The number of gamma rays that result from inelastic collisions and reach the detectors from the GR cloud is influenced by three factors: the Inelastic gamma ray source volume Inelastic gamma ray scattering volume PNG Neutron detector Inelastic scattering Gamma ray detector > Inelastic gamma ray cloud. The PNG generates neutrons that move away from the source and collide inelastically with atoms in the formation (blue shading). These collisions cause a cloud of inelastic gamma rays to form (green shading). Some of these gamma rays will travel back to the tool and be counted by the detectors. Inelastic count rate, counts/s Long-spacing detector response Gamma ray transport Neutron transport Formation density, g/cm 3 > Nuclear transport and long-spacing detector response. The response of the long-spacing gamma ray detector (black) is largely determined by neutron (blue) and gamma ray transport (red). Neutron transport is related to the interactions of neutrons with atomic nuclei in the formation. Inelastic gamma rays are produced during inelastic scattering of fast neutrons. Elastic scattering, which occurs primarily when neutrons collide with hydrogen nuclei, reduces the energy of the fast neutrons below the threshold for producing inelastic gamma rays. Thus, with increased formation density (lower porosity), there are fewer hydrogen nuclei available for elastic scattering and, as a result, there are more fast neutrons available for the production of inelastic gamma rays. Gamma ray transport and the number of inelastic gamma ray counts decrease with increased formation density because the higher electron density provides more opportunity for gamma ray interactions and energy reduction. fast neutron transport from the PNG to the point where inelastic GRs are produced within the formation, the subsequent transport of GRs from their origin back to the detectors in the tool and the electron density of the formation. The GRs generated in the formation by inelastic interactions move rapidly through the formation, interacting in a manner similar to GRs generated by a radioisotopic source, and they are attenuated by collisions with electrons within the formation primarily through Compton scattering (above). Properly characterized, the counts at the detector are used to compute electron density, which in turn is used to compute the formation bulk density. 18 If only inelastic GRs were present, the characterization would be more easily performed; however, another major source of GRs complicates the measurement. Fast neutrons eventually become thermal neutrons and are captured by atoms in the formation. Nuclei that capture thermal neutrons emit GRs to return to a stable energy state in a manner similar to the emission of GRs resulting from inelastic collisions. The population density of thermal neutrons available for capture is directly related to the number of hydrogen atoms in the formation. In a typical downhole environment, the element with the highest probability of absorbing thermal neutrons is chlorine [Cl], whose number density is related to the salinity of the formation fluids. The SNGD measurement is based only on GRs generated by the inelastic collisions. To correctly compute the bulk density value, the contributions from capture GRs resulting from neutron capture must be quantified and removed from the measurement. 19 Engineers must also account for the variability of the initial source strength. The output of a traditional source may vary, depending on age and activity level of the radionuclide, but the output is fairly constant and its change over time is predictable. Calibration of GGD tools accounts for variability between sources and detector efficiencies by correcting to a known reference. The output of a PNG is not as predictable and may vary over short periods of time and even between bursts. A control loop in the NeoScope tool adjusts the PNG to maintain a constant average output, and the tool includes a detector at the 18. Reichel et al, reference Epithermal neutrons have an energy range between about 0.02 ev and 10 kev at room temperature. 10 Oilfield Review

13 NeoScope Calibration Facility NeoScope tool Mud channel Calibration sleeve Aluminum calibration sleeve Water Detectors > NeoScope calibration device. A special calibration facility was developed specifically for the NeoScope tool. Four measurements are performed in a water-filled tank using a calibration sleeve and a simulated mud channel. With the PNG turned on, responses are measured in four configurations: sleeve raised, mud channel filled with air (1); sleeve raised, mud channel filled with water (2); sleeve lowered, mud channel filled with water (3); and sleeve lowered, mud channel filled with air (4). These four measurements allow calibration gains and offsets to be computed and provide quality checks for tool verification. PNG to determine the neutron output and compensate for variations. To provide the specified g/cm 3 accuracy for the density measurement, the SNGD model uses a combination of responses from multiple detectors and requires a complex and demanding calibration. This calibration consists of correlating the count rates measured by each of the tool s detectors to those measured in the same environment with the reference tool. For this purpose, engineers have designed a new calibration tank that allows measurements over a wide range of count rates (above). The uncertainties found in downhole log measurements arise from the primary measurement, applied corrections and conversion of measured parameters to formation properties. To mitigate these uncertainties, the NeoScope service includes a quality control system that begins with general tool system hardware and moves to specific sensor functions, individual sensor measurements and integrated measurements that may involve multiple individual sensor responses (below). The last step of the process is quality control of the final integrated answers that may use multiple measurements. Neutron monitor PNG Long-spacing gamma ray detector Source output correction (neutron monitor) Near epithermal detector Near thermal detector Short-spacing gamma ray detector Far thermal detector Long-spacing gamma ray detector Sigma input Spectroscopy input Neutron porosity input Neutron-gamma density input Neutron transport correction (near epithermal and far thermal detectors) Fast neutron correction (short- and long-spacing gamma ray detectors) Sigma correction SNGD output > Multi-input, multioutput measurements. The nuclear portion of the NeoScope tool (left) uses a single PNG to generate neutrons, but the responses from multiple detectors are integrated to produce specific measurements. For example, sigma data are derived from near thermal, short-spacing gamma ray and long-spacing gamma ray detectors. SNGD data, the most complex measurement from the NeoScope tool, are primarily computed using counts from the long-spacing gamma ray detector, but inputs from the neutron monitor, near epithermal detector, short- and long-spacing gamma ray detectors and far thermal detectors are required to provide an accurate final answer. The flowchart (right) traces the corrections applied to arrive at the final density output. Summer

14 > Specifications for SNGD and GGD tools. Individual quality control considerations that may impact accuracy include sensor and hardware functionality, density values within the 1.7- to 2.9-g/cm 3 range of SNGD and tool standoff. In addition, environmental quality controls include borehole size, deviation, ROP and formation shaliness, all of which may impact measurement accuracy (above). The indicators are combined into a measurement quality control flag. A green flag suggests that the measurement is accurate and within specified limits. A yellow flag indicates that the measurement is likely to be within its specified GGD data, g/cm 3 SNGD GGD Density range 1.7 to 2.9 g/cm to 3.05 g/cm 3 Precision at ROP 61 m/h [200 ft/h] g/cm g/cm 3 Accuracy Clean sandstone, limestone and dolomite g/cm g/cm 3 Shale g/cm g/cm 3 Salt Not applicable g/cm 3 Anhydrite Not applicable g/cm 3 Axial resolution 89 cm [35 in.] 36 cm [14 in.] Depth of investigation 25 cm [10 in.] 10.2 cm [4 in.] Image capability No Yes Data within tolerance Data at limit of tolerance range but may require further interpretation, and a red flag means that the measurement is outside specified accuracy parameters. These quality flag values are crucial for comparing the accuracy of GGD and SNGD measurements. Field Testing and Beyond Field tests for the SNGD measurements consisted of comparing them with GGD measurements using a modified tool that allowed engineers to acquire both measurements simultaneously from the same well using the same SNGD data, g/cm 3 > Crossplot comparison. Density data from a GGD tool were compared with data from an SNGD tool; the data are color-coded by their quality flag value. There is good agreement between the two when SNGD data are within tolerance. The data align well along the ideal axis and are flagged as green. Invasion effects start to occur in the lower density range at approximately 2.3 g/cm 3. The spread of the data points around the ideal line is attributed to differences in the axial resolution of the two measurements while crossing various layers at high deviations. bottomhole assembly. Objectives for field testing included logging in the following: clean sandstone, limestone and dolomite formations anhydrite shale gas and light hydrocarbon reservoirs large boreholes deviated and vertical wells. Scientists compared the GGD measurement, considered the benchmark, with SNGD results and accounted for the differences and limitations of both measurements. Test acceptance criteria were based on a systematic evaluation of both measurements, and final analysis was based on a set of numerical interpretation criteria. 20 The maximum acceptable error when two independent measurements are compared is the sum of their individual accuracies. In this case, the acceptable error for the two measurements is g/cm 3 in clean formations and g/cm 3 in shales. 21 The data from the combined tools were plotted, which allowed engineers to quantify any deviation from perfect agreement. Additionally, scientists had to account for conditions in each well that might impact GGDto-SNGD comparisons. These conditions included filtrate invasion, the presence of gas or light hydrocarbons that may change with time and various drilling conditions, such as mud weight, fluid variations and changes in ROP. If a large discrepancy between the two measurements could be explained by environmental effects, the test was considered acceptable. All tests were performed in 8 1 /2-in. boreholes. In a field test of the NeoScope service, the operator drilled a well with an average inclination of 60 through a sandstone reservoir using 1.26-g/cm 3 [10.5-lbm/galUS] water-base mud (WBM). The caliper log indicated the borehole was in gauge, and no GGD data corrections were required. Additionally, the GGD data indicated no major azimuthal effects. Sigma was within a range that indicated minimal correction to the SNGD. In the hydrocarbon-bearing section of the formation, the resistivity log indicated some invasion (next page). Because of the difference in their DOIs, the SNGD and GGD outputs were slightly different in this zone. By contrast, these measurements were almost identical in a noninvaded water-bearing section of the formation. The SNGD data were within accuracy limits throughout the well (left). 20. Reichel et al, reference Theys P: Log Data Acquisition and Quality Control. Paris: Editions Technip, 2nd edition, Oilfield Review

15 Resistivity Mudcake Washout Density Caliper 8 in. 10 Ultrasonic Caliper 8 in. 10 Gamma Ray 0 gapi in. Attenuation 34-in. Attenuation 28-in. Attenuation 22-in. Attenuation Density Image 16-in. Attenuation 0.02 ohm.m g/cm Deviation 40-in. Phase Shift Sigma 0 degree in. Phase Shift 0 cu 50 Collar 28-in. Phase Shift Image-Derived Density Rotation 22-in. Phase Shift 1.9 g/cm RPM in. Phase Shift Bulk Density Upper Depth, ft 0.2 ohm.m 2, g/cm Density Correction 0.8 g/cm Neutron Density 1.9 g/cm Bulk Density 1.9 g/cm Neutron Porosity (Thermal) 40 % 15 Quadrant Bulk Density Data Average Density 1.9 g/cm Bottom Density 1.9 g/cm Left Density 1.9 g/cm Right Density 1.9 g/cm Up Density 1.9 g/cm Pyrite Water Sandstone Clay Quality Flags X10 X20 X30 X40 X50 X60 X70 > Density comparison in an invaded oil zone. The interval from X10 to X40 ft is an oil-bearing sandstone with mud filtrate invasion. The invasion is indicated by separation in the resistivity curves (Track 2, blue shading). The sandstone below X60 ft (red shading) is water filled, and the lack of separation indicates little to no invasion. The NeoScope tool along with a conventional GGD LWD tool was run in this well. The density image (Track 3) indicates a fairly homogeneous reservoir, as does the lithology computed from spectroscopy data (Track 6). Quadrant density data (Track 5) overlie each other through the two sections, as would be expected with the high-quality wellbore conditions. There is excellent agreement between the traditional density (Track 4, red) and the NeoScope density (black), although there is a slight difference between the two datasets in the oil-bearing interval because of the invasion. These data overlie the thermal neutron porosity data (blue) in clean, water- or oil-filled rocks. (Adapted from Reichel et al, reference 5.) Summer

16 Mudcake Washout Density Caliper 8 in. 10 Ultrasonic Caliper 8 in. 10 Gamma Ray 0 gapi 150 Deviation 0 degree 90 Collar Rotation 0 RPM 500 Depth, ft Resistivity 40-in. Attenuation 34-in. Attenuation 28-in. Attenuation 22-in. Attenuation 16-in. Attenuation 0.02 ohm.m in. Phase Shift 34-in. Phase Shift 28-in. Phase Shift 22-in. Phase Shift 16-in. Phase Shift 0.2 ohm.m 2,000 Density Image 1.7 g/cm Sigma 0 cu 50 Image-Derived Density 1.9 g/cm Bulk Density Bottom 1.9 g/cm Bulk Density Upper 1.9 g/cm Density Correction 0.8 g/cm Neutron Density 1.9 g/cm Bulk Density 1.9 g/cm Neutron Porosity (Thermal) 40 % 15 Quadrant Bulk Density Data Average Density 1.9 g/cm Bottom Density 1.9 g/cm Left Density 1.9 g/cm Right Density 1.9 g/cm Up Density 1.9 g/cm Carbonate Sandstone Clay Quality Flags X10 X20 X30 > Comparison of washout effects on density. Density data were acquired using a NeoScope tool and a conventional GGD LWD tool across a predominantly water-filled carbonate section (Track 6, lithology) of a test well. Caliper data (Track 1) from the NeoScope tool (black) and the traditional density tool (red) indicate an enlarged borehole (blue shading) above and below X12 ft. Resistivity data are presented in Track 2. Track 3 contains density image data from the traditional tool, along with azimuthal density from the bottom (red dashed) and upper (green) quadrants, an image-derived density (black) and sigma data (purple). The bulk density data from the conventional tool (Track 4, red) are affected by hole conditions from X10 to X18 ft, but the NeoScope tool provides good density data (black). The differences in the quadrant data from the traditional GGD tool (Track 5) demonstrate the effects of the enlarged borehole. The left quadrant (blue) and the upper quadrant (green) data are invalid, as is the average computed density (red). The bottom quadrant (pink) and the right quadrant (dark red) data are closer to the NeoScope density in Track 4. While the NeoScope density has a greater DOI and is less affected by washouts or hole rugosity, the yellow quality flag (Track 7) indicates the measurements are approaching the limits. (Adapted from Reichel et al, reference 5.) In another field test conducted in a limestone formation at the Schlumberger test facility in Cameron, Texas, USA, engineers drilled a well with an average inclination of 25 using 1.13-g/cm 3 [9.4-lbm/galUS] WBM (above). The caliper log indicated hole enlargement in the top section of the log. In zones where the SNGD quality control flag was yellow, there were significant differences between the SNGD and GGD data. The density correction on GGD data was generally between 0.1 and 0.15 g/cm 3, which is not usually indicative of compromised data quality resulting from hole rugosity, although the quadrant density data clearly showed effects of the enlarged borehole. Analysis of these two logs highlighted the value of the greater DOI of the SNGD measurement. The SNGD data were borehole corrected and, because of the NeoScope tool s greater DOI, were less influenced by variations in the near-borehole environment. The SNGD curve tracks the thermal neutron porosity curve in clean formations as expected. The SNGD data appear more reliable than the traditional GGD measurement. A Middle East operator tested the new SNGD design in four environments. 22 The NeoScope tool was run in a high-angle, high gas saturation reservoir drilled with nonaqueous mud, a high gas saturation reservoir drilled with WBM, an oilsaturated carbonate reservoir drilled with high- 14 Oilfield Review

17 salinity WBM and an oil-saturated carbonate reservoir drilled with low-salinity WBM. To validate the measurements, traditional GGD tools were run for comparison. The first test was in an 8 1 /2-in. wellbore, in which the high-angle well approached 90 deviation at TD. The nonaqueous mud system was barite-saturated, which invalidated PEF measurements from the GGD tool. The reservoir section was predominantly limestone and the formation density ranged from around 1.95 to 2.7 g/cm 3. A comparison of the data from the GGD tool with those from the NeoScope SNGD measurement shows excellent agreement (right). One benefit of the NeoScope tool is the availability of neutron capture spectroscopy data. Although the PEF measurement from the traditional tool was affected by barite in the mud system, lithology could still be determined using spectroscopy data from the NeoScope tool. The majority of the interval was limestone, although some dolomite was observed. The second example was a vertical well drilled with WBM through a gas-filled carbonate reservoir in the same field as the previous well. Comparison of GGD with SNGD data again showed good agreement across a wide range of values. A third example was drilled with high-salinity WBM through an oil-saturated carbonate reservoir. In this highly deviated well, the porosity data from the GGD and SNGD measurements compared favorably, well within statistical precision limits of the measurements. As is typical of liquid-filled reservoirs, the neutron porosity data values were similar to porosities computed from formation density data. A fourth well was a high-angle well drilled with low-salinity polymer-base WBM. As with the other three wells, there was excellent agreement between the SNGD data and conventional GGD measurements. Petrophysical analysis of data from these four wells demonstrated that in a variety of wells with a wide range of density values, SNGD data from the NeoScope tool compare favorably with data from conventional density tools. In addition to the SNGD data, the neutron porosity and resistivity measurements provide a sourceless triplecombo logging option for LWD applications. Sigma and spectroscopy data are added benefits that petrophysicists can use to better characterize and understand reservoirs. 22. Atfeh M, Al Daghar KA, Al Marzouqi K, Akinsanmi MO, Murray D and Dua R: Neutron Porosity and Formation Density Acquisition Without Chemical Sources in Large Carbonate Reservoirs in the Middle East A Case Study, Transactions of the SPWLA 54th Annual Logging Symposium, New Orleans, June 22 26, 2013, paper KKK. Bit Size 8 in. 10 Ultrasonic Caliper 8 in. 10 Gamma Ray 0 gapi 100 Depth, ft X,300 X,400 X,500 X,600 Sigma Resistivity 40-in. Phase Shift 34-in. Phase Shift 28-in. Phase Shift 22-in. Phase Shift 16-in. Phase Shift 0 cu ohm.m 2,000 Density Correction 0.8 g/cm Neutron Porosity (Corrected) 40 % 15 Bulk Density 1.9 g/cm Density Image Neutron Density 1.9 g/cm g/cm Neutron Porosity (Thermal) Bulk Density 40 % g/cm Lithology Dolomite Sandstone > Density comparison in a barite-weighted mud system. Barite in drilling mud can render PEF measurements invalid. PEF is important for inferring lithology, which is used for porosity calculations. In this high-angle Middle East carbonate reservoir, the spectroscopy data from the NeoScope tool provide mineralogy information (Track 6) that would not have been available from traditional density tools. For example, the data show dolomite mixed with calcite from X,350 to X,420 ft. In the high-density carbonate intervals, such as from X,400 to X,520, the NeoScope density data (Track 4, black) compare favorably with traditional bulk density (red). Traditional thermal neutron porosity (blue) is presented along with a density-corrected thermal neutron porosity (green). The NeoScope tool does not provide azimuthal density or density images as are available from the traditional LWD GGD tool (Track 5). Sigma data (Track 2) may be used to determine changes in hydrocarbon saturation or fluid contacts over time. Track 3 presents resistivity data. (Adapted from Atfeh et al, reference 22.) The Pulse of Things to Come? It has been a long time coming, but the introduction of SNGD technology may revolutionize LWD porosity logging. Replacing sources with PNGs has the potential to eliminate exposure risks and reduce costs associated with source storage, transportation and record keeping. Calcite Introducing similar measurements for wireline applications is the next obvious step. Unfortunately, modeling borehole effects on the measurement for wireline tools has been beyond the reach of current research and software. It may take some time, but if traditional sources can be replaced in wireline tools, the ALARA standard as low as reasonably achievable will be reached in the oil and gas industry. TS Clay Summer

18 Core Truth in Formation Evaluation The nature of subsurface exploration forces oil and gas companies to investigate each reservoir remotely, primarily through well logs, seismic surveys and well tests. Through analysis of rock samples obtained downhole, core laboratories provide a wealth of information about lithology, porosity, permeability, fluid saturation and other properties to help operators better characterize the complex nature of the reservoir. Mark A. Andersen Brent Duncan Ryan McLin Houston, Texas, USA Oilfield Review Summer 2013: 25, no. 2. Copyright 2013 Schlumberger. For help in preparation of this article, thanks to Angela Dippold Beeson, David Harrison, Mario Roberto Rojas and Leslie Zhang, Houston; Carlos Chaparro and Adriano Lobo, Ecopetrol, Bogotá, Colombia; Alyssa Charsky, Michael Herron and Josephine Mawutor Ndinyah, Cambridge, Massachusetts, USA; William W. Clopine, ConocoPhillips Company, Houston; Rudolf Hartmann, BÜCHI Labortechnik AG, Flawil, Switzerland; Thaer Gheneim Herrera, Bogotá, Colombia; Wendy Hinton, Himanshu Kumar and David R. Spain, BP, Houston; Upul Samarasingha, Salt Lake City, Utah, USA; Tony Smithson, Northport, Alabama, USA; and Elias Yabrudy, Coretest Systems, Morgan Hill, California, USA. Techlog, TerraTek and XL-Rock are marks of Schlumberger. PHI-220 Helium Porosimeter is a mark of Coretest Systems, Inc. LECO is a mark of the LECO Corporation. Cores provide essential data for the exploration, evaluation and production of oil and gas reservoirs. These rock samples allow geoscientists to examine firsthand the depositional sequences penetrated by a drill bit. They offer direct evidence of the presence, distribution and deliverability of hydrocarbons and can reveal variations in reservoir traits that might not be detected through downhole logging measurements alone. Through measurement and analysis of porosity, permeability and fluid saturation from core samples, operators are better able to characterize Whole Core Segment 1 ft Full Diameter Core Analysis pore systems in the rock and accurately model reservoir behavior to optimize production. Core analysis is vital for determining rock matrix properties and is an important resource for formation characterization. The process known as routine core analysis helps geoscientists evaluate porosity, permeability, fluid saturation, grain density, lithology and texture. Routine core analysis laboratories (RCALs) frequently provide a variety of additional services such as core gamma logging for correlating core depth with wellbore logging depth, core computed tomography (CT) scans for 1 ft Core Plug Analysis 2.5 to 3 in. 3 ft 1 ft 1 ft 1 ft 1 ft > Divided cores. At the wellsite, whole cores are typically cut into smaller segments for ease of shipping. At the laboratory, the whole core segments may be cut and subsampled. 16 Oilfield Review

19 characterizing rock heterogeneity and core photographs for documenting and describing the core. When operators need to understand complex reservoir behaviors, they turn to special core analysis for detailed measurements of specific properties. Special core analysis laboratories (SCALs) are typically equipped to measure capillary pressure, relative permeability, electrical properties, formation damage, nuclear magnetic resonance (NMR) relaxation time, recovery factor, wettability and other parameters used for calibrating logs. SCAL services are also used to characterize reservoirs for enhanced oil recovery (EOR) and for studying multiphase flow and rock-fluid interactions. Only a few samples are selected for these extensive tests, some of which require weeks to complete. For years, Schlumberger has maintained a number of core analysis laboratories to support research into wireline tool response, drilling fluid chemistry, formation damage, EOR or completion technology. However, these facilities did not provide core analysis on a commercial scale. Until recently, the company s commercial core analysis services were centered in Salt Lake City, Utah, USA, where the TerraTek rock mechanics and core analysis facility is known for its focus on geomechanics and unconventional reservoirs. The 2012 inauguration of Schlumberger Reservoir Laboratories has opened the way for integrating rock measurement technologies with fluids expertise to help customers better understand reservoir behavior. Schlumberger now offers rock and fluid analysis through 27 laboratories around the globe. Several companies offer similar analyses of conventional cores. This article focuses on routine analysis of conventional sandstone and carbonate cores carried out by specialists at the Schlumberger Reservoir Laboratory in Houston. Sample Sizes Cores come in a variety of lengths and diameters (previous page). The information extracted from a core depends in part on the size and quantity of the core, which control the types of analyses that may be performed. To meet customer needs, the core analysis laboratories must be flexible enough to process the various types of core sent from the wellsite, be they bottomhole cores or sidewall cores. Summer

20 Bottomhole cores, also referred to as whole cores, or conventional cores, are obtained during the drilling process using a special coring bit (below). The cores typically range in diameter from 4.45 to 13.3 cm [1.75 to 5.25 in.] and are generally drilled in 10-m [30-ft] increments, which correspond to the length of the core barrel or its liner. Whereas a conventional bit is designed to grind away the rock at the bit face, the doughnut-shaped coring bit creates a cylinder of rock that passes through the center of the bit and is retained in a protective core barrel. When the core barrel is full, the driller pulls the assembly out of the hole, and a wellsite coring specialist lays the barrel liner on the pipe rack. The liner, with core inside, is then scribed with depth markings and orientation lines. For ease of shipping, the metal liner is usually cut into 1-m [3-ft] segments and sealed at each end. To prevent shifting during transit, the wellsite corehandling team may inject epoxy or foam into the liner to stabilize the core. For sidewall cores (SWCs), the process is far less involved. SWCs are obtained by a wireline sampling device, which is typically run in the hole near the conclusion of an openhole wireline logging job after the operator consults the logs to identify zones that merit sampling. The SWC device can extract up to 90 samples from the side of the wellbore at selected depths. Once on the surface, sidewall cores are retrieved from the tool, sealed in individual bottles and shipped to the laboratory for analysis. Percussion-type sampling devices obtain SWCs measuring from about 2.86 to 4.45 cm [1.125 to 1.75 in.] in length by 1.75 to 2.54 cm [0.688 to 1 in.] in diameter. Percussion sampling devices are known as core guns because they use small explosive charges to propel individual core barrels, called bullets, into the formation. The core barrels are attached to the gun with strong cables that are used to pull the core bullet from the borehole wall as the gun is reeled uphole. By contrast, rotary cores are cut from the formation using a miniature, horizontally oriented coring bit. The XL-Rock large-volume rotary sidewall coring tool can drill cores 6.4 cm [2.5 in.] long by 3.8 cm [1.5 in.] OD from the side of the borehole. This device produces core samples that have more than three times the volume of percussion SWCs. A third type of rock sample is the core plug. The core plug is extracted from segments of whole core. These plugs are taken as a representative subsample of the whole core and are useful in analyzing intervals of relatively homogeneous core. Core plugs in conventional reservoirs are routinely taken at 0.3-m [1-ft] intervals along the length of the core and measure about 6.4 cm long by 2.54 or 3.8 cm in diameter. Variations in lithology may require smaller sampling intervals, but if the core is highly heterogeneous, as seen in vugular or fractured carbonates or thinly laminated sand-shale intervals, the operator may elect to analyze the whole core rather than plugs. Initial Processing The basic workflow for conventional core analysis moves from receiving to preliminary imaging, then to preparation and analysis. Each process involves several steps. Whole cores typically require more initial processing than sidewall cores. Although routine core analysis provides a standard set of measurements, not all cores go through the entire workflow described here. At the laboratory, cores are received and inventoried. Whole cores are run through a core gamma ray logger, which measures gamma rays that are naturally emitted from the cores. By comparing core gamma ray measurements to LWD or wireline gamma ray logs, geoscientists can correlate core depth to log depth and identify intervals from which core may have been lost or damaged. The core gamma ray logging device uses a conveyor to move the core either exposed or sealed within the liner past a gamma ray detector. The detector scans the core along its length from bottom to top, which replicates the logging sequence used in obtaining wireline logs. Next, the core is run through a computed tomography scanner to obtain a CT image. The CT device obtains a 3D image of the whole core, taking a series of closely spaced scans that can be sliced at any point or orientation to create a virtual slab of the core. The CT scanner permits a quick reconnaissance across the core. When zones of interest are identified, they may be scanned again for detailed examination (next page). CT scanning is especially useful for detection and evaluation of internal features such as bedding planes, vugs, nodules, fossils and frac- > Coring bit. This polycrystalline diamond compact (PDC) bit employs a fixed cutter design that leaves the center of the borehole untouched. The bit creates a cylindrical core of the formation that passes through the middle of the bit, to be retained within the bottomhole assembly. 1. For more on CT scans in oilfield applications: Kayser A, Knackstedt M and Ziauddin M: A Closer Look at Pore Geometry, Oilfield Review 18, no. 1 (Spring 2006): Passey QR, Dahlberg KE, Sullivan KB, Yin H, Brackett RA, Xiao YH and Guzmán-Garcia AG: Digital Core Imaging In Thinly Bedded Reservoirs, in Dahlberg KE (ed): Petrophysical Evaluation of Hydrocarbon Pore-Thickness in Thinly Bedded Clastic Reservoirs. Tulsa: The American Association of Petroleum Geologists, AAPG Archie Series, no. 1 (June 30, 2006): Perarnau A: Use of Core Photo Data in Petrophysical Analysis, Transactions of the SPWLA 52nd Annual Logging Symposium, Colorado Springs, Colorado, USA, May 14 18, 2011, paper Z. 18 Oilfield Review

21 > Whole core CT scans. Pore characteristics are brought into sharp focus in a virtual slice of core (top, foreground) as the sample passes through the CT scanner (top, background). Color coding on the scan helps distinguish regions of differing density or mineralogy. By contrast, grayscale images are used to highlight core damage. A core obtained through a friable formation at the Casabe field in Colombia was scanned prior to being removed from the core liner (bottom). Stacks of cross sections revealed areas where portions of the core were damaged. The white exterior ring is the core liner; a layer of caked drilling mud inside the liner surrounds the core. By avoiding fractured intervals (bottom left), the core analyst was able to select undamaged sections (bottom right) from which to extract plugs. (CT images courtesy of Carlos Chaparro and Adriano Lobo, Ecopetrol, Bogotá, Colombia.) tures. 1 Operators occasionally specify that sidewall cores be scanned as well. CT scans are noninvasive, require no further preparation of the core and can be performed rapidly on exposed cores or on cores retained inside the core barrel. After performing initial scanning, the core analyst frees the core from the barrel to prepare it for further testing. The analyst uses a band saw or radial saw, equipped with a diamond-impregnated blade, to cut the core lengthwise parallel to the core axis into slabs. In most cases, the core is cut off center rather than sliced down the middle. The thickness of the slab dictates the maximum size of any plugs subsequently sampled from the core. The flat face of the thinner slab is polished to remove saw marks in preparation for slab photography. In some cases, portions of the core are not slabbed. When a core exhibits substantial, largescale heterogeneity typical of vuggy carbonates or severely fractured or conglomeratic rock then sections of the core may be set aside without slabbing to permit analysis of the full diameter core. The core slabs are photographed using a 35-mm digital camera linked to a dedicated computer, which can digitize, display and transmit images to the client. Photographs can often resolve individual layers within thin beds measuring just tenths of an inch. Digital photography helps highlight important geologic and petrophysical characteristics. These high-resolution color images provide an important visual record of lithology, bedding characteristics, contacts, fractures, fossils, porosity, vugs and sedimentologic variations that may be studied in detail long after the core has been subjected to further testing. Subsequent manipulation and analysis of core images often yield valuable information not readily apparent from the original photographs. In some cases, they can be used to reconcile discrepancies between core and log analysis, detecting formation laminations that are too thin to be resolved by the logging tool. Upon client request, a 360 axial wrap of the core is imaged. This is accomplished using a digital camera and a table with rollers that rotate the full diameter core longitudinally as it is photographed. Photographs are taken in white and in ultraviolet (UV) light. Images shot in plain white light show the cores under natural lighting conditions. The UV light may highlight certain types of minerals but, more importantly, it can enhance the contrast between nonreservoir and oil-bearing zones. Oil-bearing reservoir rocks frequently exhibit strong ultraviolet fluorescence. Typically, an oil emits fluorescence, the brightness and color of which are affected by its composition. However, some oils do not fluoresce. Furthermore, if flushing has removed some of the oil as the core was brought to the surface, or if the core was not well preserved, the pay interval may not fluoresce uniformly. 2 It is difficult to assess fluorescence using the naked eye; however, digital color photography records numerical input, which some operators use for subsequent computer analysis. 3 Each photograph is made up of pixels, and each pixel may be assigned one of more than 16 million shades. Geoscientists filter or manipulate these colors to highlight important features. Statistical analysis of color data can help geologists differentiate between lithologies or establish porosity or permeability cutoffs. The computer can count how many pixels fall within a specified color range to determine net sand or net fluorescence in thinly laminated zones. Although core facilities typically accommodate a wide range of samples, core plugs are most frequently used for routine core analysis. Plugs provide Summer

22 Solvent Boiling Point Solubility Methylene chloride Hexane Chloroform/methanol azeotrope Acetone Methanol Tetrahydrofuran Cyclohexane 40.1 C [ F] 49.7 C to 68.7 C [121.5 F to F] 53.8 C [128.8 F] 56.5 C [133.7 F] 64.7 C [148.5 F] 65.0 C [149.0 F] 81.4 C [178.5 F] Oil and limited water Oil Oil, water and salt Oil, water and salt Water and salt Oil, water and salt Oil Ethylene chloride 83.5 C [182.3 F] Oil and limited water 100 C Toluene C [231.1 F] Oil Tetrachloroethylene Xylene Naphtha C [249.8 F] C to C [280.4 F to F] C [320.0 F] Oil Oil Oil > Common core-cleaning solvents, ordered by boiling point temperature. The choice of solvent typically depends on wettability interactions between the crude oil and the minerals contained within the rock. Complete extraction of some oils may require mixtures or series of solvents. The red line represents the boiling point of water. (Table adapted from API, reference 6.) a reliable characterization of the core when the pore system is relatively homogeneous. 4 The core analyst, sometimes working in concert with the operator s geologist, drills sample plugs from a full diameter core. Most laboratories use a mill or a drill press with a diamond bit to drill the core plugs. The analyst cuts the plug to a Extractor tor Siphon Distillation flask Condenser Core samples Heating mantle standard length then applies a precision finish using an end face grinder. The result is a right cylinder, typically 38 mm [1.5 in.] diameter by 64 mm [2.5 in.] long, with a flat face at each end. By creating plugs of standard shape and size, the analyst obtains samples with the same cross-sectional area and length; thus, each plug has essentially Distilled solvent Spill point Return liquid solvent Solvent vapor Solvent vapor Core samples > Soxhlet distillation extractor. Solvent in the distillation flask (left) is gently heated until it vaporizes. The solvent vapors rise from the flask and cool when they reach the condenser. The cooled liquid solvent drips onto the core to permeate the sample. The solvent condensate carries away the hydrocarbons and brine from the sample. When distilled solvent in the extractor reaches its spill point, the used solvent siphons back into the flask to be redistilled (right). This process is repeated continuously and can be sustained as long as needed. The hydrocarbons from the core are retained and concentrated in the distillation, or boiling, flask. Some Soxhlet devices can accommodate multiple core plugs. the same bulk volume. A standard size plug also reduces the potential for measurement errors stemming from irregularly shaped samples. Core Cleaning and Fluid Extraction In addition to rock matrix, core samples contain formation fluids. If the core is taken from a productive zone, these formation fluids will typically contain a mixture of hydrocarbons and saltwater, or brine. At the laboratory, these fluids, which would otherwise interfere with routine core analysis measurements of porosity and permeability, must be completely removed from the pore spaces of the rock. Core cleaning and fluid extraction are combined in a delicate process, which must be thorough enough to remove heavy fractions of crude oil yet gentle enough to prevent damage to the mineral constituents of the rock. This process must avoid creation of additional pore space resulting from dehydration of clays and hydrous minerals, such as gypsum, or from erosion caused by high flow rates as solvent passes through the sample. 5 Several techniques have been developed for removing residual formation fluids; the most widely used involve distillation extraction or continuous solvent extraction. Unslabbed cores, plugs and SWCs are carefully cleaned using a specialized closed-loop system that employs either a Soxhlet cleaning treatment or a Dean-Stark fluid extraction process. In the Soxhlet process, the sample is allowed to soak in the solvent; in the Dean-Stark method, solvent vapors and liquids flow through the sample. Both techniques rely on heat to drive the water from the core sample and on solvent to extract any hydrocarbons (above left). Soxhlet extraction uses a distillation process to clean the core. The Soxhlet apparatus consists of a heating mantle with a thermostatic controller, boiling flask, extractor and condenser (left). The solvent is gently boiled, and the distilled solvent collects in the extractor, in which one or more core samples soak. The heated solvent is continually distilled, condensed and refluxed. The cleanliness of the sample is determined from the color of the solvent that siphons periodically from the extractor; the process is repeated until the extract remains clear after an extended soak cycle. This method uses one or more solvents to dissolve and extract oil and brines from the core sample. After repeated cycles, the extract should become clear as no more oil is carried out of the rock. However, the fact that one solvent is clear may not necessarily mean that the oil has been completely removed from the sample. 6 Sequentially stronger solvents may be required to clean the sample. 20 Oilfield Review

23 Another distillation method, Dean-Stark extraction, is an industry standard method for determining fluid saturation (right). The core analyst first weighs the sample on an analytical balance before placing it into a thimble in the Dean-Stark apparatus above its heating flask. The flask is heated to raise the solvent temperature to its boiling point, and the sample becomes enveloped in solvent vapors as they rise from the flask. Water in the sample is vaporized by the solvent and rises with the solvent vapors to the condenser. There, the vaporized water and solvent cool and condense before falling into a calibrated receiving tube. The water, denser than solvent, settles to the bottom of the receiving tube. When the solvent condensate overflows the tube, it drips down onto the sample. The condensate mixes with oil in the rock, and this mixture drips back into the flask below, where the solvent is again heated and the vaporization-condensation cycle continues. Once the volume of water in the receiving tube reaches a constant value, with no more water produced from the sample, the Dean-Stark distillation is complete. Because the sample may not be completely cleaned of oil and salts, a Soxhlet cleaning often follows the Dean-Stark method before the sample is placed in the oven to dry. The core analyst weighs the sample after Dean-Stark extraction and Soxhlet cleaning and periodically during drying (right). 7 The difference between sample weights before and after cleaning is attributed to the weight of the extracted fluids. The calibrated receiving tube measures the extracted water volume, which is converted to weight by using the density of distilled water. The remaining weight difference is a result of any oil that has been extracted. Typically, an oil density value is assumed for determining the oil volume based on weight. 4. Almon WR: Overview of Routine Core Analysis, in Morton-Thompson D and Woods AM (eds): Development Geology Reference Manual, Part 5 Laboratory Methods. Tulsa: The American Association of Petroleum Geologists, AAPG Methods in Exploration Series, no. 10 (October 1, 1993): Macini P and Mesini E: Petrophysics and Reservoir Characteristics, in Macini P and Mesini E (eds): Petroleum Engineering Upstream, Encyclopaedia of Life Support Systems (EOLSS) 2008, developed under the auspices of the United Nations Educational, Scientific and Cultural Organization, EOLSS Publishers, Oxford, England, (accessed July 16, 2013). 6. American Petroleum Institute (API): Recommended Practices for Core Analysis. Washington, DC: API Exploration and Production Department, Recommended Practice 40, Second Edition, February The core is dried in an oven until its weight is constant over a specified time interval, which implies that all the water has evaporated. Normally, a convection or vacuum oven is used to dry the samples. However, if the cores contain gypsum or hydratable clays, then they are dried in an oven equipped with a water vapor injection system to regulate relative humidity. Water trap Extraction thimble Desiccant Condenser Adapter Thimble basket support Core Distillation flask Heating mantle > Dean-Stark apparatus. A core analyst inserts a core plug into the sample chamber (photograph). The typical setup (left) consists of an electric heating element, or heating mantle, a boiling flask with extractor chamber, a sample thimble or support screen, a water trap or calibrated receiving tube, and a condenser. The Dean-Stark method results in a quantitative measure of water volume extracted from a core, and therefore each sample is cleaned individually in a separate apparatus. > Weighing core plugs. Precision weighing of every sample at each stage in the cleaning and extraction process is required because small differences in weight affect grain density calculations and subsequent determination of other important reservoir parameters such as fluid saturation. Summer

24 Later, analysts measure the pore volume of the core sample; the difference between the pore volume and the sum of the water and oil volumes is the gas volume. These fluid volumes are converted to saturations by dividing by the pore volume. Laboratories sometimes use other cleaning and extraction techniques to accommodate different types of rock. Analysts developed a technique for cores containing very fine clays with delicate mineral structures. The cores are cleaned with a series of mutually miscible solvents, injected in sequence such that each solvent displaces a specific pore fluid and each solvent in the sequence is displaced by the next. During flow-through cleaning, solvent may be either injected continuously or periodically halted to allow it to permeate the core. For quick processing of cores, laboratory workers may use a rapid extractor that injects heated solvent into the sample. Multiple cores can be analyzed in a single operation; each sample is placed into a separate pressure vessel, then the rapid extractor heats and pumps solvent into the samples at high pressure. The displaced fluids are collected separately for each sample. He Helium tank Valve Pressure transducer Valve Pressure transducer Pressure transducer V 1 Valve V 2 Reference cell Valve Core plug Sample cell > Boyle s law porosimeter. A porosimeter (top) measures the pressure difference between a reference chamber and a sample chamber to determine pore and grain volumes. The basic system diagram (bottom) shows the inner workings of a porosimeter, with its reference chamber of fixed, known internal volume and a sample chamber. The device also has valves to admit a gas under pressure to each chamber, transducers to measure pressure and requisite plumbing to permit communication between a pressurized gas container and the two chambers. Calibration, operation of valves and calculation of results are completely automated. (Photograph courtesy of Coretest Systems, Inc.) Vent Key Measurements Porosity and permeability are essential measurements for understanding how a reservoir will produce. Porosity, a measure of reservoir storage capacity, can be determined by measuring grain volume, pore volume and bulk volume (below). Only two of the three volumes are required to determine porosity, and pore volume is measured under simulated overburden stress conditions. φ = V p /V b, φ = (V b V g )/V b, φ = V p /(V p +V g ), where φ = porosity V p = pore volume V b = bulk volume = grain volume V g > Porosity relationships. Porosity is defined as the ratio of pore volume to bulk volume. Because bulk volume is the sum of grain volume and pore volume, measuring any two of these volumes allows for calculation of the third, with subsequent calculation of porosity. Over the years, scientists have developed various methods for measuring these core volumes; most are based on physical measurements of weight, length, volume or pressure. Some of these measurements are obtained directly from the sample; others rely on the displacement of fluids. Direct measurements may be taken to determine bulk volume. The core analyst may simply use a digital caliper or micrometer to measure the core plug length and diameter. A minimum of five measurements is recommended. The crosssectional area of the core plug is calculated from the average diameter, then multiplied by the average length to yield bulk volume. 8 In some laboratories, digitally calipered core measurement data are automatically logged into a computer, which calculates the geometric bulk volume, shape factor, effective flow area and caliper bulk factor. Other techniques are based on Archimedes principle of fluid displacement: A solid submerged completely in fluid displaces an amount of fluid equal to its volume. Displacement can be measured volumetrically or gravimetrically. The volumetric approach for finding bulk volume uses a small amount of mercury in a porosimeter. 9 First, the empty sample chamber of the porosimeter is filled with mercury to determine its volume. The mercury is then drained from the chamber and the core plug is inserted. The chamber is again filled with mercury. The volume of mercury that filled the empty chamber minus the volume needed to fill the chamber while it held the sample equals the sample s bulk volume. The gravimetric approach uses a beaker of mercury placed on a laboratory balance. After the beaker and mercury are weighed, a cleaned, dried core plug of known weight is submerged in the mercury. The weight gain from the sample submersion, divided by the density of mercury, gives the bulk volume. Today, many laboratories prefer not to use mercury and instead apply Archimedes principle using other fluids such as brine, refined oil or toluene. 10 After determining bulk volume, the analyst measures the grain and pore volume of the samples. The most rapid and widely used device for measuring grain volume and pore volume and hence, determining porosity is the automated porosimeter (above). This device employs Boyle s law to calculate porosity based on the pressure decrease measured when a known amount of fluid is vented into an expansion chamber containing a core. In this case, the fluid is helium gas. 11 To measure pore volume, the analyst places a cleaned and dried core sample in a core holder fitted with an elastomer sleeve. When air pressure is applied to the outside of the sleeve, it conforms to the shape of the core. The core holder is 22 Oilfield Review

25 P i V i = P f (V i + V l + V p ), where P i P f V i V l V p = initial pressure = final pressure in the system = initial volume in reference chamber = volume of connecting lines = pore volume of sample > Pore volume calculation. Following Boyle s law, the pore volume can be calculated using the difference between initial and final pressures in the porosimeter. used in place of the porosimeter sample chamber. The reference chamber is initially isolated from the core in the holder and filled with helium to a specified pressure. The valve to the sample chamber is then opened to permit the helium pressure to equilibrate between the reference chamber and the pore volume of the confined sample. Porosity is calculated using the bulk and pore volume measurements (above). The process for measuring grain volume is similar, except that the sample is not confined, but is placed, with no sleeve, directly into the sample chamber. Permeability, the measure of a rock s capability to transmit fluids, is another key reservoir characteristic. In the laboratory, analysts determine permeability by flowing a fluid of known viscosity at a set rate through a core of known length and diameter then measuring the resulting pressure drop across the core. For routine core analysis, the fluid may be air, but is more often nitrogen or helium, depending on the type 8. API, reference Mercury is used because it is a nearly perfect nonwetting fluid and does not enter the rock pores under normal pressure. 10. API, reference Helium is used because it is an inert gas that does not readily adsorb onto mineral surfaces of the core and tends to exhibit ideal gas behavior at moderate pressures and temperatures. Furthermore, the small size of the helium atom enables it to rapidly enter the micropore system of the core, penetrating very small pores approaching 0.2 nm. For more on porosity analysis: Cone MP and Kersey DG: Porosity, in Morton-Thompson D and Woods AM (eds): Development Geology Reference Manual, Part 5 Laboratory Methods. Tulsa: The American Association of Petroleum Geologists, AAPG Methods in Exploration Series, no. 10 (October 1, 1993): API, reference Klinkenberg LJ: The Permeability of Porous Media to Liquids and Gases, Drilling and Production Practice, (1941): Rushing JA, Newsham KE, Lasswell PM, Cox JC and Blasingame TA: Klinkenberg-Corrected Permeability Measurements in Tight Gas Sands: Steady-State Versus Unsteady-State Techniques, paper SPE 89867, presented at the SPE Annual Technical Conference and Exhibition, Houston, September 26 29, of permeameter used. The analyst loads a clean, dry core into a specially designed core holder, where it is enclosed in a gas-tight elastomer sleeve (below). The permeameter forces pressurized gas through the inlet port and into the core. The pressure differential and flow rate are metered at the outlet port. This configuration is used in a steady-state gas permeameter. In an alternative method for determining permeability, analysts charge a chamber to a high gas pressure and then open a valve, allowing the gas to pass through the core plug as the pressure declines. If the laboratory uses this unsteady-state, or pressure-transient permeameter, analysts can use the time rate of change of pressure and effluent flow rate to solve for the plug permeability. Analysts apply corrections to compensate for the differences between laboratory and downhole conditions. 12 They account for stress differences by applying confining stress to one or more representative plug samples; some permeameters are capable of imposing confining pressures to 70 MPa [10,000 psi]. Often, analysts use several confining stresses to determine the stress effect on permeability then apply a correction factor for the reservoir confining stress to the other routine permeability measurements. Gas flow in pores differs from liquid flow because the flow boundary condition at the pore walls is different for gases and liquids. Liquids experience greater flow resistance, or drag, at the pore wall than gas does. This gas slip effect can be corrected by increasing, in steps, the mean gas pressure in the plug, which increases the drag at the pore wall. The Klinkenberg correction is an extrapolation of these measurements to infinite gas pressure, at which point gas is assumed to behave like a liquid. 13 Analysts apply an additional correction for high gas flow rates through tortuous flow paths. The Forchheimer correction accounts for effects produced when gas accelerates as it passes through small pore throats and decelerates upon entering the pores. In many automated unsteadystate permeameters, both the Klinkenberg and Forchheimer corrections are automatically solved during analysis. To flowmeter Low air pressure (flow) Outlet port Metal cap Rubber disk Elastomer sleeve Core High air pressure port (sealing) Inlet port > Hassler chamber for measuring permeability to gas. A core sample is placed in an elastomer sleeve. The caps at either end of the device are fitted with axial ports to admit gas. The permeameter (photograph) forces gas through the inlet port at the bottom, and the gas passes through the core before exiting to a flowmeter. Permeability is calculated using the Darcy equation. (Photograph courtesy of Coretest Systems, Inc.) Summer

26 DRFT-IR, wt % DRFT-IR, wt % Clay 0 50 DRIFTS, wt % Quartz 0 50 DRIFTS, wt % > Confirmation of DRIFTS measurements. Results from the DRIFTS measurement in the vertical evaluation well compare favorably with companion DRFT-IR mineralogy for clay, carbonate and quartz content. The kerogen content from DRIFTS was compared with a LECO TOC measurement. DRIFTS measures wt % of the kerogen, which includes other elements than carbon; therefore, the industry uses a factor of 1.2 to correlate between these TOC and kerogen measurements. The above plots show good agreement between DRIFTS and the other measurements. Upon completion of its analyses, the laboratory transmits a report, along with digital copies of photographs and scanning data, to the client. Depending on client instructions, the core may be kept in storage, returned to the client, or archived at a core library for future reference. Petrographic Measurements Routine core analysis helps operators evaluate reservoir lithology, bedding features, residual fluids, porosity and permeability, but these provide only a portion of the information that can be extracted from a core. Complementary petrographic tests furnish additional analytical results and visual records of the core. Scanning electron microscopy allows inspection of core surface topographies with magnifications capable of resolving features at the nanometer scale. A scanning electron microscope scans the surface of a sample with a finely focused electron beam to produce an image based on beam-specimen interactions. DRFT-IR, wt % Total organic carbon 1.2, wt % Carbonate 0 50 DRIFTS, wt % Kerogen DRIFTS, wt % Electron detectors receive data on specimen surface topography while backscatter detectors resolve compositional variations across the sample surface. Analysts use a color cathodoluminescence detector to examine variations in mineral composition, including phase and trace element distribution. This detector permits visualization of chemical overprinting and overgrowths, growth zonation and internal healed fractures. These images provide insight into processes involving the growth of mineral crystals as well as their replacement, deformation and provenance. Petrologic applications include investigations of cementation and diagenesis of sedimentary rocks, provenance of clastic rock materials and examination of the internal structures within fossils. Diffuse reflectance infrared Fourier transform spectroscopy (DRIFTS) provides a fit-forpurpose technique for measuring mineralogy and organic content data that are proving instrumental in supporting completion designs in mudstone reservoirs. Scientists can analyze core, cuttings or outcrop samples. DRIFTS analysis is fast; a 50-second scan determines mineralogy and organic content. A sample preparation procedure that is proprietary to Schlumberger enables it to be used as a quantitative measure of rock constituents. The process requires a small sample of only 5 g [0.18 ozm] for analysis. The device scans the sample with infrared light at multiple wavelengths. The light scatters as it passes through the rock. The reflected infrared energy is analyzed based on regression analysis of the frequency and amplitude of the spectra to determine the lithology, mineralogy and organic content of each sample. To obtain an initial calibration of mineralogy and kerogen measurements, analysts run dual range Fourier transform infrared (DRFT-IR) spectroscopy and X-ray fluorescence (XRF) on representative samples to verify mineralogy, and they run a LECO total organic carbon (TOC) scan to verify organic matter content and kerogen amount. After the full study of DRFT-IR, XRF and TOC is complete, DRIFTS data can be acquired on a rapid basis to give operators timely information for completion decisions. An operator in the western US performed DRIFTS analyses on Mancos Shale wells to evaluate their utility for identification of mineralogy and kerogen content in unconventional plays. The first study focused on a vertical well that was cored and logged. This well provided an extensive database for evaluating the Mancos Shale. The laboratory used crushed samples from cores to determine mineralogy and organic content. In addition to DRIFTS data, the evaluation included mineralogy from DRFT-IR, XRF and TOC measurements. These traditional analytical methods utilized material from the same crushed samples that were subjected to DRIFTS analysis. Results from these evaluations showed good agreement between the DRIFTS results and the other three more accurate analytical methods (above left). The results gave the operator confidence to apply the DRIFTS method to other wells drilled in the Mancos formation. The second well in this study was a horizontal production well. Near the heel of the well, high gamma ray measurements and low mud log gas readings suggested that the well might be out of the primary target zone. The gamma ray response decreased as the well moved upward in the stratigraphic section, indicating better reservoir quality in the targeted portion of the well; this was consistent with mud log gas readings toward the toe of the well. 24 Oilfield Review

27 Maximum Pressure, 1,000 psi Stage DRIFTS Composition, % Total Clay Total Carbonate Total Quartz Average, Rate, bbl/min Depth Gamma Ray Total Gas True Vertical Depth ft 0 gapi TG units 85 5,800 ft 5,720 V,250 V,500 V,750 W,000 W,250 W,500 W,750 X,000 X,250 X,500 X,750 Y,000 Y,250 Y,500 Y,750 Z,000 Z,250 Z,500 Total Kerogen Sand Pumped, 1,000 lbm Tracer Concentration, parts per billion (ppb) > Response in a bentonite zone. The gamma ray log (Track 3 from top) reads high from V,100 to V,400 ft measured depth, interpreted as a bentonite zone (red box). The well trajectory (Track 1) was changed to drill upward through this zone. The high gamma ray signature, combined with low mud gas readings (Track 2), is a typical indicator of poor reservoir quality. All zones of this horizontal well were stimulated. In the bentonite zone, the injection rate required to fracture was higher at the same pressure (Track 4). A tracer survey (Track 5) shows the presence of a chemical tracer throughout the 15-stage interval, indicating that the proppant was successfully placed at each stage. The DRIFTS analysis (Track 6) indicates that kerogen is present throughout this zone, which gave petrophysicists confidence that the bentonite zone (yellow box) was a thin zone in a productive Mancos formation, despite high gamma ray and low mud gas readings. In the toe of the wellbore, the DRIFTS data recorded values above the operator s minimum cutoff for kerogen content along with acceptable values of clay, carbonate and quartz, in agreement with gamma ray and mud gas data (above). From the heel of the well, other data showed unacceptably high clay content, supporting the earlier gamma ray interpretation that the well had drilled out of zone. However, the DRIFTS data showed anomalously high kaolinite values at the heel of the well, typical of thin bentonite layers known to exist in the Mancos Shale. The heel also exhibited higher kerogen content (5.6% compared with a range from 3.1% to 4.3% in the toe of the well). These observations, not available through MWD logs obtained in this well, gave the operator confidence that the bentonite zone was a thin anomaly, not representative of the Mancos formation surrounding it. Postfracturing data indicate that the well was successfully stimulated with adequate proppant placement, although higher injection rates were needed to successfully break down the clay-rich bentonite zone. The operator is incorporating these data in completion optimization studies for future wells. Operators combine other data with these important ground truth measurements in their formation evaluation programs. Core analysis, in its many forms, will continue to inform operator decisions to drill ahead, abandon or complete their wells. In some cases, routine analysis and petrology provide an operator with all the core information needed. More commonly, additional analyses are obtained from this valuable asset. These include evaluations of multiphase saturation and flow properties, such as capillary pressure and relative permeability; log-tuning measurements, such as electrical properties for determining porosity and saturation from logs; flow assurance studies; geomechanical measurements or enhanced oil recovery evaluations. These measurements add tremendous value to reservoir evaluation, and they all begin with routine core analysis. MV Summer

28 Multistage Stimulation in Liquid-Rich Unconventional Formations Production of liquids from shale formations, pioneered in North America, has grown exponentially in the past decade. The economics of these plays, however, remain sensitive to prices and demand, thus operators and service companies must continually develop more-efficient methods of recovering these once-overlooked hydrocarbons. Isaac Aviles Jason Baihly Sugar Land, Texas, USA Guang Hua Liu CNPC-Dagang Oilfield Company Tianjin, People s Republic of China Oilfield Review Summer 2013: 25, no. 2. Copyright 2013 Schlumberger. For help in preparation of this article, thanks to Amy Simpson, Houston. Copperhead, DiamondBack, Falcon, KickStart, nzone, PowerDrive Archer and Spear are marks of Schlumberger. 1. For more on kerogen and oil shales: Allix P, Burnham A, Fowler T, Herron M, Kleinberg R and Symington B: Coaxing Oil from Shale, Oilfield Review 22, no. 4 (Winter 2010/2011): Baihly J, Altman R and Aviles I: Has the Economic Stage Count Been Reached in the Bakken Shale?, paper SPE , presented at the SPE Hydrocarbon, Economics and Evaluation Symposium, Calgary, September 24 25, Jabbari H and Zeng Z: Hydraulic Fracturing Design for Horizontal Wells in the Bakken Formation, paper ARMA , presented at the 46th US Rock Mechanics/ Geomechanics Symposium, Chicago, June 24 27, Baihly et al, reference Martin R, Baihly J, Malpani R, Lindsay G and Atwood WK: Understanding Production from the Eagle Ford Austin Chalk System, paper SPE , presented at the SPE Annual Technical Conference and Exhibition, Denver, October 30 November 2, Martin et al, reference For more on PowerDrive Archer technology: Felczak E, Torre A, Godwin ND, Mantle K, Naganathan S, Hawkins R, Li K, Jones S and Slayden F: The Best of Both Worlds A Hybrid Rotary Steerable System, Oilfield Review 23, no. 4 (Winter 2011/2012): For more on the Spear bit: Centala P, Challa V, Durairajan B, Meehan R, Paez L, Partin U, Segal S, Wu S, Garrett I, Teggart B and Tetley N: Bit Design Top to Bottom, Oilfield Review 23, no. 2 (Summer 2011): Baihly et al, reference 2. During the past decade, oil companies have performed thousands of hydraulic stimulations on intervals along horizontal wellbores drilled through ultralow-permeability formations. Operators are using these techniques to exploit organic-rich shales, which were traditionally viewed only as source rock for conventional reservoirs. These extremely tight sedimentary formations differ significantly from oil shales, which are sedimentary rocks containing kerogen partially degraded organic material that has not yet matured enough to generate hydrocarbons. 1 In contrast, as a result of the pressure and heat of the burial process, the kerogen in gas- and liquidrich shales has matured sufficiently to generate significant amounts of gas and oil, which remain trapped within the shale. CANADA USA Montana Billings Numerous liquid-rich shale formations exist in North America. Among these are the Bakken and the Eagle Ford formations. Unlike in other unconventional plays around the world, operators and service companies have years of experience working in these two extensive plays. The formations are familiar to petrophysicists and engineers and have been the proving grounds for much of the technology now used to exploit unconventional liquid-rich reservoirs. Covering an area of 780,000 km 2 [300,000 mi 2 ], the Bakken formation lies within the Williston basin of North Dakota, South Dakota and Montana in the US and in parts of Manitoba and Saskatchewan in Canada (below). 2 Operators first produced oil and gas from this formation in the early 1960s through conventional vertical wells. In the 1980s, production increased when Wyoming Saskatchewan Regina Bakken Formation North Dakota Bismark Williston Basin South Dakota Manitoba > The Bakken. The Bakken formation (pink) covers an area of more than 780,000 km 2 across the states of Montana and North Dakota in the US and parts of the Canadian provinces of Manitoba and Saskatchewan. 26 Oilfield Review

29 operators began drilling horizontal wells. 3 When operators combined the complementary technologies of horizontal drilling and hydraulic stimulation to maximize the amount of formation exposed to the wellbore, North Dakota production from Bakken fields rose dramatically, from 16,000 m 3 [100,000 bbl] per day in 2005 to 96,000 m 3 [600,000 bbl] per day in These increased production rates in North Dakota led geoscientists to consider using the same techniques to produce oil from source rock in other existing plays, including the Eagle Ford Shale, in Texas, USA, which is the source rock for the massive hydrocarbon accumulation that has produced from the Austin Chalk for 80 years. That trend overlies the Eagle Ford Shale across large swaths of south Texas (right). 5 The Eagle Ford play, which stretches from central Texas southwest into Mexico, is 160 km [100 mi] long and averages 100 km [60 mi] wide. 6 In an effort to help operators optimally exploit unconventional plays, service companies have refined certain critical technologies. Today, operators are able to drill long horizontal wells and place them accurately within formation sweet spots. Production and completion engineers have also sought to improve methods for stimulating the numerous potentially productive intervals pierced by these wells (see Stimulation Design for Unconventional Resources, page 34). Refinements to directional drilling assemblies such as the PowerDrive Archer rotary steerable system have led to more efficient drilling through higher build rates and improved rates of penetration. In addition, engineers have designed bits specifically for use in shale formations. The Spear steel bit from Smith Bits, a Schlumberger company, is designed to meet the demands unique to rotary steerable systems drilling in shale formations. 7 In ultralow-permeability formations, operators nearly always use multistage stimulation (MSS) techniques to access commercial volumes of oil, condensate and dry gas. These methods enable engineers to stimulate multiple intervals along horizontal sections. Typically, completion engineers isolate individual intervals and, either through perforating or by opening sliding sleeves, expose the zone to be treated. The well is then hydraulically stimulated. Engineers repeat this sequence, moving upward along the wellbore until all targeted zones have been stimulated. This article examines various MSS methods. Case histories from the US and China illustrate their use and advantages. MEXICO Oil window Wet gas condensate window Dry gas window Texas Eagle Ford Shale Formation > The Eagle Ford. The Eagle Ford Shale formation, which is the source rock for the Austin Chalk play, covers a large swath across southern Texas and runs parallel to and north of the Gulf of Mexico coastline. The burial process of the Eagle Ford formation has resulted in a trend of oil (green), wet gas and condensate (yellow), and dry gas (blue) from the northwest to southeast. Balls, Seats and Valves As the industry improved its ability to drill horizontally, wellbore lengths increased. So too did the number of intervals that had to be isolated and treated. In 2007, the average treatment number, or stage count, in Bakken wells was three. By the end of 2011, that number was nearly 30, and some wells had more than 40 stages in a single lateral. 8 While the economies of scale seemed to dictate treating as many intervals as possible per wellbore, operators sought to improve well economics further by reducing the time required to stimulate all the stages in a given well. Exploiting a liquid-rich shale play is drilling intensive, and despite the advantages of hydraulically treating longer wells, the drainage area of each wellbore in these tight formations is limited. With more than 200 rigs working in the Bakken at the end of 2011, there was great economic incentive to move the rigs off one well and on to the next as quickly as possible. USA Texas Gulf of Mexico 0 km mi 100 Traditionally, stimulating multiple zones in a conventional vertical well involved perforating the lowest zone, retrieving the perforating guns and pumping the treatment. The operator flowed the well back to drain extra proppant and carrying fluids and to force closure of the propped fracture. The completion engineer then set a bridge plug to isolate the interval from those above, pulled out of the hole to pick up perforating guns and repeated the process. Once all zones were treated, drillers milled out or retrieved the plugs and brought the well on line. Often, the well had to be completed with multiple strings of tubing or isolation valves to prevent crossflow between zones having different pressures. While this was a time-consuming process, it was not economically prohibitive in a vertical well with only two or three stages. However, when dozens of intervals in each wellbore needed treatment, operators sought Summer

30 Heel > Plugging and perforating procedure. In a typical cemented and cased well plug and perf scenario, the deepest interval at the toe of the well is perforated and treated first. A plug is then set above the perforation cluster. The next stage is treated, a plug is set, perforations are added and the process is repeated until all intervals are stimulated. The driller mills the plugs using coiled tubing or a conventional drillstring. The operator then commingles production for all intervals. to reduce the time required between reaching total depth and initial production. In response, service companies developed more-efficient treatment methods that relied on external packers, balls and seats, or plugs, to isolate and treat intervals. They also developed valves that, in some circumstances, could be substituted for perforations. Today, most horizontal wells are completed so that each interval can be isolated and perforated in one intervention using pumpdown wireline or coiled tubing conveyance and then treated. A final intervention may be required to mill out isolation plugs. Because the intervals are in one zone and equally pressured, the well is ready to produce. Closed Position Heel Open Position Valve seat Frac plugs Perforations Toe Typically, service company completion specialists use plugs or ball-and-seat systems to isolate each stage. When the company opts for a plug, it is placed on wireline and pumped down the hole, or less commonly, it is run and set on coiled tubing. The assembly includes perforating guns. Once the plug is set above the topmost perforation cluster of the previous stage, the completion team pulls the guns into position. Each cluster of the next stage is then perforated, and the tools, along with the spent guns, are retrieved. Next, the team stimulates the open interval, and this plug and perf procedure is repeated (above). When all intervals have been treated, the driller mills out the plugs, and production from all intervals is commingled. Frac sleeve Flow port Ball Frac sleeve > Ball and seat. A valve device is run into the hole in the closed position (top). When the ball (bottom, red) lands in a valve seat in a frac sleeve (green), pressure applied at the surface causes the sleeve to slide downward and open a flow port, which exposes the interval to be treated. The ball seals against the valve seat to isolate the previously treated stage below it. This process is repeated for each stimulation stage. Toe In other completion designs, a valve containing a ball seat and sliding sleeve is run into the hole as part of the completion. External packers isolate each interval. The ball seat is designed to capture a ball of a specific size that is pumped into the well. The diameters of the seats become successively larger from the bottom to the top of the completion. When the ball lands in the seat, continued pumping causes pressure to build against the ball and seat (below left). At a specified pressure, the ball-and-seat assembly moves downward, which opens a sleeve in the valve to expose the formation between the external packers. The interval is then treated. The next larger size ball is then run, isolating the treated zone. Completion specialists repeat this ball drop stimulation treatment sequence for all intervals beginning at the toe and moving toward the heel of the well. The method offers an advantage over the use of plugs because, as long as the ball seats do not represent a significant flow restriction, the balls may be flowed back to the surface, obviating the need for and risk of milling. Additionally, the operation is continuous, thus less time consuming. For cemented completions, engineers may perform similar operations using specially designed valves run as part of the completion string. When the ball is pumped downhole, it lands and creates a seal in the seat of the deepest exposed valve, which results in a closed system. Pressuring the well causes the sliding sleeve to open, allowing the interval to be treated directly through the cement. As a result, the operator does not need to perforate the casing and cement first. Despite the success of these systems, operators still seek hedges against narrow profit margins and unpredictable commodity prices that govern the economics of unconventional plays. In an effort to cushion profit margins, service companies are working with operators to refine MSS practices and tools and to shave costs and risks from well completion operations while simultaneously increasing production rates and ultimate recovery from these wells. Making Ideas Better In the mid-1960s, water depth of more than about 60 m [200 ft] was considered by the E&P industry to be a very deep working environment. But 9. Raulins GM: Well Servicing by Pump Down Techniques, paper OTC 1016, presented at the First Annual Offshore Technology Conference, Houston, May 18 21, Stegent N and Howell M: Continuous Multistage Fracture-Stimulation Completion Process in a Cemented Wellbore, paper SPE , presented at the SPE Eastern Regional Meeting, Charleston, West Virginia, USA, September 23 25, Oilfield Review 65263schD6R1.indd 28 8/19/13 6:18 PM

31 operators were already contemplating the implications of servicing subsea wells completed with wellheads on the seafloor in water as deep as 3,650 m [12,000 ft]. To address the challenges of deep water, engineers developed several technologies, including pumpdown for interventions traditionally performed using slickline. 9 Pumpdown systems convey tools downhole using fluid pressure. When fluid is pumped against mandrels equipped with swab cups, tools move up or down the tubing. Because this system requires the fluid to circulate, designers created a crossover port that allowed circulation between the tubing and the annulus. Today, completion engineers apply this method to push plugs and perforating guns attached to electric line to depth in horizontal wells. Service technicians set the plug above the shallowest perforation cluster of the previous fracture stage, detach the perforation guns from the plug assembly and move up the hole to create the next perforation cluster. After the guns have been fired, they are retrieved to the surface, and the interval stage is stimulated. The process is repeated for each stage. Once stimulation operations are complete, the driller must mill out each plug before putting the well on production. In this form of MSS, the last step milling is often the most difficult and time-consuming portion of the operation in high-angle wells because weight on bit is limited. Engineers have developed plugs of varying design and material that are able to withstand stimulation pressures while at the same time are more easily ground into cuttings than are traditional cast-iron bridge plugs; these cuttings are small enough to be circulated out of the hole. The aluminum Copperhead drillable and flowthrough fracture plug and the DiamondBack composite fracture plug are examples of these new plugs (above right). The former is rated to MPa [15,000 psi] and 205 C [400 F] and is designed to withstand multiple pressure and temperature cycles. The latter may be used when downhole conditions are less extreme and is rated for pressures up to 68.9 MPa [10,000 psi] and temperatures up to 177 C [350 F]. Both plugs are significantly easier to mill than are standard cast-iron plugs. Researchers have also developed a mill specifically for drilling out the Copperhead plug. The new mill reduces milling time and creates smaller cuttings. Because the DiamondBack plug is constructed of a composite material that is considerably softer than metal plugs, it is easily and quickly milled using standard mills. Aluminum slip pads with cast-iron facing Sealing aluminum backup ring Element backup Aluminum slip pads with cast-iron facing Copperhead Plug > Bridge plugs. The Copperhead plug body (left) includes slip pads constructed of aluminum with cast-iron facing, which helps prevent cracks in the slips when deployed in hard casing. The Copperhead plug includes a shear ring embedded in the slips (not shown) to help ensure that presetting does not occur and an element backup that enhances seal effectiveness while the bridge plug is exposed to multiple pressure changes. Because the plug body and slips are composed mainly of aluminum rather than cast iron, when the plug is milled, its cuttings are more easily flowed from the well. The DiamondBack plug (right) consists of composite material. Like the Copperhead plug, the DiamondBack plug includes an internal shear ring to prevent presetting. It also features rigid slips and a pumpdown ring to minimize fluid use. Because the plug is composed of a composite material, it can be quickly milled with a standard mill. In addition, both plugs are designed to prevent premature setting, which can be a problem with plugs that are landed and set on slips intended to wedge against the casing wall. If plugs of this design are conveyed downhole at excessive speeds, the slips may overtake the lower mandrel on the plug, causing them to expand against the casing wall and the tool to set. To help prevent this problem, both plugs use shear rings to hold the slips in place until at least half the set-down weight is applied to the assembly. This significantly reduces the chances that the plugs will be set prematurely even when they are run or pumped into the well at relatively high speeds. When developing the pumpdown concept, designers incorporated a circulation path for fluids exiting the tubing and returning to the Shear ring Shear ring DiamondBack Plug Aluminum slip pads with cast-iron facing Aluminum slip pads with cast-iron facing Pumpdown ring surface via the casing annulus. This process is not possible in cemented horizontal wells because until the well is perforated, the well is a closed system. Therefore, during plug and perforation operations using the pumpdown technique in a cemented horizontal wellbore, the first set of perforating guns those at the toe of the well must be conveyed on coiled tubing, wireline tractor or drillpipe. Service industry experts have tried several methods to avoid this costly step, including overdisplacing the cement to leave a flow path open through the casing shoe. For numerous reasons, including the inability to get a pressure test of the casing and cement, most operators deemed this wet shoe solution unacceptable. 10 Summer

32 Fracture ports Schlumberger researchers addressed the problem of opening this closed system without mechanical intervention through the KickStart pressure-activated rupture disc valve for cemented multistage fracturing. The valve is run as part of the casing string one or two joints above the float shoe. Its internal diameter is nearly equal to that of a 4 1 /2- or 5 1 /2-in. casing, which allows it to accommodate standard cement wiper plugs and requires no change to cementing procedures. The valve includes two discs, but only one must rupture for the stimulation to be successful. Once the disc ruptures, a helical port pattern made up of seven 6-in. long ports with 15 phasing is open to the cement sheath through which the interval is stimulated (above). Following numerous iterations in the laboratory, mathematical modeling and finite element analysis, designers arrived at this configuration, which minimized fracture initiation pressure through the cement Piston Rupture discs > First stage valve. The KickStart rupture disc valve eliminates an intervention during MSS operations by facilitating circulation at the toe of horizontal wells. The valve is part of the casing string and is cemented in place along with the casing. After the casing is pressure tested, the well is pressured to some value higher than the test pressure to rupture the discs and open the valve. The fracture ports are designed to ensure that at least one opening is within 3 of the minimum stress direction of the formation to be stimulated. while promoting a single vertical fracture in the cement. Experts have expressed doubts about the efficacy of fracture stimulations performed through ports instead of perforations, but the KickStart valve arrangement allays those concerns by ensuring that at least one of the fracturing slots is no more than 3 from one of the minimum stress points on the hoop stress envelope of the wellbore. The total area of all the ports is 69 cm 2 [10.7 in 2 ], which is the equivalent of six 0.6-m [2-ft] long perforation clusters with 19 shots per meter [6 shots per ft]. 11 After the casing string is cemented in place and the casing has been pressure tested, the driller increases pump pressure to a predetermined level, which ruptures the discs in the KickStart valve. This exposes the cement in the annulus through which the formation is stimulated. The final step of the treatment is to pump a flush fluid, which can also be used as the pumpdown fluid for the next plug and perforation gun assembly. Then, the remaining intervals may be plugged and perforated using standard pumpdown practices. Cabot Oil & Gas Corporation, a long-time Eagle Ford Shale operator, has implemented numerous innovations in the play, including reducing well spacing without sacrificing wellbore length. In one campaign, the completion engineer used the rupture disc valve to stimulate the toe section of the formation in more than a dozen wells. Typically, the wells in the Buckhorn area of the shale play are drilled in 5,500-ft [1,676-m] laterals and are stimulated in 14 to 20 stages. The operator tested its casing to 10,000 psi [68.9 MPa] with the KickStart valve discs set to rupture when the pressure was 10,600 to 10,800 psi [73 to 74.5 MPa]. Cabot engineers routinely pumped the first treatment consisting of more than 250,000 lbm [113,000 kg] of proppant, at 65 bbl/min [10 m 3 /min] through the valve ports. When engineers compared the results of the section treated through the valve with those treated through perforations, they found that the pump pressures, rates and volumes all compared favorably. They also concluded that the KickStart valve saved the operator more than US$ 100,000 per well by eliminating the coiled tubing intervention to perforate the interval at the toe of the well. 12 Savings per well is critical for operators producing from low-permeability formations because these plays are typically exploited using many wells that produce at rates near their economic limit. To make such a strategy work requires each well to be drilled, completed and produced efficiently. The plug and perforate procedure with the first stage performed using the KickStart rupture disc valves helps operators reach that goal. 13 Ball and Seat In the past decade, operators have come to view openhole completions in horizontal wells as substantially more cost-efficient than cemented completions. These systems use hydraulically set or swellable packers to isolate each interval. Sliding sleeve valves, run as part of the completion tubulars between packers, are opened by hydraulic pressure applied to a seal created by a ball that is dropped from the surface to land in a mated seat. These seats increase in size from the smallest in the toe to the largest in the heel of the well, thus the smallest ball passes through each seat to the toe and the largest stops in the first seat near the heel (next page). 30 Oilfield Review

33 The industry has embraced these openhole systems because they may result in certain advantages over plug and perforate cased hole completions: less time-consuming and less expensive completion operations production from the open hole as well as the fractures a simpler connection between the wellbore and the fractures wellbore fractures that generate higher early production. 14 These systems also have potential disadvantages. Unlike cased wells that are stimulated through valves or perforations, openhole stimulations are confined only by packers, which may leave large sections of formation exposed between them. As a consequence, the operator has little control of the fracture location or number of fractures created in a stage. In addition, as the ball seats decrease in size with well depth, friction pressures increase, which may result in higher overall fracture initiation and extension pressures. 15 There may also be problems with the interaction between the ball and seat. When the ball lands and pressure is applied, the sleeve slides downward, exposing the annulus for treatment. The ball and seat then become the barrier isolating the lower intervals of the hole that have been previously treated. Both these actuator and seal functions are critical. If the ball fails to create a seal, the sliding sleeve may not move and the interval cannot be treated. At the same time, previously treated zones below the seat may be exposed a second time to stimulation fluids and pressure, which can damage production from that zone as well. After all the intervals have been successfully treated, the balls must flow off their seats and not impair production. Operators had long assumed that the balls floated off their seats even though not all balls were accounted for in a ball catcher at the surface. The widely accepted explanation for this seeming discrepancy has been that some balls flow back to a highly deviated point in the well where they churn in the flow and smash against each other until they break into pieces that are small enough to flow out of the well. 16 However, some operators have become sufficiently concerned about ball material left in the well that they routinely mill the seats to make certain the flow path is clear. One operator found that after milling the ball-and-seat sleeves in 10 wells, estimated ultimate recovery 3-in. frac sleeve 2 1 /2-in. frac sleeve increased significantly; the experiment was expanded to more than 300 wells. 17 But elimination of a coiled tubing intervention to mill out plugs was one of the original drivers for adopting the ball-and-seat technology, and service companies have sought to eliminate the possibility of balls staying in place through numerous methods, including retrievable seats and valves; like most methods, however, that alternative also requires a coiled tubing intervention. 18 One of the issues with balls not seating or not floating off the seat after treatment is in the material used for the balls predominantly phenolic, composite or metal alloy. These balls must be light enough to flow out of the well but strong enough to land in the seat at a high velocity without being deformed or damaged. Some industry experts believe these low compressive strength balls are breaking before they have a chance to work. Under pressure, the balls may extrude, causing them to become stuck in their respective seats or one of the next seats uphole as they are flowed up the well. Additionally, some types of these balls are constructed in layers and have inherent weaknesses in the layer bonding that may cause them to fail under pressure. If they land on the seat in certain positions relative to the layering, they may delaminate and break apart. Schlumberger engineers have incorporated several solutions to address these concerns in the Falcon multistage stimulation method for uncemented wells. While testing various ball materials, the engineers also tested seat designs and discovered that spherical seats far outperformed typical cone-shaped seats. They also found that a magnesium alloy was superior to phenolic or composite ball material. The lightweight magnesium used in the Falcon system balls minimizes ball extrusion; in addition, the balls are temperature insensitive, flow back intact and do not break on contact with the seat or during stimulation. They are rated to 68.9 MPa differential pressure and are easily milled. In one configuration of the Falcon system, the toe valves have multiple smaller balls that land in a single seat. These balls are able to easily pass through the upper seats to reach the lower sections of the well, but the total flow-through area remains large enough even at the lowest > Typical ball-and-seat configuration. Ball-and-seat MSS systems use frac valves, or sleeves, with seats that decrease in size from heel to toe. This allows the lower valves to be activated by balls (red) small enough to pass through the upper valves. In long horizontal sections, this can become a problem as friction pressures increase with wellbore length and decreasing seat diameters. 11. Baihly et al, reference Baihly et al, reference Arguijo AL, Morford L, Baihly J and Aviles I: Streamlined Completions Process: An Eagle Ford Shale Case Study, paper SPE , presented at the SPE Canadian Unconventional Resources Conference, Calgary, October 30 November 1, Daneshy A: Hydraulic Fracturing of Horizontal Wells: Issues and Insights, paper SPE , presented at the SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, USA, January 24 26, Openhole packer 2-in. frac sleeve 1 1 /2-in. frac sleeve 15. Daneshy, reference Baihly et al, reference Wozniak G: Frac Sleeves: Is Milling Them out Worth the Trouble?, paper SPE , presented at the SPE Tight Gas Completions Conference, San Antonio, Texas, November 2 3, Griffin J, Barraez R and Campbell S: To Mill or Not to Mill: A Fully Retrievable Multistage Fracturing System, paper SPE , presented at the SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, March 26 27, Summer

34 point of the well to eliminate the effects of friction pressure on fracture initiation (below). The material and design of the seats allow them to be easily and quickly milled. No Limits Engineers at Schlumberger have recently developed a variation on ball-activated systems that may be used in cemented wells. The technique uses balls or darts to activate sliding sleeves that provide stage isolation. Because this technique does not require seats of decreasing diameter to get the balls to TD, the technique can be used to stimulate a nearly unlimited number of stages in a single continuous operation. The nzone multistage stimulation system includes a control line connected to sequential valves that make up part of the completion. To initiate the stimulation operation, a dart, which is pumped from the surface, lands on a C-ring an incomplete circle in the lowermost valve. The completion engineer then applies pressure against the dart, which opens the sliding sleeve and pressurizes the control line. This pressure is transferred to a piston in the valve immediately above it, which closes the C-ring, creating an O-ring with a reduced ID (next page, top). The first stage of the stimulation is pumped, and during the flush stage, another dart is released. This dart lands on the now-compressed C-ring, isolating Stage 2 from Stage 1. The resulting increase in pressure forces the sleeve to slide for Stage 2 and the control line to become pressurized and close the next C-ring, which is then ready to catch the next isolation dart. Stage 2 is treated, and during the flush stage, another dart Single Ball Seat 3,359 is pumped. When fracturing operations for all stages are complete, the well can be produced. The darts can remain in the well, but to obtain full wellbore access for future interventions, the darts must be milled out. Alternatively, the operator can deploy dissolvable darts. Recently, in an effort to increase production and reduce completion costs per well, the operator of the Dagang field in the Huanghua depression of eastern China, which had previously drilled only vertical wells, changed to horizontal wells. The first commercial discovery in this field was made in 1963 in the Tertiary Guantao group. By 1996, this oil-bearing play had expanded to 564 km 2 [218 mi 2 ] with proven original oil in place of 790 million metric tons (t) [5.8 billion bbl]. This same trend has a proven gas-bearing area of km 2 [40.3 mi 2 ] with original gas in place of 31 billion m 3 [1.1 Tcf]. Additionally, the depression has estimated proven gas condensate reserves of 7.34 million t [54 million bbl]. Currently, there are 23 oil and gas fields in Multiple Ball Seat 1,314 the depression, including 15 oil- and gasproducing fields in 24 development areas in the Dagang field. Annual production from this field is 4.3 million t [31.4 million bbl] of oil and 380 million m 3 [13 Bcf] of gas. This field has been traditionally produced through cased and cemented vertical wells. Because many wells of this type are required to produce these relatively low-permeability formations, the economics may be considered marginal despite the large production volumes. The operator recently set an oil production target rate for the field of more than 6,000 t/yr [44,000 bbl/yr] oil equivalent. Completing wells quickly and achieving incremental production gains in each well are the keys to reaching the operator s objective. To do so, engineers must properly identify and complete as many pay zones per well as possible using appropriate technology, including horizontal drilling. Additionally, the operator calculated that vertical wells in the target formation would produce an average of 15 m 3 /d [94 bbl/d] of oil, while horizontal wells would produce an average 45 m 3 /d [283 bbl/d] using traditional completion techniques. To increase the return on horizontal wells, and after assessing the plug and perforate methodology, engineers opted for an nzone completion that included a rupture disc valve placed at the toe of the well to expose the formation for treatment of the first stage. 19. Hua LG, Kai CH, Fould J, Lee JS, Long WH, Guo ZX, Aviles I and Baihly J: An Efficient Horizontal Cased Hole Multistage Stimulation Well: China Case Story, paper SPE , presented at the SPE Oil and Gas India Conference and Exhibition, Mumbai, March 28 30, Baihly et al, reference Martin et al, reference 5. 2,523 1,267 1,687 ~3,400 psi in. ball seat 1,220 ~1,300 psi Four in. ball seats Static pressure, psi Static pressure, psi 1,174 1,127 1,081 1,657 1,034 2, , > Multiple ball seats. By replacing a single ball-and-seat configuration (bottom left) with multiple seats (photograph, top), the Falcon multiple seat valve (bottom right) enables the system to use balls small enough to reach and activate the lower valves. The smaller ball size also reduces friction pressure and pump horsepower requirements as well as wear on the ball seat. 32 Oilfield Review

35 Hydraulic control line to upper valves and surface Fracture ports 3.75-in. internal diameter Shifted sleeve Open C-ring Closed circular ring > Unlimited numbers of stages. Using an nzone valve, operators ready the stage below the valve for treatment when a ball or dart lands in the seat of the sliding sleeve. Pressure increases in a hydraulic control line that connects numerous valves. When a lower nzone valve opens, stimulation fluids are pumped into the formation (yellow arrows). Pressure on the hydraulic line shifts a sleeve downward, causing a C-ring to move into the smaller inner diameter of the valve and form a smaller diameter circular seat that is ready to receive the next dart or ball to begin the process again. Because the seats are not in descending size, the process can be repeated for as many stages as are required to stimulate the entire well. Pressure Stage 1 C A B Stage 2 Dart in sliding sleeve seat Hydraulic control line to lower valves 3.25-in. internal diameter The horizontal section of the well was completed as a 5 1 /2-in. monobore casing cemented in an 8 1 /2-in. hole and treated via a four-stage stimulation. The disc valve at the shoe was opened at 3,500 psi [24 MPa] above the casing test pressure, which allowed engineers to test the casing as part of the cementing operation. After the disc valve ruptured, which manifested as a sudden pressure drop observed at the surface, engineers first performed a minifracture to determine formation parameters and confirm injectivity into the first zone; they followed that with the first stimulation stage. Completion engineers launched a ball from the surface during flush to isolate the first stage and begin Stage 2. When the ball landed in the first seat, the pressure increased, and engineers shut down the pumps. When pumping resumed, a sudden drop in pressure indicated the valve had opened and the formation was fractured using less Stage 3 Stage 4 Pressure Pump rate Proppant concentration Fluid volume Sand weight 8:24 9:36 10:48 12:00 13:12 14:24 15:36 16:48 18:00 19:12 Time > Stimulation treatment. Following the opening of the rupture disc valve to begin the MSS operation in the Dagang field in China, fracturing operations started with the treatment of the first zone. After a full flush on the first stage, the first ball was released into the well. This operation took about 1.5 h per stage. Once the ball landed on the first seat (second stage) at about 10:48, the pressure increased quickly (A), and all pumps were shut down. Pumping resumed, and a sudden drop in pressure indicated that the valve had opened (B). The pump rate was increased further (C), and the Stage 2 fracture was initiated. These steps were repeated until all four stages were treated. (Adapted from Hua et al, reference 19.) than 4,800 psi [33 MPa] pressure as measured at the surface. Engineers attribute this low fracture pressure to the helical port design of the Falcon fracture valves. These steps were repeated until all four stages were stimulated, during which fracture initiation pressures from Stage 1 to Stage 4 were 5,100, 4,800, 5,800 and 5,500 psi [35, 33, 40 and 38 MPa], respectively (below left). That pressures were different at each stage is a strong indication that all four stages were treated. Unlike most other wells in the area, the treated well was able to flow back immediately and without artificial lift. Production was 8 to 10 times greater than that of a vertical offset well and was expected to be triple that of an unstimulated horizontal well. After five weeks, because flow rates were higher than those in other wells in the field, the operator was able to produce the well using a less expensive electric submersible pump instead of a rod pump. Payout from the well in which the operator used the nzone system was calculated at two and one-half months in contrast to four months for the unstimulated horizontal well and eight months for vertical wells. The operator plans several more wells using MSS technology. 19 Not One Size Fits All As MSS technology rapidly transitions from emerging to mature status, the industry remains uncertain about how best to apply it. Exploiting liquid-bearing shales and other ultralowpermeability formations is a relatively recent endeavor, and long-term data are nonexistent. For example, while engineers have doubled the length of laterals in the Bakken Shale in the past decade, the stimulation stage count has increased 10-fold. At the same time, as lateral lengths have increased, operators have generally decreased stage spacing and the amount of proppant and fluid pumped per stage. And although data seem to indicate a limit to the rate of return on investment from more stages per well about 37 stages in the Bakken long-term economic analysis of these plays is currently impossible; these wells have not been producing for enough time to generate sufficient data for meaningful decline curve analysis. 20 Similarly, the industry is still learning how to get the most from the shales. For example, the industry does not yet fully understand the storage mechanisms of the Eagle Ford Shale and the factors that differentiate a good producing area from a mediocre one. 21 Only data gathered over time will answer the economic and reservoir questions of unconventional resources, even as technologies emerge to take advantage of that knowledge. RvF Summer

36 Babatunde Ajayi Seneca Resources Corporation Pittsburgh, Pennsylvania, USA Iroh Isaac Aso Ira J. Jay Terry, Jr. Kirby Walker Kevin Wutherich Canonsburg, Pennsylvania Jacob Caplan Dewey W. Gerdom PDC Mountaineer LLC Bridgeport, West Virginia, USA Brian D. Clark Utpal Ganguly Houston, Texas, USA Stimulation Design for Unconventional Resources The oil and gas industry has undergone a renaissance brought on by the development of ultralow-permeability reservoirs, made possible through horizontal drilling and hydraulic fracturing. Recent innovations in systematic engineering design are improving stimulation effectiveness and well production. Completion engineers are able to perform the entire design loop, from reservoir characterization to stimulation plan, monitoring and calibration and production evaluation. Xianwen Li Yonggao Xu Hua Yang PetroChina Changqing Oilfield Company Xi an, Shaanxi, People s Republic of China Hai Liu Beijing, People s Republic of China Yin Luo Chengdu, Sichuan, People s Republic of China George Waters Oklahoma City, Oklahoma, USA Oilfield Review Summer 2013: 25, no. 2. Copyright 2013 Schlumberger. For help in preparation of this article, thanks to Paul A. Babasick, Houston; John P. McGinnis and Barry L. McMahan, Seneca Resources Corporation, Houston; and Michael Yang, Beijing. Mangrove, Petrel, RST, Sonic Scanner, StimMAP LIVE and UFM are marks of Schlumberger. INTERSECT is a joint mark of Schlumberger, Chevron and Total. 1. For more on current horizontal drilling technology: Felczak E, Torre A, Godwin ND, Mantle K, Naganathan S, Hawkins R, Li K, Jones S and Slayden F: The Best of Both Worlds A Hybrid Rotary Steerable System, Oilfield Review 23, no. 4 (Winter 2011/2012): For more on steering horizontal wells: Amer A, Chinellato F, Collins S, Denichou J-M, Dubourg I, Griffiths R, Koepsell R, Lyngra S, Marza P, Murray D and Roberts I: Structural Steering A Path to Productivity, Oilfield Review 25, no. 1 (Spring 2013): Miller C, Waters G and Rylander E: Evaluation of Production Log Data from Horizontal Wells Drilled in Organic Shales, paper SPE , presented at the SPE North American Unconventional Gas Conference and Exhibition, The Woodlands, Texas, USA, June 14 16, The ability to efficiently exploit ultralow-permeability plays has invigorated the oil and gas industry around the globe. The transition from vertical to horizontal wells was spurred by development of revolutionary techniques for drilling and completion. Eventually, completion and stimulation design for horizontal wells evolved into a standard template the geometric method, whereby engineers divide the horizontal wellbore length evenly into the number of planned intervals, or stages, designated for fracture treatment. To promote fracture growth from multiple starting points, engineers then design stages typically with two to eight perforation clusters distributed uniformly along the stage length. The geometric approach for fracture design ignores the vertical and horizontal heterogeneity of unconventional reservoirs. Vertical wells may penetrate a stack of highly variable sandstone and shale strata. Horizontal wells may wander through heterogeneous portions of a reservoir, or even completely out of a reservoir, depending on how closely the driller was able to follow the target zone. Geologic heterogeneity along wellbores causes wide variability of rock properties that, in turn, directly affect where fracturing stages will encounter producible reservoir rock. Consequently, the geometric placement of stages often results in poor well performance, leading completion engineers to use manual, time-intensive methods of picking stage and perforation locations based on subtle well log characteristics. Increasingly, directional wells are being drilled and steered based on logging-while-drilling (LWD) data. 1 Engineers can use these measurements to characterize small-scale heterogeneities that horizontal wells encounter as they penetrate stratified formations. However, even with the addition of LWD data to help in planning stimulation programs, well performance has been difficult to predict. Recently, Schlumberger engineers analyzed production logs from more than 100 horizontal shale gas wells in six US shale basins to identify factors that influence the effectiveness of hydraulic fracture completions. 2 The analysis indicated that perforation efficiency the percentage of perforation clusters that contribute to production was about 70%. Nearly a third of the clusters contributed nothing to production. The investigators looked deeper into the data to explain this inefficiency. The data showed that increasing the number of fracture stages and decreasing the distance between stages and between perforation clusters correlated with a rise in production rate from a well. Stimulation design is a compromise between the extremes of a single customized fracture stage and of multiple stages to cover a wide variety of rocks. Increasing the number of perforation clusters and stages is not a guarantee for success. The analysis suggested that focused staging is important: Fracture stages should target rocks with similar petrophysical and geomechanical properties. 34 Oilfield Review

37 Summer

38 Reservoir Quality (RQ) Organic content Thermal maturity Effective porosity Intrinsic permeability Fluid saturations oil, gas, condensate and water Organic shale thickness Hydrocarbons in place > Reservoir quality and completion quality factors. Because it was apparent that not every stage contributed equally to well productivity, the investigators also examined the contribution of perforation clusters within fracture stages. They determined that, like fracture stages, not every cluster contributed equally to production, and they concluded that the optimal number of perforation clusters per stage ranged from two to five. The analysis suggested that strategic placement of clusters within productive and fracturable geologic units was more important than the number of clusters. The study results led to fundamental design questions: Is there an optimal number of treatment stages? Is there an optimal location for each treatment stage along a wellbore? Is there an optimal place for perforation clusters within stages? To address these questions, Schlumberger completion engineers developed the Mangrove reservoir 3. Cipolla C, Weng X, Onda H, Nadaraja T, Ganguly U and Malpani R: New Algorithms and Integrated Workflow for Tight Gas and Shale Completions, paper SPE , presented at the SPE Annual Technical Conference and Exhibition, Denver, October 30 November 2, Cipolla C, Lewis R, Maxwell S and Mack M: Appraising Unconventional Resource Plays: Separating Reservoir Quality from Completion Effectiveness, paper IPTC 14677, presented at the International Petroleum Technology Conference, Bangkok, Thailand, February 7 9, Fabric refers to the spacing, arrangement, distribution, size, shape and orientation of the constituents of rocks such as minerals, grains, porosity, layering, bed boundaries, lithology contacts and fractures. 5. For more on fracture staging algorithms: Cipolla et al (2011), reference For more on conventional hydraulic fracture models: Brady B, Elbel J, Mack M, Morales H, Nolte K and Poe B: Cracking Rock: Progress in Fracture Treatment Design, Oilfield Review 4, no. 4 (October 1992): Jeffrey RG, Zhang X and Thiercelin M: Hydraulic Fracture Offsetting in Naturally Fractured Reservoirs: Quantifying a Long-Recognized Process, paper SPE , presented at the SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, January 19 21, Completion Quality (CQ) Mineralogy mainly clay, carbonate and silica Mechanical properties Young s modulus, Poisson s ratio and tensile strength Natural fractures presence, density, orientation and condition (open, closed or cemented) In situ stress variations between intervals accounting for mechanical properties anisotropy stimulation design software for engineering, modeling and designing hydraulic stimulations. The software facilitates a systematic strategy for designing multistage stimulations centered on single wells embedded within the context of a 3D earth model of the reservoir. Completion and stimulation design is based on multidisciplinary reservoir characterization that is combined with microseismic information for model calibration and integrated with production forecasting for design evaluation. 3 This article describes the Mangrove software and outlines case studies that demonstrate how the software helps operators improve well productivity. Two examples from the eastern US show side by side comparisons of well productivities that result from conventional and engineered completions in the Marcellus Shale. An example from the Ordos basin of China illustrates improvements to production from lowpermeability sandstones. Suárez-Rivera R, Deenadayalu C, Chertov M, Hartanto RN, Gathogo P and Kunjir R: Improving Horizontal Completions on Heterogeneous Tight Shales, paper CSUG/SPE , presented at the Canadian Unconventional Resources Conference, Calgary, November 15 17, Suárez-Rivera R, Burghardt J, Stanchits S, Edelman E and Surdi A: Understanding the Effect of Rock Fabric on Fracture Complexity for Improving Completion Design and Well Performance, paper IPTC 17018, presented at the International Petroleum Technology Conference, Beijing, March 26 28, For more on the wiremesh model: Xu W, Thiercelin M, Ganguly U, Weng X, Gu H, Onda H, Sun J and Le Calvez J: Wiremesh: A Novel Shale Fracturing Simulator, paper SPE , presented at the CPS/SPE International Oil and Gas Conference and Exhibition in China, Beijing, June 8 10, For more on the UFM model: Weng X, Kresse O, Cohen C, Wu R and Gu H: Modeling of Hydraulic Fracture- Network Propagation in a Naturally Fractured Formation, SPE Production & Operations 26, no. 4 (November 2011): Kresse O, Cohen C, Weng X, Wu R and Gu H: Numerical Modeling of Hydraulic Fracturing in Naturally Fractured Formations, paper ARMA , presented at the 45th US Rock Mechanics/Geomechanics Symposium, San Francisco, June 26 29, Engineered Stimulations While Mangrove software provides a specific engineering workflow intended for predictive model building and evaluation of hydraulic fracture treatment in unconventional reservoirs, it also continues to support workflows and modeling necessary for conventional reservoirs. The Mangrove system is capable of accommodating reservoir heterogeneity, rock fabric, physical properties and geomechanical properties at a fine level of detail without compromising computational efficiency. 4 Input to the workflow comes from geologic, core, well log, seismic, production log and engineering data. Geologists, geophysicists and engineers compile, synthesize and interpret these data and summarize them in a common 3D earth model. This integration and display are performed within the Petrel E&P software platform. The earth model forms the basis for geologic, discrete fracture network (DFN) and geomechanical models that are input to the completion advisor as well as to a number of hydraulic fracture models and to production and forecasting simulators accessible within the Mangrove workflow. Engineers use the Mangrove completion advisor to assign levels of reservoir quality and completion quality to the reservoir rock (above left). Reservoir quality (RQ) is a prediction of how prone the rock is to yield hydrocarbon. Completion quality (CQ) is a prediction of how effectively the rock may be stimulated using hydraulic fractures. The RQ and CQ parameters typically receive binary scores of good or bad based on cutoff criteria for a reservoir. They are then combined into composite scores that grade the intervals from best to worst for placing fracturing stages and perforation clusters within each stage. The best locations have good RQ and CQ grades, meaning the rock should be productive and fracturable (next page). 5 The completion advisor also allows similar quality rocks to be grouped in the same stage, leading to the most effective multistage treatment. The completion advisor is able to accommodate user-provided operational constraints, such as the maximum stage interval or minimum and maximum perforation interval, and structural constraints such as fault locations and distances of perforation clusters from these faults. After deciding where to locate stages and perforation clusters, engineers design the stimulation treatments using hydraulic fracture (HF) simulators. In situations in which the geology is 36 Oilfield Review

39 relatively simple, conventional HF simulators are adequate. These time-tested 2D and pseudo-3d models treat HFs as planes propagating away from the well in the direction of the maximum principal compressive stress. 6 Engineers have the option to use these models in the Mangrove workflow and determine which model is best suited for a given reservoir. Conventional models are not comprehensive enough for heterogeneous and naturally fractured reservoirs. Hydraulic fracture growth is complex, and its characterization requires 3D models that incorporate interactions of HFs with natural fractures while also considering the impact of HFs on local principal stresses. 7 To address complex situations, the Mangrove system provides two fracture models: the wiremesh hydraulic fracturing model and the UFM unconventional fracture modeling simulator. The wiremesh model provides a mathematical equivalent representation of the hydraulic fracture network. 8 The wiremesh approach is relatively fast and suitable for environments that lack significant reservoir characterization data. To improve well productivity, completion designers are able to iterate and parameterize the input values to obtain an optimal stimulation design for fracture length, height, surface area and proppant distribution. The UFM model is the first commercially available complex hydraulic fracture model to incorporate fracture-to-fracture interactions. 9 The model accounts for the effects of natural fractures and geomechanical properties on hydraulic fracture growth and predicts dendritic multiple branching hydraulic fracture propagation as well as fluid flow and proppant transport. Hydraulic fracture growth is governed by the rock fabric and geomechanical properties of the reservoir, the preexisting fracture network and prevailing in situ stress magnitudes and anisotropy. As the HF network develops, it perturbs the stress field as each fracture surface becomes pressurized, opened and propped. Engineers may use the UFM simulator for HF network design to optimize well productivity. Regardless of the HF model engineers use to prepare their initial design, the result must be calibrated during HF stimulations. The Mangrove workflow is able to incorporate results obtained from monitoring microseismicity induced by propagating HFs to calibrate the predicted model. Geophysicists process the microseismicity data to locate seismic emissions from small slip events associated with the development of the Segments of Similar Lithology Austin Chalk Upper Eagle Ford Shale Stages of Similar Rock Quality and Stress Gradient Rock Quality RQ and good CQ Bad RQ and bad CQ Bad RQ and good CQ RQ and bad CQ Rock quality Stress gradient Low Stress gradient Lower Eagle Ford Shale High Buda Limestone Well segments Hydraulic fracturing stages Austin Chalk Eagle Ford Shale Buda Limestone > Dividing horizontal laterals into segments and stages. This horizontal well (top center) targets a reservoir zone near the boundary horizon (purple) between the upper and lower Eagle Ford Shale, which was deposited above the Buda Limestone and below the Austin Chalk. The other horizons are the top surfaces of the Buda Limestone (blue) and the upper Eagle Ford Shale (brown). Engineers divided the lateral into segments based on location within the reservoir, the wellbore trajectory and rock properties. Each segment contains similar lithology along its length. Engineers further subdivided the segments into stages (bottom center) based on similar minimum horizontal stress gradients, reservoir quality (RQ) and completion quality (CQ) along the length of each stage. Each stage is then a candidate for hydraulic stimulation. A color-coded rock quality index, shown above the well, combines RQ and CQ and indicates the best intervals for stimulation. The relative magnitude of the far field minimum horizontal stress gradient, shown along the bottom of the well, indicates the relative pressure levels at which the reservoir interval will fracture. [Adapted from Cipolla et al (2011), reference 3.] Summer

40 Perforation cluster Geometric Placement of Fracture Stages and Perforation Clusters Rock Quality RQ and good CQ Bad RQ and bad CQ Bad RQ and good CQ RQ and bad CQ Fracture stage Rock quality Stress gradient Stress gradient Low High Engineered Placement of Fracture Stages and Perforation Clusters Rock quality Stress gradient > Comparing hydraulic fracture designs for a horizontal well in the Eagle Ford Shale. In a geometric design (top), fracture stages (inset, four disks of the same color) and perforation clusters (individual disks) were distributed uniformly along the length of the lateral. In the engineered design from the Mangrove workflow (bottom), engineers determined the location and length of each fracture stage and the placement of each perforation cluster from analysis of the composite rock quality scores and minimum horizontal stress gradients. The optimal design is for all perforation clusters (PCs) to break down and initiate fractures at more or less the same pressure. The composite RQ and CQ rock quality index is shown along the top of the well. The relative magnitude of the far field minimum horizontal stress gradient is shown along the bottom of the well. [Adapted from Cipolla et al (2011), reference 3.] HFs. 10 Often, to increase the precision and accuracy of the event locations, geophysicists adjust their geologic and velocity models. These adjustments, in turn, are used to update the geomechanical and the DFN models for the HF models. Before and after completion of HF stimulations, production engineers run reservoir flow models to predict the resulting production performance. These models couple mechanical deformation and pore volume changes. The fracture models simulate rock deformation, the creation of conductive fractures and channels in the reservoir and the placement of proppant into them. The reservoir simulators predict the flow of fluids from the reservoir into and through the higher conductivity pathways created by HFs that have been propped open. Within the Mangrove workflow, these calculations may be performed using the INTERSECT reservoir simulator, which allows unstructured gridding for a range of grid densities. Fine gridding in the vicinity of the wellbore and HF network captures fine-scale details. Coarse gridding is usually sufficient far from the wellbore and HF network. 11 The Mangrove workflow provides analysis from data entry to model updates. In this process, geologic and engineering field data are input for building models of the reservoir. Engineers use the models to estimate RQ and CQ (above). Engineers input the completion design into 2D or 38 Oilfield Review

41 3D HF simulators for evaluating the fracture stimulations that will be pumped and then feed the stimulation design into reservoir simulators to forecast production. The system is able to incorporate microseismicity monitoring to calibrate steps in the Mangrove workflow. Such calibration comes from locating microseismic events precisely and comparing these locations with predicted HF growth. The location of microseismic events may help the system estimate the effective stimulated reservoir volume, which may then be used to adjust the completion and stimulation strategies of subsequent fracture stages or make adjustments even while stimulation is occurring in some stages. In addition, to obtain precise microseismic event locations, geophysicists conduct seismic velocity inversion, and in the process, adjust the starting model of the geologic and mechanical properties within the reservoir zone. The adjusted model may be used to update predictions of hydraulic fracture growth and forecasts of reservoir production. The Mangrove workflow centers around completion and stimulation design for single wells within the 3D context of a larger reservoir model. The focus on single wells reduces model size, enables faster calculations and gives completion engineers flexibility to make quick decisions and adjustments to stimulation programs. The Mangrove software may be run on a single platform, which eliminates the need to migrate data from one software application to another and to address problems of software interfaces and interoperability. 10. For more on hydraulic fracture monitoring: Bennett L, Le Calvez J, Sarver DR, Tanner K, Birk WS, Waters G, Drew J, Michaud G, Primiero P, Eisner L, Jones R, Leslie D, Williams MJ, Govenlock J, Klem RC and Tezuka K: The Source for Hydraulic Fracture Characterization, Oilfield Review 17, no. 4 (Winter 2005/2006): Burch DN, Daniels J, Gillard M, Underhill W, Exler VA, Favoretti L, Le Calvez J, Lecerf B, Potapenko D, Maschio L, Morales JA, Samuelson M and Weimann MI: Live Hydraulic Fracture Monitoring and Diversion, Oilfield Review 21, no. 3 (Autumn 2009): For more on the INTERSECT simulator: Edwards DA, Gunasekera D, Morris J, Shaw G, Shaw K, Walsh D, Fjerstad PA, Kikani J, Franco J, Hoang V and Quettier L: Reservoir Simulation: Keeping Pace with Oilfield Complexity, Oilfield Review 23, no. 4 (Winter 2011/2012): Walker K, Wutherich K, Terry J, Shreves J and Caplan J: Improving Production in the Marcellus Shale Using an Engineered Completion Design: A Case Study, paper SPE , presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, October 8 10, Gerdom D, Caplan J, Terry IJ Jr, Wutherich K, Wigger E and Walker K: Geomechanics Key in Marcellus Wells, The American Oil & Gas Reporter 56, no. 3 (March 2013): A software-mediated systematic approach to planning, engineering and executing stimulations has proved to be more effective than conventionally planned stimulations. PDC Mountaineer LLC and Schlumberger obtained favorable results with engineered completions in the Marcellus Shale. Comparing Completion Methods PDC Mountaineer LLC (PDCM) focuses primarily on natural gas production from the Marcellus Shale formation. In the company s efforts to develop a Marcellus Shale field near Bridgeport in Harrison County, West Virginia, USA, its first three horizontal wells were only marginally economic. Consequently, PDCM wanted to determine how to improve production. The company started each of these first wells by drilling and logging a vertical pilot well. Engineers used these data to determine the target reservoir zone and the landing point for the horizontal well, or lateral. PDCM then drilled the laterals using data derived from mud logs and logging-while-drilling (LWD) gamma ray for guidance to stay within the target zone. The laterals were completed using designs based on a geometric method stages and perforation clusters distributed uniformly followed by slight manual adjustments to the design to move perforation clusters within each stage to zones that were estimated to have lower minimum horizontal stress. 12 PDCM and Schlumberger engineers analyzed the data from the first three wells and concluded that the completion designs paid little attention to specific conditions in each well lithology, reservoir quality, mechanical properties and in situ stresses. Furthermore, examination of stimulation-induced microseismicity monitored during the treatments showed a relationship between the locations of perforation clusters, predicted minimum in situ horizontal stress and microseismic activity; the highest microseismic activity concentrated near perforations in rocks of low stress, and lower activity occurred elsewhere. Fractures started and grew by taking paths of least resistance. Areas near the geometrically located perforation clusters were effectively stimulated only when the clusters happened to be located in easily fractured rock. Otherwise, areas tended to be understimulated because the perforation clusters were not strategically located. The analysis indicated that optimal stimulations would result if the completions were engineered so each stage and each perforation cluster contributed to the overall production in proportion to their number. Horizontal wells would be divided into segments of similar lithology that did not include discontinuities primarily faults, fractures and highly laminated intervals. The segments would then be divided into stages and perforated in rocks of similar minimum horizontal stress. During each fracture stage, all perforations would initiate fractures at roughly the same pumping pressure, the fractures would extend and propagate together, and eventually, production would flow from the fractures in proportion to the stimulated reservoir volume they contact. To test this procedure, the PDCM team selected three new well locations, near the original three wells, which had similar reservoir and completion quality. Except for the engineered design for distributing the staging and perforation locations along the laterals, the new wells would be completed in the same way as the earlier wells. The wells were drilled in the direction of the regional minimum in situ principal horizontal stress to facilitate opening of hydraulic fractures emanating perpendicularly from the wells. The lateral wells cut across rocks of variable lithology and, consequently, mechanical properties, which dictate how the regional stress field is transmitted through the rock to the local borehole wall. After drilling the wells and before designing the completions, the team collected the following well information: wellbore directional surveys, gamma ray logs, petrophysical and mechanical properties for evaluating RQ and CQ, planned fracture fluid types and properties, pumping rates, number of stages, number of perforation clusters per stage and perforation diameter, density and phasing. The completion design called for slickwater to be pumped at 80 bbl/min [13 m 3 /min] through five perforation clusters in each stage. Engineers assembled this information in the Mangrove workflow software and constructed 3D earth models of each well. Based on data from the 3D earth models, engineers were able to segment the wells into lengths of similar lithology; each segment was subdivided into stages, such that each stage length contained rock of similar reservoir quality and was capable of accepting the planned pumping rate. The team selected perforation locations based on completion quality. The perforation locations were adjusted until the models showed that fractures initiated at each perforation cluster within a stage at the same pressure within a tolerance of 0.01 psi/ft [0.23 kpa/m] for the Summer

42 minimum in situ stress gradient. 13 When the team was satisfied with the completion plans, the wells were stimulated (below). Completion engineers conducted each fracture treatment according to the intended proppant schedule. Compared with the treatments in the original three horizontal wells, the engineered completions were pumped at 10.3% higher average pumping rates and 5.7% lower average treating pressures. In addition, the treatments succeeded in placing 30% more of the designed proppant load per lateral and experienced no screenouts (next page, top left). The team compared the first 30 days of production from each well, which revealed a second measure of success. Compared with the original wells, the engineered completions resulted in significantly higher production. During the first 30 days, the engineered completions resulted in 106% higher initial cumulative production per foot of stimulated wellbore length than the original three wells. Based on these positive results, PDC Mountaineer now performs engineered completion designs for all its horizontal wells. The company has determined that the time and effort spent on the design are more than offset by the savings from operational effectiveness during completions and revenue from increased production. 14 Perforating Low-Stress Intervals Seneca Resources Corporation and Schlumberger conducted another test of engineered completion design. Seneca Resources produces natural gas from Marcellus Shale reservoirs in Pennsylvania and New York, USA. The company sought to increase production by maximizing reservoir contact through hydraulic fracture stimulations from horizontal wells. Seneca Resources had been stimulating wells in the Marcellus Shale but results were highly variable, even from apparently identical wells. However, the Marcellus Shale comprises many thin laminations, each distinct from its neighbor in terms of physical and mechanical properties. As horizontal wells cut through the formation, they intercept these varied laminations. The company teamed with Schlumberger to conduct a controlled pilot study to test the effectiveness of engineered completions compared with what had been standard practice for the company geometric completions. Measured Depth, ft X1,000 Gamma Ray Minimum Stress Gradient Poisson s Ratio Young s Modulus Calcite Volume Quartz Volume Kerogen Volume Effective Porosity 0 gapi psi/ft MMpsi % % % 25 0 % 15 Stimulation Stages Perforation Cluster Stage 14 Stage 13 Segment 1 Measured Depth, ft Original Minimum Stress Gradient 5-ft Moving Average Smoothed Minimum Stress Gradient 0.67 psi/ft psi/ft 1.01 X1,500 Stage 12 Segment 2 X3,850 Stage 11 X2,000 Stage 10 X3,900 X2,500 Stage 9 Stage 8 Segment 3 X3,950 X3,000 Stage 7 X3,500 Stage 6 X4,000 Stage 5 X4,000 X4,500 X5,000 Stage 4 Stage 3 Stage 2 Stage 1 X4,050 Segment 4 Stress gradient Low High > Segments, stages and clusters. Stresses typically change from one lithology to another. To prevent a fracture stage from crossing a lithology barrier, engineers divide the well into segments of similar lithology. Stimulation stages (left, Track 9, green and light blue) should be contained within a segment, and their lengths should be within prescribed minimum and maximum values. Engineers position the perforation clusters (Track 9, short horizontal lines to the left and right of the fracture stages) based on preset design criteria: the number of clusters per stage, the minimum and maximum distance between clusters and a minimum horizontal stress gradient (Track 2) tolerance of 0.01 psi/ft [0.23 kpa/m]. During completion design and modeling, these criteria may need to be relaxed to account for the minimum horizontal stress variation. A close-up of the red box (right) from Track 2 shows the stress gradient ranges from high (blue) to low (red). The original stress gradient logs were recorded every half foot (inset, Track 1) and smoothed using a 5-ft [1.5-m] moving average algorithm (inset, Track 2) to account for imprecision during the perforating operation. (Adapted from Walker et al, reference 12.) 13. The rate of these stress variations within a few borehole diameters of the wellbore, away from the immediate influence of the borehole, is the wellbore-parallel stress gradient and, for wells drilled parallel to the minimum in situ principal stress direction, is equivalent to the minimum stress gradient. 14. Walker et al, reference Wutherich K, Walker K, Aso I, Ajayi B and Cannon T: Evaluating an Engineered Completion Design in the Marcellus Shale Using Microseismic Monitoring, paper SPE , presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, October 8 10, Waters G and Zhao R: Measuring the Impact of Geomechanical Heterogeneity in Organic Shales on Hydraulic Fracture Initiation and Propagation, paper CSUG/SPE , presented at the Canadian Unconventional Resources Conference, Calgary, November 15 17, Oilfield Review

43 Design Summary Well Well 1 Well 2 Well 3 Well 4 Well 5 Well 6 Design Proppant per Lateral, lbm/ft Design Pumping Rate, bbl/min Average Perforation Completion Lateral Stage Clusters Method Fluid Length, ft Stages Length, ft per Stage Nonengineered Slickwater 3, , Nonengineered Slickwater 2, , Nonengineered Slickwater 2, , Average 2, , Engineered Slickwater 4, , Engineered Slickwater 3, , Engineered Slickwater 3, , Average 4, , Well A Well B Well C 0 m ft 1,000 N Completion Summary 30-Day Cumulative Production Monitor well Well Well 1 Well 2 Well 3 Average Well 4 Well 5 Well 6 Average Average difference Percent average difference Average Treating Pressure, psi 7,749 7,557 7,716 7,674 7,308 7,105 7,298 7, % Average Treatment Rate, bbl/min % Placed Proppant per Lateral, lbm/ft 1, ,103 1,002 1,251 1,245 1, % Percentage of Proppant Placed Versus Design 107.0% 55.0% 65.0% 75.7% 92.8% 101.7% 100.5% 98.3% 22.7% 30.0% > Summary of completion design and results. Data from six horizontal wells drilled into the Marcellus Shale illustrate the results of nonengineered and engineered completion methods (top). Wells 1 to 3 were drilled and completed conventionally. Wells 4 to 6, which were drilled near Wells 1 to 3, were completed using an engineered design method that specifies stage and perforation cluster placement. The engineered completions were more effective than the nonengineered completions (bottom); the success of the engineered completions is measured by lower treating pressures, higher pumping rates, more efficient proppant placement and higher cumulative production after 30 days compared with those in the nonengineered completions. (Adapted from Walker et al, reference 12.) Gross, Mcf 63,194 42,396 65,039 56, , , , , , % Normalized by Lateral Length, Mcf/ft % Normalized by Number of Stages, Mcf/ft 4,514 6,057 9,291 6,094 17,719 13,554 15,036 15,437 9, % Normalized by Number of Perforation Clusters, Mcf/cluster 903 1,211 1,858 1,219 3,544 3,012 3,341 3,308 2, % > Well plan. From a single pad, Seneca Resources drilled horizontal Wells A, B and C and drilled a vertical monitor well for recording stimulation-induced microseismicity. Well A was completed following a geometric design and Wells B and C were completed according to engineered completion designs. The disks on each well, which represent perforation clusters, are grouped into fracture stages with adjacent stages differentiated by color. (Adapted from Wutherich et al, reference 15.) The company drilled three horizontal wells into the same Marcellus Shale reservoir zone from the same drilling pad. The laterals were drilled parallel to one another, 800 ft [240 m] apart and aligned to the northwest, in the direction of the regional minimum in situ principal horizontal compressive stress (above right). Well A, the base case, was completed using the standard geometric method. 15 Wells B and C were completed using the engineered approach. The RST reservoir saturation tool and Sonic Scanner acoustic scanning tool were run along each lateral after casing had been set to determine the extent of variation between lithologic and mechanical properties and the resolved stresses in the three wells. 16 These measurements were compiled and interpreted using the Mangrove workflow software to produce an engineered completion strategy for each well. Although completion strategies were customized to optimize production from each well, engineers kept a number of completion variables fluid, proppant type and size and pumping flow rate the same and also kept the number of stages, number of perforation clusters per stage and amounts of proppant per length of lateral similar for both wells. Nonetheless, some variability existed across the three wells. By their nature and because they are intended to account for the rock and stress heterogeneity along the wellbore, engineered completion designs inevitably result in variable stage lengths, perforation cluster spacings and pumping schedules. To accommodate these variations and maintain the spirit of consistency, the company staggered the timing of the well stimulations using a zipper-fracture method, whereby plug and perforation operations followed by stimulation of stages were rotated from one well to the next. As Well A was being stimulated, Well C was undergoing plugging and perforating. Then stimulation moved to Well B, while plugging and perforating moved to Well A. This process continued until stimulation of all stages in all the wells was complete. The stimulation engineering team analyzed pilot study results by comparing treatment, microseismicity and initial flowback data from the geometrically designed completion in Well A to similar data from the engineered completions in Wells B and C. Because all of the perforation clusters were engineered to be located in wellbore intervals of relatively low minimum principal stress, the average fracture breakdown and treatment pressures were 7% Summer

44 Design Summary Well Well A Well B Well C Design Proppant per Lateral, lbm/ft Design Pumping Rate, bbl/min Completion Method Fluid Proppant Size Lateral Length, ft Stages Average Stage Length, ft Perforation Clusters per Stage Geometric Slickwater 40/70 5, , Engineered Slickwater 40/70 4, , Engineered Slickwater 40/70 4, , Completion Summary Flowback Results Well Average Breakdown Pressure, psi Average Treating Pressure, psi Average Treatment Rate, bbl/min Placed Proppant per Lateral, lbm/ft Percentage of Proppant Placed Versus Design Maximum Flow, Mcf/d/1,000 ft Tubing Pressure, psi Choke, in. Well A Well B Well C Difference Percent difference 5,572 5, % 7,277 7, % % 1,122 1, % 68% 83% 15% 22% % 1,500 1,800 1, % 5/8 5/8 5/8 > Summary of completion design and results. Of three horizontal wells drilled into the Marcellus Shale, Well A, the reference case, was completed following a geometric design (top). Wells B and C were completed according to engineered completion designs, which were more effective than the geometric completion. Their relative success is measured by lower breakdown and treating pressures, higher pumping rates, more effective proppant placement and higher flowback rates than those of Well A (bottom). (Adapted from Wutherich et al, reference 15.) and 3% lower and the average treatment rate and amount of proppant placed were 16% and 22% higher in Wells B and C, respectively, than in Well A. The treatment comparison indicated that the engineered completions were more effective than the geometric completion (above). Initial gas flowback rates from Wells B and C were 33% and 40% higher than the rates from Well A on the same 5/8-in. choke size. In addition, fracture-water flowback recovery from Wells B and C was twice that from Well A. These flowback data suggest that the wells stimulated by engineered completions were making better reservoir contact, leading to better production, than was the geometrically completed well. During the pilot study, the team placed a vertical monitor well between Wells A and B; the well was instrumented with geophones for monitoring microseismicity induced by the stimulations in the three wells. The StimMAP LIVE real-time microseismic monitoring service recorded and analyzed microseismicity. When compared with perforation cluster locations, microseismic event locations from the StimMAP LIVE service revealed that as much as 35% of the perforation clusters in Well A, with the geometric completion, were not contributing to the reservoir volume targeted for stimulation. In contrast, microseismicity from the engineered completions and stimulations in Wells B and C showed improvement in the percentage of perforation clusters that contributed to the stimulated reservoir volume only 20% of the perforation clusters made little to no contribution (next page). The microseismicity comparison indicated that the engineered completions resulted in better placement of perforation clusters than did the geometric completion. The Mangrove workflow software not only produced the designs that led to these positive results but also reduced completion design time from several hours to about one hour per well. Moreover, the software rationalized data handling and procedural operations, which led to fewer inaccuracies and improved perforation placement. Seneca Resources continues to use computer-aided completion design and microseismic analysis on other wells in its fields. 17 Stimulation of Tight Oil Sandstone Conventional reservoirs are also candidates for the application of the systematic, engineering approach to reservoir stimulation. The PetroChina Changqing Oilfield Company conducted a pilot study using the engineered approach for designing reservoir stimulation in a conventional clastic reservoir. The Ordos basin, in north-central China, is a gentle monocline that dips stratigraphically about 1 from east to west. Its fill, which consists of sediments deposited during the Paleozoic, Mesozoic and Cenozoic eras, thickens in the dip direction with an average thickness of 4 to 5 km [2.5 to 3.1 mi]. The Paleozoic sediments are marine deposits that yield primarily natural gas, while the Mesozoic sediments have a continental origin and yield oil Wutherich et al, reference For more on the Ordos basin: Yang Y, Li W and Ma L: Tectonic and Stratigraphic Controls of Hydrocarbon Systems in the Ordos Basin: A Multicycle Cratonic Basin in Central China, AAPG Bulletin 89, no. 2 (February 2005): Oilfield Review

45 Well A Event count Event count 0 0 A B Event count Event count 0 0 C D Well B 40 Stress gradient 40 Stress gradient Event count Low High Event count Low High 0 0 A B 250 Stress gradient 40 Stress gradient Event count Low High Event count Low High 0 0 C D > Microseismicity comparison. Microseismicity resulting from four fracture stages in Well A (top) and Well B (bottom) indicate improved stimulations from the engineered completions in Well B over the stimulations from the geometric completions in Well A. In each panel, the data show results from a fracture stage; the disks along the colored well trace represent stimulated perforation clusters and the dots are induced microseismic event locations. To show correlation, the disks and dots have the same color. Above the well trace, the height and color of the orange-to-green bars indicate the number of microseismic events along each wellbore interval. Below the well trace on Well B, the minimum horizontal stress gradient is plotted; the amplitude and color of the pink-to-blue shading specify the closure stress gradient level. The company placed perforation clusters based on engineering design principles at locations with relatively low stress gradients. There is a better one-to-one correspondence between microseismicity and perforation locations in Well B than in Well A, indicating improved perforation performance results from an engineered completion design. (Adapted from Wutherich et al, reference 15.) Summer

46 300 m 300 m Ordos Basin 250 m MW1 Beijing 500 m MW2 C H I N A Xi an Shanghai 500 m MW3 N 250 m HW2 HW m ,500 ft Basin Gas field Oil field South China Sea > Ordos basin, north-central China. A completions team conducted a pilot study to test engineered completion designs from Mangrove software. The field test area (white box) is in southwest Ordos basin. The well layout (inset) consists of two parallel horizontal production wells (HWs) and three vertical monitoring wells (MWs, blue circles) constucted for recording microseismicity. The Chang 7 member of the Yanchang Formation was the target horizon. (Adapted from Liu et al, reference 20.) The Yanchang Formation is a thick sequence of lake and delta sediments deposited during the Late Triassic period. The formation consists of 10 lithologic members, named Chang 1 to Chang 10 from top to bottom. The members are stacks of alternating mudstone, siltstone and sandstone layers that result in vertical heterogeneity. The reservoirs in the Yanchang Formation are naturally fractured, low-permeability sandstones in which porosity is typically about 10% and permeability is generally 0.1 to 10 md. The natural fractures occur in two sets that tend to dip steeply and generally strike in the ENE and NNW directions. 19 To produce oil from these low-permeability reservoirs, an operator must stimulate the production intervals through multistage hydraulic fracturing. Historically, most production wells have been vertical, and after HF stimulation, their initial production rates have varied from 5 to 8 m 3 /d [30 to 50 bbl/d]. In the few horizontal wells, the initial production rates after HF stimulation have averaged 32 m 3 /d [200 bbl/d]. While still considered economic, these production rates are only marginally acceptable. To improve the production outcomes from its stimulation programs, the company partnered with Schlumberger in a pilot project to test the Mangrove workflow in horizontal wells in a tight oil reservoir zone in the southwest Ordos basin. 20 The company drilled two 1,500-m [4,920-ft] parallel horizontal wells in the Chang 7 member of the Yanchang Formation. The wells, 600 m [1,970 ft] apart, were drilled in the N15 W direction, which is parallel to the minimum in situ principal horizontal stress direction in the Ordos basin. The company drilled three vertical wells 500 m [1,640 ft] apart between and along a line parallel to the horizontal wells; these vertical wells were added for microseismicity monitoring (MSM) during the fracture stimulations of the horizontal wells (above). The pilot study team constructed 3D geologic, geomechanical and DFN models from the pilot study well log data and from core descriptions and geologic studies in the surrounding area (next page). These models were calibrated using data from the three monitoring wells and integrated using the Mangrove system to form the bases for modeling reservoir quality, completion quality, stimulation staging and perforation placement, hydraulic fracture stimulation design and production performance forecasting. Optimal stimulation design requires that each stage and its perforation clusters be placed in wellbore intervals that have a high likelihood of producing economic amounts of hydrocarbon and breaking down by fracturing in response to increased pressure during stimulation. These wellbore intervals possess good RQ and good CQ. The team used the Mangrove completion advisor to select 18 stages per well. In conjunction with the completion advisor, the team used the UFM simulator to predict HF propagation, growth and interaction with natural fractures (NFs) in the reservoir. Depending on the in situ stress direction and anisotropy in relation to the reservoir NF system, hydraulic fractures may take advantage of the NFs to produce 19. For more on the Yanchang Formation: Lianbo Z and Xiang-Yang L: Fractures in Sandstone Reservoirs with Ultra-Low Permeability: A Case Study of the Upper Triassic Yanchang Formation in the Ordos Basin, China, AAPG Bulletin 93, no. 4 (April 2009): Liu H, Luo Y, Li X, Xu Y, Yang K, Mu L, Zhao W and Zhou S: Advanced Completion and Fracturing Techniques in Tight Oil Reservoirs in Ordos Basin: A Workflow to Maximize Well Potential, paper SPE , presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, October 8 10, Yang H, Xu YG, Yang KW, Zhou SX, Liu H and Luo Y: Optimized Treatment Design Shows Promise, E&P 86, no. 2 (February 2013): Weng et al, reference Oilfield Review

47 Horizon Surface Total Vertical Depth, m MW1 MW2 MW3 Neutron Porosity (left) 0 % 100 Neutron Porosity (left) 0 % 100 Bulk Density (right) Neutron Porosity (left) 0 % 100 Bulk Density (right) Resistivity Gamma Ray Resistivity Gamma Ray Bulk Density Resistivity (right) Gamma Ray 7 ohm.m g/cm gapi ohm.m 2,200 1 g/cm gapi ohm.m 1,700 1 g/cm gapi 200 X, MW1 MW2 MW3 HW2 HW1 X, X, X,400 X,500 3 X,600 MW1 2 X,700 MW2 MW3 1 X,800 N HW1 HW2 > Model building for Ordos basin wells. Because there were no seismic or geologic data for the location, model building started after well logs were acquired from the three vertical monitor wells (left, MWs). Logs for each well display resistivity (Track 1), neutron porosity and bulk density (Track 2) and gamma ray (Track 3). Geoscientists began model building by extracting geologic horizon surfaces based on well-to-well correlations between the monitoring wells. Engineers used the surfaces for well placement guidance (top right) and for 3D model development (middle right) by upscaling petrophysical properties derived from well log data and filling in between the wells while honoring the horizon surfaces. Geologists created a simple discrete fracture network (DFN) model (bottom right) based on geologic studies and core descriptions. The DFN contained two dominant steeply dipping fracture sets, characterized by average strike orientations of N75 E (cyan) and N15 W (purple) and average fracture spacing of 15 m [49 ft]. The DFN was calibrated later and modified based on microseismicity data. (Adapted from Liu et al, reference 20.) complex HF networks and, consequently, high fracture surface area to make contact with the reservoir. The production of complex HF networks is more likely when the in situ stress anisotropy is low. 21 During the UFM modeling, the team was also concerned about determining how existing HFs affected the behavior of subsequent HFs. After an HF is created and filled with proppant, the immediate vicinity of the HF changes forever. The HF imposes a compressive stress component, or stress shadow, that acts outward from the HF plane in the minimum principal stress direction It alters the local stress magnitude and anisotropy near the fracture and affects adjacent fractures through mechanical interactions. To properly space HF stimulation staging, engineers must include such stress shadow effects when calculating CQ. After selecting the stage and perforation locations, the team began to execute its design. During stimulation operations, the team employed the StimMAP LIVE real-time microseismic monitoring (MSM) service. After each stage, the team used MSM results to recalibrate the 3D models, UFM model and stimulation design. For the next stage, the engineers wanted to maximize the HF surface area and proppantfilled volume to obtain the best production from the stimulated reservoir interval. MSM data suggested that the HFs being created tended to be long and contained within the targeted Chang 7 reservoir interval. While monitoring the first five to six stages, the team observed considerable overlap of microseismicity from neighboring stages, indicating suboptimal stage spacing. The team decided to Summer

48 Measured Depth, m X,200 X,400 X,600 X,800 Y,000 Y,200 Y,400 Y,600 Gamma Ray Stress Gradient High Low Minimum Stress Gradient 0 gapi psi/m 0.30 Bad RQ Bad Bad Rock Quality RQ and good CQ Bad RQ and bad CQ Bad RQ and good CQ RQ and bad CQ Bad > Completion advisor results. Engineers used the Mangrove completion advisor to compile and analyze petrophysical data to select fracture stages and perforation cluster locations for wells in the Ordos basin. Gamma ray (Track 1) and the minimum horizontal stress gradient (Track 2) were key parameters for the design. For the stress gradient profile, blue is high and red is low. Reservoir quality (Track 3), completion quality (Track 4) and composite (RQ plus CQ) quality scores (Track 5) provide color-coded quality indicators for stage and cluster selection. Initially, engineers proposed 18 stimulation stages (Track 6). After 5 stages were stimulated, engineers recalibrated the stimulation program using microseismic monitoring data and, as a result, reduced the number of stages to 13 (Track 7). The blue spikes (Tracks 6 and 7, left and right of stimulation stages) indicate proposed perforation cluster locations. (Adapted from Liu et al, reference 20.) CQ Bad Bad Composite GG BB BB GG GG GG GG GG GG GG GG GG GG GG Initial Stimulation Stages Perforation Cluster Stage 18 Stage 17 Stage 16 Stage 15 Stage 14 Stage 13 Stage 12 Stage 11 Stage 10 Stage 9 Stage 8 Stage 7 Stage 6 Stage 5 Stage 4 Stage 3 Stage 2 Stage 1 Updated Stimulation Stages Perforation Cluster Stage 13 Stage 12 Stage 11 Stage 10 Stage 9 Stage 8 Stage 7 Stage 6 Stage 5 Stage 4 Stage 3 Stage 2 Stage 1 increase the spacing of stages and reduce the number of stages from 18 to 13 per well (left). After all 26 stages were stimulated in both horizontal wells, the operator put the wells into production. Initial production rates were m 3 /d [649.1 bbl/d] and m 3 /d [783.1 bbl/d], a three- to fourfold improvement over the average production rate of 32 m 3 /d from previous horizontal wells. After three months, the production rates from these wells stabilized and were 50% higher than the previous best production from any horizontal well in the formation. Stimulation by Design Unconventional reservoirs provide special challenges because they are heterogeneous reservoirs composed of highly stratified sediments. Staying within a reservoir zone during horizontal drilling is difficult. Consequently, the wellbore intersects variable lithologies, which exhibit dissimilar petrophysical and mechanical properties. Unconventional reservoirs are also usually anisotropic and naturally fractured. Shales possess layering caused by the horizontal alignment of finely laminated sediments and platy clay minerals. This layering causes rock properties, such as permeability, elastic moduli and electrical resistivity, to be anisotropic. 22 These properties may vary more from layer to layer than within layers. Natural fractures may cut across this layering and superimpose additional anisotropy on the shales. Both anisotropy and natural fractures complicate the propagation of hydraulic fractures. 23 Recent advances in multistage stimulation technology are making it possible to stimulate and develop unconventional hydrocarbon resources more successfully (see Multistage Stimulation in Liquid-Rich Unconventional Formations, page 26). Parallel advances in the Mangrove stimulation design software are making it possible to design completions that are more effective. Integration of the two technologies promises a positive future for unconventional resource development. RCNH 22. For a discussion of permeability anisotropy: Ayan C, Colley N, Cowan G, Ezekwe E, Wannell M, e P, Halford F, Joseph J, Mongini A, Obondoko G and Pop J: Measuring Permeability Anisotropy: The Latest Approach, Oilfield Review 6, no. 4 (October 1994): For more on elastic anisotropy: Armstrong P, Ireson D, Chmela B, Dodds K, Esmeroy C, Miller D, Hornby B, Sayers C, Schoenberg M, Leaney S and Lynn H: The Promise of Elastic Anisotropy, Oilfield Review 6, no. 4 (October 1994): For more on the anisotropy of electrical properties: Anderson B, Bryant I, Lüling M, Spies B and Helbig K: Oilfield Anisotropy: Its Origins and Electrical Characteristics, Oilfield Review 6, no. 4 (October 1994): Wu R, Kresse O, Weng X, Cohen C and Gu H: Modeling of Interaction of Hydraulic Fractures in Complex Fracture Networks, paper SPE , presented at the SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, February 6 8, Oilfield Review

49 Contributors Babatunde Ajayi is a Senior Completions Engineer for Seneca Resources Corporation in Pittsburgh, Pennsylvania, USA. Previously, he was a field engineer and then a production stimulation and completions engineer for Schlumberger and a supply chain management program intern for Halliburton. He has a BS degree (Hons) in chemical engineering from the Boğaziçi University in Istanbul, Turkey, and an MS degree in petroleum engineering from Texas A&M University, College Station, USA. Françoise Allioli is a Principal Physicist and Development Physics Team Leader for LWD tools with Schlumberger. Since joining the company at the Schlumberger Riboud Product Center in Clamart, France, in 1995, she has worked on both wireline and LWD tool projects, including nuclear and resistivity tools. She has coauthored and presented papers at SPE, SPWLA and other conferences. Françoise holds a PhD degree in nuclear physics from Université Paris Diderot. Mark A. Andersen, Schlumberger Domain Head for Core Physics in Houston, joined the company in He spent 11 years as an Oilfield Review editor and executive editor before returning to his roots in core analysis to help build a new business for Schlumberger. He began his career in 1981 as a researcher in rock properties at Amoco Research Center in Tulsa. He subsequently spent several years in Stavanger, where he managed the Amoco Norway external research program and wrote Petroleum Research in North Sea Chalk. Mark is the author of many technical papers, including 23 articles for Oilfield Review. He earned a BS degree in engineering physics from the University of Oklahoma at Norman, USA, and MS and PhD degrees in physics from The Johns Hopkins University in Baltimore, Maryland, USA. Iroh Isaac Aso, based in Canonsburg, Pennsylvania, has been a Production and Stimulation Engineer with Schlumberger since Some of his responsibilities include completions optimization and production performance analysis of horizontal shale wells and hydraulic fracture design and evaluation. Prior to his career with Schlumberger, Iroh was a graduate research assistant at the Integrated Core Characterization Center, University of Oklahoma, Norman. He obtained a BS degree in electrical and electronics engineering from the University of Lagos, Nigeria, and an MS degree in petroleum engineering from the University of Oklahoma, Norman. Isaac Aviles is the Schlumberger Global Portfolio Manager for Multistage Stimulation and has been with the company since 2000; he joined the multistage stimulation team in 2010 and began his current assignment in Before moving to Sugar Land, Texas, he held field operations positions in Alaska, USA; Argentina and Colombia. He was also a field service manager in Mexico and spent three years performing technical support of worldwide field operations for fracturing and stimulation. Isaac received a BS degree in chemical engineering from Universidad de las Américas, Puebla, Mexico, and an MBA degree in finance from Rice University, Houston. Jason Baihly, based in Sugar Land, Texas, is the Schlumberger Subsurface Manager for the Eagleville Joint Venture Project in Texas for which he formulates and executes plans to optimize production of horizontal Eagle Ford oil wells. Previously, he was a multistage stimulation product line manager, was instrumental in merging Smith and Schlumberger R&D teams for a new business unit and created new R&D teams to focus on multistage stimulation hardware solutions. Prior to this role, and as the horizontal optimization and completion team leader within the Schlumberger Petro-Technical Services group, he led and was exposed to many integrated shale projects. Jason is a Principal Engineer with more than a dozen years of industry experience. He has a bachelor s degree in civil engineering from the South Dakota School of Mines and Technology in Rapid City, USA, and a master s degree in management in the oil and gas industry from Heriot-Watt University in Edinburgh, Scotland. Jacob Caplan is a Senior Completions Engineer for PDC Mountaineer LLC in Bridgeport, West Virginia, USA. He joined the company in 2010 and has focused on completions in the Marcellus Shale; he has also worked in the Utica Shale. He began his career with Schlumberger, where he was a field engineer in the Well Services segment in south Texas and the Texas Panhandle and then was engaged in starting the Haynesville Shale play as the field service manager for the stimulation department in Bossier City, Louisiana, USA. He also served as a sales engineer in Dallas. Jacob holds a BS degree in petroleum and natural gas engineering from West Virginia University, Morgantown. Brian D. Clark, a Senior Production and Completions Engineer with Schlumberger in Houston, has worked on a variety of projects in shale reservoirs. He started his career with Schlumberger in 1994 as a field engineer; he was involved in cementing and fracturing operations and performed laboratory work. Brian earned a BS degree in mechanical engineering from Clarkson University, Potsdam, New York, USA. Valentin Cretoiu, based at the Schlumberger Riboud Product Center, Clamart, France, is the Project Manager for the EcoScope 675* Measurement Improvements and NeoScope* projects with a focus on NeoScope commercialization. Valentin joined Schlumberger as an electronics software engineer in 1999 in Houston. In 2001, he moved to Clamart as an electrical engineer working on nuclear acquisition and control design. He has been project manager for various Wireline and Drilling & Measurements tools, recently focusing on the development of advanced measurements for the EcoScope* tool and the NeoScope service. He received an MS degree in electrical engineering from the Institut National des Sciences Appliquées de Lyon, France. Brent Duncan has been the Schlumberger Routine Core Analysis Supervisor in Houston since He began his career in the oil industry in 2001 as a hydrogeologist with Eagon & Associates, Inc. and has since worked as a hydrogeologist and soil technician, laboratory supervisor, geologist and project manager. Brent obtained a BS degree in geology from Olivet Nazarene University, Bourbonnais, Illinois, USA. Mike Evans is a Scientific Advisor for Schlumberger working with the EcoScope nuclear group, in Sugar Land, Texas. He joined Schlumberger in 1981 as a development engineer and worked on several wireline nuclear logging tools. In 1986, Mike joined the original Schlumberger LWD project development team and has been involved in the design of several nuclear tools. During his career, Mike has coauthored dozens of papers and holds 13 patents. He has a BS degree in physics, an MS degree in computer science and a PhD degree in physics, all from Texas A&M University, College Station. Utpal Ganguly is Global Stimulation Software Portfolio Manager for Schlumberger. Based in Houston, he directs the company s stimulation software development, defines technology strategy and conducts product marketing. He began his career with Schlumberger as a Well Services field engineer. With more than 18 years of experience in the oil field, he has held various roles in field operations, engineering and marketing. Utpal received an MS degree in petroleum engineering from the Norwegian Institute of Technology, Trondheim, and an MS degree in computer science from the University of Tulsa. He currently focuses on novel applications of software technologies enabling unconventional reservoir development and production. Dewey Gerdom is Vice President of Eastern Operations at Petroleum Development Corporation (PDC) and Chief Executive Officer of PDC Mountaineer LLC in Bridgeport, West Virginia. With 26 years of experience with both major and independent producers, he previously served as vice president of exploration, acquisitions and divestures at PDC. He joined the company in 2000 as project manager and was responsible for all exploration and land activities in the Rocky Mountain region in the US. Prior to that, he was the chief operating officer of Fruehauf Production Company. He also served as an asset manager at Chevron USA and Gulf Oil Company. Dewey holds a BS degree in business from the University of Wyoming, Laramie, USA. Roger Griffiths is the Petrophysics Domain Head for Schlumberger Drilling & Measurements in Petaling Jaya, Malaysia. He joined the company in 1987 as a wireline field engineer and has worked in Asia, the Middle East, Europe, Africa and North America in field, management, engineering and technical positions. He is a Technical Advisor in petrophysics and well placement, has written two books, coauthored numerous technical papers and holds several patents related to petrophysics and well placement. Roger obtained a degree (Hons) in mechanical engineering from The University of Melbourne, Victoria, Australia. Fabien Haranger is a Senior Physicist who began his career with Schlumberger in 2006 as a physicist working on technical support for the nuclear detectors and generators in the Drilling & Measurements (D&M) EcoScope, arcvision* and SlimPulse* tools. Based in Princeton, New Jersey, USA, his current project is to develop new nuclear detectors for D&M and Wireline tools. Fabien has a degree in engineering from the Ecole Nationale Supérieure d Ingénieurs de Caen, France, an MS degree in physics from Université Paris- Sud and a PhD degree in physics from Université de Caen Basse-Normandie, France. Summer

50 Xianwen Li is the Vice President of the Petroleum Technology Institute of PetroChina Changqing Oilfield Company, based in Xi an, Shaanxi, People s Republic of China. He is also a senior technical expert recognized by the China National Petroleum Corporation. He has been engaged in research and management work in oil and gas field development since His major interest is in production enhancement technologies. Xianwen received a master s degree in petroleum production engineering from Daqing Petroleum Institute and a PhD degree in materials science from Xi an Jiaotong University, both in the People s Republic of China. Guang Hua Liu is Cell Lead of the technical design cell for the Oil Development Segment of the CNPC- Dagang Oilfield Company in Tianjin, People s Republic of China. His responsibilities include well design, procedure and the introduction of new techniques. He began his career in 1999 as a junior engineer for the Dagang Oilfield Company and became an engineer and then senior engineer with the company. Guang Hua earned a BS degree in petroleum engineering from the Jianghan Petroleum Institute, Jingzhou, People s Republic of China. Hai Liu is currently Well Services General Manager for Schlumberger covering China, Japan, Korea and Taiwan; he is based in Beijing. In his 18-year career, he has worked in China, the Middle East and Texas and focused on production optimization and stimulation. He moved to a management role in early His main areas of expertise are in reservoir production and stimulation. He is recognized as Principal Engineer in Schlumberger Eureka Technical Careers and received Performed by Schlumberger Bronze, Silver and Chairman awards for his technical contributions. Before joining Schlumberger, he worked for the Production Technology Research Institute of PetroChina Xinjiang Oil Company from 1995 to Hai holds a BS degree in petroleum geology from Xi an Petroleum Institute, People s Republic of China. Yin Luo is Senior Technical Sales Engineer for Schlumberger China. He joined Schlumberger in 2006 after earning a master s degree in computer science from Peking University in Beijing. He has worked in Nigeria, Texas and Beijing and is currently based in Chengdu, Sichuan, People s Republic of China. His primary areas of expertise are in reservoir stimulation and software architecture. Yin is the recipient of two Performed by Schlumberger Bronze awards for his technical contributions. Marie-Laure Mauborgne is a Senior Physicist working on nuclear measurements for Drilling & Measurements at the Schlumberger Riboud Product Center in Clamart, France. Her career with Schlumberger began in 2006, when she worked on the EcoScope tool as a postdoctoral physicist. Marie-Laure earned a BS degree in nuclear engineering and an advanced degree in nuclear physics from Ecole Nationale Supérieure d Ingénieurs de Caen, France, and a PhD degree in nuclear physics from the University of Caen at the Institut de Recherche sur les Lois Fondamentales de l Univers, Saclay, France. Ryan McLin, who is a Senior Geologist, Petrology Manager and Diffuse Reflectance Infrared Fourier Transform Spectroscopy Product Champion, works at the Schlumberger Reservoir Laboratory in Houston. In his early career, which centered on the environmental sciences, he worked as a soils laboratory technician. In 2005, he moved to support the oilfield industry, when he began as a geologist at TerraTek* Services in Salt Lake City, Utah, USA. Ryan has BS and MS degrees in geology from New Mexico Institute of Mining and Technology, Socorro, USA. Doug Murray is LWD Domain Champion and Petrophysics Advisor for Schlumberger in Abu Dhabi, UAE. Since joining Schlumberger in 1982, he has held various positions in the field and in management, engineering and formation evaluation. His career includes assignments in Canada, Algeria, Nigeria, Saudi Arabia, Trinidad and Tobago, Argentina, Japan and China. Doug holds a BS degree in electrical engineering from Lakehead University, Thunder Bay, Ontario, Canada, and an MA degree in management from the University of Hull, Yorkshire, England. He is a member of the SPWLA, the SPE and SEG. Nicole Reichel is the LWD Petrophysics Associate Domain Champion and Senior Petrophysicist for Schlumberger in Stavanger, Norway. She joined Schlumberger in 2007 and worked as an LWD field engineer in Canada and Oman prior to her post at the Schlumberger Riboud Product Center in Clamart, France, where she was part of the LWD petrophysics interpretation group. In this function, she participated in the development of interpretation and answer products for LWD acquisition and provided global petrophysics field support. Nicole teaches courses in LWD petrophysics and has served as an SPWLA Distinguished Lecturer. She obtained BSc and MSc degrees in applied geosciences at the Montanuniversität in Leoben, Austria. Christian Stoller is a Schlumberger Scientific Advisor and Physics Métier Manager for the Princeton Technology Center, New Jersey, and for the Houston Formation Evaluation Center. Before joining Schlumberger, he worked on a variety of phenomena in nuclear, atomic and applied physics at the Nuclear Physics Laboratories of Eidgenössische Technische Hochschule (ETH) Zurich, Switzerland, and at Stanford University, California, USA. During more than 20 years with Schlumberger, he has been involved in the design and testing of most of the Schlumberger nuclear wireline tools for downhole applications. In 2005, he moved to the Princeton Technology Center, where he helped with the development of photomultipliers and detectors for downhole applications and the development and manufacturing of pulsed neutron generators. Most recently, he worked with the team that developed the first LWD tool that incorporates a pulsed neutron generator. Chris received MS and PhD degrees in physics from ETH Zurich. Ira J. Jay Terry, Jr. joined Schlumberger in 1987 as a Wireline field engineer in Shreveport, Louisiana, and has held field, sales and technical support positions in a variety of North American locations. Currently in Canonsburg, Pennsylvania, he has worked for the past 18 years as Senior Sales Engineer in the Charleston, West Virginia, and Pittsburgh, Pennsylvania, offices, amassing extensive technical expertise in the Marcellus, Utica and other Appalachian region reservoirs. Jay holds a BS degree in geological engineering from Louisiana State University, Baton Rouge, and a BS degree in geology from Centenary College of Louisiana, Shreveport. Kirby Walker has served in numerous operational, management and technical capacities for Schlumberger in south Texas, Alaska and the Appalachian basin, USA; Venezuela; and Russia in his 11-year career. He has concentrated on production engineering and stimulation techniques. Previously, as stimulation domain manager in Canonsburg, Pennsylvania, Kirby managed a group of completion engineers focused on designing and analyzing shale completions for the Northeast US. He is Chair of the SPE Pittsburgh Petroleum Section and has a BS degree in petroleum and natural gas engineering from Pennsylvania State University, University Park. George Waters is an Unconventional Completions Technical Manager for Schlumberger in Oklahoma City, Oklahoma. He is responsible for the geomechanical assessment and completion design of organic shale reservoirs under exploration and for initial reservoir development outside of North America. He has performed appraisals of hydraulic fracture dimensions and producibility via laboratory and field measurements on multiple reservoirs in more than 20 countries on six continents. George has been involved in the stimulation optimization of organic shales since 2000 and has extensive experience in shale basins throughout North America. He earned a BS degree in petroleum engineering from West Virginia University, Morgantown, an MS degree in environmental engineering from Oklahoma State University, Stillwater, and an MS degree in petroleum engineering from Institut Français du Petrole, France. George was a SPE Distinguished Lecturer on completion of organic shale reservoirs. Kevin Wutherich, based in Canonsburg, Pennsylvania, is the Stimulation Domain Expert for Schlumberger in the Northeast US. He is primarily engaged in optimizing completion practices in the Marcellus and Utica shales with a focus on integrating expertise from multiple domains. Previously, he was the stimulation domain manager for Schlumberger in Europe, where he engaged in numerous high-profile projects, including the first shale gas developments in Europe. Kevin holds a bachelor s degree in chemical engineering from the University of Waterloo, Ontario, Canada. Yonggao Xu recently became Deputy General Manager and Chief Engineer for Shaanxi Yanchang Petroleum (Group) Corporation Ltd. in Xi an, Shaanxi, People s Republic of China. Previously, he served as deputy chief engineer of PetroChina Changqing Oilfield Company. Yonggao received a bachelor s degree in petroleum production engineering from Jianghan Petroleum University, Jingzhou, Hubei, and a master s degree in reservoir and production engineering from Southwest Petroleum University, Chengdu, Sichuan, both in the People s Republic of China. Hua Yang is Deputy General Manager for PetroChina Changqing Oilfield Company in Xi an, Shaanxi, People s Republic of China, and in charge of oil and gas exploration and appraisal for reservoirs in the Ordos basin, People s Republic of China. He is also the Director of the National Engineering Laboratory for Low Permeability Oil and Gas Field Exploration and Development. He graduated from the Southwest Petroleum University in Nanchong, Sichuan, People s Republic of China. Hua has also been recognized as professoriate senior engineer by the People s Republic of China for his contribution to the discovery of the Jiyuan, Huaqing, Yulin and Sulige oil and gas reservoirs and holds a first prize and second prize for National Science and Technology Progress in the People s Republic of China. An asterisk (*) is used to denote a mark of Schlumberger. 48 Oilfield Review

51 NEW BOOKS Coming in Oilfield Review Diamondoid Molecules: With Applications in Biomedicine, Materials Science, Nanotechnology & Petroleum Science G. Ali Mansoori, Patricia Lopes Barros de Araujo and Elmo Silvano de Araujo World Scientific Publishing Company 27 Warren Street, Suite Hackensack, New Jersey USA pages. US$ ISBN: Diamondoids are stable, saturated ringed hydrocarbons with applications in fields ranging from chemistry to geology. This book looks at the history and fundamentals of diamondoid science and technology and examines the importance of the diamondoid molecule to the global scientific community. The authors explore both theoretical and experimental work with diamondoids. Contents: Molecular Structure and Chemistry of Diamondoids Diamondoids in Petroleum and Other Fossil Fuels Physical Properties of Diamondoids Diamondoids as Nanoscale Building Blocks Properties of Diamondoids Through Quantum Calculations Biomedical Applications of Diamondoids Diamondoids in Materials Science Glossary, Index Diamondoid Molecules is a thorough presentation of current and future applications of diamondoids.... Every chapter is excellently illustrated with plenty of clearly designed figures and graphs and well-organized tables.... [T]he book is an excellent introduction to theoretical and technological aspects behind diamondoids chemistry, their molecular structure and physical properties. Perišić O: Book Reviews, Journal of Nanophotonics 7, no. 1 (April 4, 2013): As someone who has worked in nanoscience for many years, I was gratified to see a book that links the dots in the different areas of science and technology. Diamondoid Molecules opens a door for newcomers, even in industry and government, and for seasoned researchers who want to explore new opportunities in other areas of the research. I strongly recommend the book to researchers and students in all the relevant fields. Zhang G: Book Review, Physics Today 66, no. 3 (March 2013): Maverick Genius: The Pioneering Odyssey of Freeman Dyson Phillip F. Schewe Thomas Dunne Books, an imprint of St. Martin s Press 175 Fifth Avenue New York, New York USA pages. US$ ISBN: Freeman Dyson, one of the foremost physicists of our time, has played many roles: mathematician, astronomer, biologist and engineer, among others. This biography explores his life and the impact his work has had on the world. Considered a genius by many, Dyson colleague and friend of J. Robert Oppenheimer, George F. Kennan and Richard Feynman also won the Templeton Prize for his writing on science and religion. Contents: Killing Time: Dyson Bombs Berlin ( ) Life Is a Blur: Dyson as Mathematician ( ) Ecumenical Councils: Dyson as Seminarian ( ) The Secret Signature of Things: Dyson as Artist ( ) Recessional: Dyson as Professor ( ) Nuclear Opera: Dyson and the Cold War ( ) Intrinsically Safe: Dyson as Engineer ( ) Space Traveler s Manifesto: Dyson as Rocketeer ( ) Civilized Behavior: Dyson Searches for Extraterrestrial Intelligence (Early 1960s) Nuclear Manifesto: Dyson as Diplomat (Early 1960s) On the Oregon Trail: Dyson as Pentagon Consultant (1960s 1970s) Success in Life: Dyson as Astronomer (Mid 1960s to Mid 1970s) Science and Sublime: Dyson as Essayist ( ) Nuclear Slavery: Dyson as Abolitionist (1980s) The Arc of Life: Dyson as Biologist (1980s and 1990s) God and Man at Princeton: Dyson as Preacher ( ) Splintering the Species: Dyson as Heretic ( ) Long-Term Thinking: Dyson as Storyteller (Recent Years) A Many-Colored Glass Notes, Index A fascinating account of an iconoclastic scientific polymath and the lively collection of scientists who were his friends. Book Review, Kirkus (December 16, 2012), phillip-f-schewe/maverick-genius/ (accessed April 2, 2012). Discussion of Dyson s opposition to the Superconducting Super Collider and to the Hubble Space Telescope... would... have brought a sharper, more critical focus on Dyson s contrarian personality, and made the end of Schewe s book read less like an extended flattering magazine portrait of a prophet. Still, Maverick Genius provides a vivid and enjoyable sketch of one of the most prominent scientific rebels of our day. Crease RP: Rebel Without a Pause, Nature 494, no (February 21, 2013): 311. Despite some strange digressions, Dr. Schewe knows the physics, and he gained access to colleagues, family everyone except Freeman Dyson, who politely declined, saying, Maybe in 50 years you ll be able to tell whether I did anything important. Hoffman J: Growing Wings and Rising Oceans, The New York Times (February 25, 2013), growing-wings-and-rising-oceans.html?_r=0 (accessed April 2, 2013). Mudrocks. Until the late 20th century, mudrocks including shales were largely ignored except for their source rock potential and capacity to form seals, trapping hydrocarbon beneath them. Research is now revealing that mudrocks are as interesting and complicated as sandstones and carbonates. They form under similar hydrodynamic flow regimes as sandstones and carbonates, and their characteristics are predictable using the principles of sequence stratigraphy. Consequently, techniques used to characterize sandstone and carbonate reservoirs may be adapted for characterizing mudrock resources. Underreaming. To enlarge the wellbore diameter below a casing shoe or other restriction that might limit the maximum diameter of a reaming tool, operators employ underreamers. These tools have been used for decades with varying degrees of success. Advanced underreamer designs, coupled with innovative activation and deactivation techniques, are helping operators drill deep or extended-reach wells with greater efficiency. Measuring Casing Corrosion. The bane of all things metal is corrosion. In the upstream industry, tubulars, designed to protect the well and the environment, are continuously exposed to naturally occurring elements and chemicals that aggressively promote corrosion. Operators can use monitoring to determine the extent and location of corrosion in time to manage it. By implementing advanced downhole corrosion monitoring techniques and tools, companies are protecting their investments and the environment. Geomagnetic Referencing. Accurate positioning of well trajectories is required to optimize hydrocarbon recovery, determine where each well is relative to the reservoir and avoid collisions with other wells. Advances in geomagnetic referencing now allow companies to use real-time data from accelerometers, magnetometers and gyroscopes to land horizontal wells according to plan. This article examines the science of well guidance, focusing on modern magnetic surveying techniques. Summer

52 The Great Fossil Enigma: The Search for the Conodont Animal Simon J. Knell Indiana University Press Office of Scholarly Publishing Herman B Wells Library East 10th Street Bloomington, Indiana USA pages. US$ ISBN: Through an exploration of 150 years of scientific thinking, studies, misconceptions and misunderstanding of the conodont, the author reveals an emerging consensus among scientists about this creature s place in the fossil records. Contents: The Road to El Dorado A Beacon in the Blackness The Animal with Three Heads Another Fine Mess Outlaws Spring Diary of a Fossil Fruit Fly Fears of Civil War The Promised Land The Witness The Beast of Bear Gulch The Invention of Life El Dorado Over the Mountains of the Moon Afterword: The Progress of Tiny Things Notes, Index... Knell uses the history of conodont research to show how the ideas and actions of scientists are influenced not merely by the clinical interpretation of the evidence but also by their imagination.... If you want [an] entertaining and interesting account of the discovery of knowledge through the analytical, political, and idiosyncratic activities of researchers, The Great Fossil Engima will serve you well. Donoghue P: Fascinating Little Whatzits, Science 340, no (May 17, 2013): 813. The Earthquake Observers: Disaster Science from Lisbon to Richter Deborah R. Coen University of Chicago Press 1427 East 60th Street Chicago, Illinois USA pages. US$ ISBN: Eyewitness accounts of earthquakes once knitted together the stories of seismic devastation. The author explores this citizen science, which was abandoned with the introduction of the Richter scale, through commentary from observers such as Charles Darwin, Mark Twain, Ernst Mach and John Muir as well as from ordinary citizens, and discusses how it developed into a field of scientific research. The book tells the history of this dialogue between scientists and citizens, which has since been revived in the 21st century. Contents: The Human Seismograph The Planet in the Village: Comrie, Scotland, News of the Apocalypse The Tongues of Seismology: Switzerland, Geographies of Hazard The Moment of Danger Fault Lines and Borderlands: Imperial Austria, What Is the Earth? The Youngest Land: California, A True Measure of Violence: California, Conclusion, Notes, Bibliography, Index... The author demonstrates how the approach, and even the goals, of earthquake science are intertwined with and influenced by their historical and political context. The book is well written, the documentation meticulous, and the depth of research impressive.... The chronology of attempts to recruit amateur earthquake observers that Coen assembles to make her case is fascinating, and on that basis alone the book is worth reading. Crowd-sourced science has rarely been so thrilling. As Deborah R. Coen reveals, the rumbustious history of seismology began with roving scientists gathering locals accounts of shocks, shudders and thumps.... Coen argues for a hybridized disaster science, factoring in such responses from human seismographs with geology and instrumental data. Books in Brief, Nature 491, no. 525 (November 21, 2012), nature/journal/v491/n7425/full/491525a.html (accessed July 1, 2013). Fundamentals of Condensed Matter and Crystalline Physics David L. Sidebottom Cambridge University Press 32 Avenue of the Americas New York, New York USA pages. US$ ISBN: Intended for undergraduates, this textbook combines solid-state physics with condensed matter physics. The author takes a holistic approach to condensed matter physics by integrating the crystalline and amorphous states and relating areas of condensed matter such as electronic properties of solids and statistical mechanics of hard and soft materials to one another. Contents: Part I. Structure: Crystal Structure; Amorphous Structure; Bonds and Cohesion; Magnetic Structure Part II. Scattering: Scattering Theory; Scattering by Crystals; Scattering by Amorphous Matter; Self-Similar Structures and Liquid Crystals Part III. Dynamics: Liquid Dynamics; Crystal Vibrations; Thermal Properties; Electrons: The Free Electron Model; Electrons: Band Theory; Bulk Dynamics and Response Part IV. Transitions: Introduction to Phase Transitions; Percolation Theory; Mean Field Theory and Renormalization; Superconductivity Appendices, Index The author... blends the condensed-matter topics in a manner that blurs the distinction between soft and hard parts. That s a novel idea. Potentially, this book will modernize the undergraduate condensed-matter physics course by introducing more of the soft-matter component.... Since the book covers such a wide variety of topics, the level of detail suffers a bit. Overall, though, [the book] succeeds at covering many fundamental concepts of solid-state and softmatter physics and at combining them in an approachable manner. Smalyukh I: An Introduction that Blends Hard and Soft Condensed Matter, Physics Today 66, no. 5 (May 2013): 49. Beroza GC: Did You Feel It?, Science 340, no (April 19, 2013): Oilfield Review

53 DEFINING HYDRAULIC FRACTURING Elements of Hydraulic Fracturing Richard Nolen-Hoeksema Editor P breakdown Preopening P closure A well s ability to produce hydrocarbons or receive injection fluids is limited by the reservoir s natural permeability and near-wellbore changes resulting from drilling or other operations. Hydraulic fracturing, also known as hydraulic stimulation, improves hydrocarbon flow by creating fractures in the formation that connect the reservoir and wellbore. A hydraulic fracture is a pressure-induced fracture caused by injecting fluid into a target rock formation. Fluid is pumped into the formation at pressures that exceed the fracture pressure the pressure at which rocks break. To access a zone for stimulation, engineers perforate the casing across the interval and use retrievable plugs to isolate the interval from other open zones. This interval is then pressurized to the formation breakdown pressure, or fracture initiation pressure, the point at which the rock breaks and a fracture is created. Fracture Fracture σ Hmin σ Hmax > In situ stresses and hydraulic fracture propagation. The three principal compressive stresses (red arrows) are a vertical stress (σ V ) and a maximum and minimum horizontal stress (σ Hmax and σ Hmin ). Hydraulic fractures open in the direction of the least principal stress and propagate in the plane of the greatest and intermediate stresses. Oilfield Review Summer 2013: 25, no. 2. Copyright 2013 Schlumberger. For help in preparation of this article, thanks to Jerome Maniere, Mexico City. σ v Bottomhole pressure, P Breakdown Time Reopening After closure P initial The Physics of Fracturing The size and orientation of a fracture, and the magnitude of the pressure needed to create it, are dictated by the formation s in situ stress field. This stress field may be defined by three principal compressive stresses, which are oriented perpendicular to each other (below). The magnitudes and orientations of these three principal stresses are determined by the tectonic regime in the region and by depth, pore pressure and rock properties, which determine how stress is transmitted and distributed among formations. In situ stresses control the orientation and propagation direction of hydraulic fractures. Hydraulic fractures are tensile fractures, and they open in the direction of least resistance. If the maximum principal compressive stress is the overburden stress, then the fractures are vertical, propagating parallel to the maximum horizontal stress when the fracturing pressure exceeds the minimum horizontal stress. The three principal stresses increase with depth. The rate of increase with depth defines the vertical gradient. The principal vertical stress, commonly called the overburden stress, is caused by the weight of rock overlying a measurement point. Its vertical gradient is known as the lithostatic gradient. The minimum and maximum horizontal stresses are the other two principal stresses. Their vertical gradients, which vary widely by basin and lithology, are controlled by local and regional stresses, mainly through tectonics. The weight of the fluid above a measurement point in normally pressured basins creates in situ pore pressure. The vertical gradient of pore pressure is the hydrostatic gradient. However, pore pressures within a basin may be less than or greater than normal pressures and are designated as underpressured or overpressured, respectively. Beyond Fracture Initiation At the surface, a sudden drop in pressure indicates fracture initiation, as the fluid flows into the fractured formation. To break the rock in the target interval, the fracture initiation pressure must exceed the sum of the minimum principal stress plus the tensile strength of the rock. To find the fracture closure pressure, engineers allow the pressure to subside until it indicates that the fracture has closed again (above). Engineers find the fracture reopening pressure by pressurizing the zone until a leveling of pressure indicates the fracture has reopened. The closure and reopening pressures are controlled by the minimum principal compressive stress. Pumping rate > Fracture pressures. During a stimulation treatment, engineers pump fluid into the targeted stimulation zone at a prescribed rate (blue polygons), and pressure (red line) builds to a peak at the breakdown pressure, then it drops, indicating the rock around the well has failed. Pumping stops and pressure decreases to below the closure pressure. During a second pumping cycle, the fracture opens again at its reopening pressure, which is higher than the closure pressure. After pumping, the fracture closes and the pressure subsides. The initial pore pressure is the ambient pressure in the reservoir zone. Summer

54 DEFINING HYDRAULIC FRACTURING Therefore, induced downhole pressures must exceed the minimum principal stress to extend fracture length. After performing fracture initiation, engineers pressurize the zone for the planned stimulation treatment. During this treatment, the zone is pressurized to the fracture propagation pressure, which is greater than the fracture closure pressure. Their difference is the net pressure, which represents the sum of the frictional pressure drop and the fracture-tip resistance to propagation. Keeping Fractures Open The net pressure drives fracture growth and forces the walls of the fracture apart, creating a width sufficient to allow the entry of the fracturing slurry composed of fluid and proppant solids that hold the fracture open after pumping stops. Once the pumping is halted, the pressures inside a fracture subside as the fluids either flow back into the well or leak away into the reservoir rock. This drop in pressure allows the fracture to close again. To ensure that fractures stay open, engineers inject additional materials, depending on lithology. In sandstone or shale formations, they inject proppant sand or specially engineered particles to hold fractures open (below). In carbonate formations, they pump acid into the fractures to etch the formation, creating artificial roughness. The stimulation treatment ends when the engineers have completed their planned pumping schedule or when a sudden rise in pressure indicates that a screenout has taken place. A screenout is a blockage caused by bridging accumulation, clumping or lodging of the proppant across the fracture width that restricts fluid flow into the hydraulic fracture. Controlling Hydraulic Stimulation Stimulation engineers maintain a constant rate of fluid injection. The volume injected includes the additional volume created during fracturing and the fluid loss to the formation from leakoff through the permeable wall of the fracture. However, the rate of fluid loss at the growing fracture tip is extremely high. Therefore, it is not possible to initiate a fracture with proppant in the fracturing fluid because the high fluid loss would cause the proppant at the fracture tip to reach the consistency of a dry solid, causing bridging and screenout conditions. Consequently, some volume of clean fluid a pad must be pumped before any proppant is pumped. 1 mm 1 mm 1 mm > Proppant. Several proppant types, including high-strength bauxite (left), resin-coated silica (middle) and lightweight ceramic (right), are pumped into fractures to maintain open fractures for enhanced hydrocarbon production. Horizontal departure, ft ,200 1,600 2,000 2,400 2,800 3,200 3,600 > Microseismic monitoring of multiple-stage hydraulic stimulation. Analysis of microseismic data provides operators with information about the effectiveness of hydraulic stimulation treatments. In this example, five fracturing stages were pumped into the treating well (red line) while being monitored from a second well (green line with location of geophones shown as green disks). Microseismic events during stages 1 through 5 are indicated by the yellow, blue, red, cyan and magenta dots, respectively. Real-time microseismic monitoring may allow completion engineers to adjust operations during execution to improve the effectiveness of the treatment. When designing a hydraulic fracture treatment, engineers must establish the leakoff rate and volume of the pad in relation to the timing of slurry and proppant injection so that when the fracture reaches its designed length, height and width, the first particle of proppant reaches the fracture tip. To design a hydraulic fracturing job, engineers must understand how pumping rate and stimulation fluid properties affect hydraulic fracture geometry and propagation within the in situ stress field to achieve a targeted propped fracture length. Operators design stimulation treatments to control fracture propagation and to ensure that the hydraulic fracture stays within the reservoir and does not grow into the adjacent formation. To reduce this risk, operators monitor fracture growth. As fracturing fluid forces the rock to crack and fractures grow, small fragments of rock break, causing tiny seismic emissions, called microseisms. Geophysicists are able to locate these microseisms in the subsurface (above). Laboratory and field data have shown that these microseisms track growing fractures. Armed with the knowledge of the direction of fracture growth, engineers may be able to take action to steer the fracture into preferred zones or to halt the treatment before the fracture grows out of the intended zone. The propagation of hydraulic fractures obeys the laws of physics. In situ stresses control the pressure and direction of fracture initiation and growth. Engineers carefully monitor the stimulation process to ensure it goes safely and as planned. X,200 X,600 Y,000 Y,400 Y,800 Z,200 Depth, ft 52 Oilfield Review