The Impact of sandstone strength s behavior as a result of temperature changes in Water Injectors

Transcription

1 SPE The Impact of sandstone strength s behavior as a result of temperature changes in Water Injectors J. Tovar, Innovative Engineering System Global, W. Navarro, Pluspetrol Norte, S.A. Copyright 2008, Society of Petroleum Engineers This paper was prepared for presentation at the 2008 SPE European Petroleum Conference held in Rome, Italy, 9 13 June This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box , Richardson, Texas U.S.A., fax Abstract In water injection programs it is accepted that the temperature at which water arrives at the formation will cause the rock to shrink resulting in a reduction in the minimum horizontal stress and possibly a fracture of the rock. This effect is known as TIF or Thermally Induced Fracturing. However, little research has been carried out as to how the cooling of the rock by the injection water affect the formation mechanical properties. This paper presents work carried out to determine the effect of temperature changes on the strength of sandstone reservoirs used for water injection. An effort was initiated by Pluspetrol Norte, S.A. as part of their produced water disposal programs to develop an understanding as to how various sandstone reservoirs used for re-injection respond to temperature changes and what implications can it have for their operations. Pluspetrol production comes from two(2) main blocks in Northern Peru, Total water production has reached over bwpd of which over bwpd are currently being reinjected throughout both blocks. A large core testing program was designed and completed to measure unconfined rock strength in a number of sandstone cores available from both blocks. The cores were heated and cooled and their strength measured to identify possible changes in strength magnitude. The results obtained were analysed and compared with those available in a large geomechanical model of the blocks developed earlier known as the Custodian (1), a new predictive model was developed using the results obtained. A number of simulations were carried out using a TIF model to compare the measured field data during water re-injection with the predictions from the TIF model using the new strength model. These results are presented in detail and its application to other geomechanical problems such as sand production in water injectors is also discussed. Introduction A reduction in the minimum horizontal stress as a result of cooling the formation is an effect well known in our industry. This reduction in magnitude of σ h can result in the fracturing of the sand and is known as Thermally Induced Fracturing TIF. The effect of temperature changes on the mechanical properties of the rock is not very well documented (2,3,4), it can affect significantly the efficiency of the water injection programs and the overall response of the formation to changing mechanical loads induced by the change of temperature. Figure 1 illustrates the change in the magnitude of the minimum horizontal stress as a result of the cooling effect for a North Sea sandstone reservoir. Other effects such as formation failure and sand production in addition to fracturing can be the result of cooling of the sand face by the injection water. The core testing program developed was focused on two(2) main objectives: detailed unconfined compressive strength - UCS characterization of the sandstone formations and identification of the temperature contribution to rock strength at in-situ conditions. Formation strength determination continues to be a challenge as a result of the various methodologies and correlations used. A number of criterias are currently applied that utilize a combination of dynamic and static conditions to determine formation strength. In our case, the selected measuring method was an indirect and non-destructive method known as the Schmidt Hammer method. By being non-destructive an unlimited number of measurements can be taken, the results publishedin the literature (5) indicate that the measurement is very representative of the character and heterogeneity of the rock but its strength magnitude is underestimated as other conventional UCS measuring methods. Figure 2 illustrates a log derived strength versus the data obtained using the nondestructive method. A model that takes into account the contribution of temperature to unconfined rock strength was developed from the data and incorporated into existing in-situ strength prediction models currently used in the industry. An analytical model (6) was used for the determination of the TIF dimensions and occurrence applying the results obtained from the strength testing program. The following paragraphs describe in detail the testing program, the development of the models and the applications of the new methodology to water injection projects. Core testing program The Schmidt Hammer method is an old method used in the geological and concrete industry to measure strength.

2 2 J. Tovar, W. Navarro, SPE samples were selected from sandstone cores available from both blocks, 1AB and block 8. They were selected based on their petrophysical properties (shale content, density, porosity and sonic response). Other conditions such as physical state and geometry of the samples were key to the successful taking of the measurements. Strength for each sample was measured at ambient temperature prior to heating them in an oven to a preset temperature. Measurements were again taken and recorded at temperature for each sample and then again at ambient temperature after the samples were cooled. Figures 3 and 4 illustrate the measuring instrument and the state of the cores. The results were analysed to establish a relationship between the changes of strength observed and the petrophysical properties of the sandstones. The data showed a clear relationship between strength and two particular properties, mean grain size D 50 and V shale or the volume of third party materials contained in the matrix. The changes of strength as a function of temperature follows well the current geomechannical thinking that defines when the source of strength is given by the grain to grain contact or by the material in the matrix. Figure 5 illustrates the measured data as a function of V Shale. Development of the analytical model Current industry models concerning rock strength take into account in various forms the different effects that influence the behavior of the rock under in-situ conditions. The facts are that under in-situ conditions most analytical models use the strength of the system rock-wellbore and not rock strength only. Therefore, in water injectors the same effects are present and must be taken into consideration, these are: Confinement Wellbore geometry Temperature changes The first two(2) are taken into consideration by most models mainly through the use of the tri-axial or thick walled cylinder test data however, the temperature effect has never been considered before for rock strength computations. Temperature contribution to in-situ strength The first step was to develop a model that accurately reflects the contribution of temperature to the in-situ rock strength. A heat transfer through granular material model has been used to quantify the change in strength as a function of temperature for a number of materials. The analysis carried out indicated that there is a close relationship between the mineral composition of a sandstone reservoir and its strength according to the changes in temperature imposed by the injection of water. Two(2) clear trends were observed from the measured results; one where the strength magnitude increases with an increase in temperature and another one where it decreases. The increase is observed in rocks were the source of strength is either grain supported or fully matrix supported. The reduction of strength is noted where the support mechanism is neither grain nor matrix one but the formation shows a transition between both mechanism. The analysis indicates that this occurs because for both the grain supported and the fully developed matrix supported rock strength the expansion caused by the heating/cooling of the samples also results in an internal confinement effect that increases the strength with temperature. On the other hand, it is our view that the decrease of strength magnitude for the transition zone is the result of an uneven expansion of the mineral components. The various mineral components of the matrix tend to expand at different rates and the effect of confinement is not uniform resulting in internal stresses that generate the reduction of strength. Based on the model used these can be explained in the variation of the coefficient of thermal expansion for each of the three(3) zones described. More detailed work is required to investigate this effect. Figure 6 illustrates the changes in formation strength as a function of temperature for different mineral composition. Proposed rock strength model Once the temperature effect can be quantified then it is possible to integrate it in one of the currently used strength models. Because for production and injection wells the strength of the rock is affected by other parameters, the proposed model that integrates the temperature effect is strictly representative for unconfined rock strength. Further calibration and corrections will need to be made depending on the correlations used. It is current practice to choose from a number of rock strength models (7) that relate one or many rock petrophysical properties to strength. The general model used in this case is one that links rock porosity to its strength. Appendix A presents a model that integrates the temperature contribution quantified from this work. Application of the results Forestal field The results obtained were applied to an existing water injection program being implemented in the Forestal field, Northern Peru in block 1AB and at 98 Km from the main base in Andoas. The Vivian is the main reservoir found at ~9100 feet, Vivian is composed of up to five(5) high permeability and high porosity sandstones in Forestal and has a net thickness of ~ 36 feet. The production mechanism is water drive and the field has experienced a depletion of ~ 600 psi in over 20 years of production. Field location and other reservoir data is presented in appendix B. 17 wells have been drilled in the field of which nine(9) are producers. The wells produce up to BFPD with electrical submersible pumps and water production have reached 97.1% of total production. Forestal 04 was drilled in the flank of the structure and water breakthrough developed very rapidly and had to be abandoned. The well was converted to a water injector and re-perforated through the Vivian A3, A4 and A2 sands as can be seen in figure 7. Pressure and temperature data was obtained from a step rate test in which injection water at two(2) different temperatures was used, the results are illustrated in figures 8 and 9 and 10 for temperatures higher than 190 F and temperatures lower than 165 F. Using this experience gained in Forestal, two(2) specific applications have been selected to illustrate

3 SPE The Impact of sandstone strength s behavior as a result of temperature changes in Water Injectors 3 the use of the results of this work. The first one is the determination of the TIF effect and its characteristics, the second application is for the identification of sand production problems in water injection wells. Water injection application TIF The generation of thermally induced fractures as a result of the cooling effect in water injection wells is a well known phenomenom. In our case we use an analytical model described in reference 6 to determine the occurrence of TIF in Forestal and to determine the conditions/characteristics at which the fracture is generated. Simulations were run using the proposed rock strength model and the results compared with strength models that do not account for temperature changes as illustrated in figure 11. As can be seen from figure 11 the change in minimum horizontal stress is even larger when the temperature effect on the strength is taken into consideration but not across the whole sand. These results clearly illustrates the influence of matrix s mineralogy as the magnitude of the reduction in minimum horizontal stress is not the same throughout the interval. The other curve in figure 10 represents the same sand but simulating that its mineral composition shows a larger shale content. As can be seen in this case the reduction in minimum horizontal stress is much larger and through the whole interval. In the same manner the simulations indicate that the fractures generated might be longer than initially predicted by previous models depending on the type of sandstone and its mineral composition. The reduction of strength as the rock is cooled will allow much rapid fracture growth for the same applied pressure as the strength is lower than originally estimated. The repercutions of these findings are that for this type of sandstone where the strength source is neither grain nor matrix supported the surface pressure requirements hence equipment rating might be lower than anticipated. The injection test carried out in Forestal 4 clearly indicated that the fracture occurs at lower rate anda surface pressure as illustrated in figure 10. Sand production prediction application Water injection wells might not appear to be sand producers. However, it is well known that water injectors are the worst sand producers as it is not possible to transport or remove the produced sand. Two(2) key events must occur for an injector to produce sand these are: rock failure as a result of the water hammer effect and then flow from the reservoir into the wellbore. This second condition is perceived to be impossible to achieve as the direction of flow does not allows fluids into the wellbore but from the wellbore and into the reservoir. This process has been well documented (8) for injection wells in the Norwegian side of the North Sea and it occurs during well shut-in. As fluid level and pressures stabilizes across the reservoir during the stoppage of water injection, flow tends to ocurr between layers or sections of the reservoir due to the time it takes for the wellbore conditions to balance. Factors such as anisotropy of permeability, perforation design and pressure dissipation can contribute to cross flow. Perhaps one of the most typical example of sand production in water injectors is during cleanup of the wells. Flow back is an accepted and effective practice of cleaning back injectors. The well is produced for sometime until fines and any potential plugging material is flushed back cleaning the well. In order to induce flow a drawdown pressure must be applied to the formation to flow into the wellbore and produce the cleaning effect desired. Sand production in the case of flowing the well back for cleaning up can be illustrated using the rock strength model developed. The results are presented in terms of drawdown pressures as the well is starting to clean up. When the well is cooler is when the lower drawdown must be applied in order to avoid sanding. A much larger decrease in strength will ocurr as a result of cooling leading to the first condition required to induce sanding(i.e. rock failure). From then on any operational event that forces a shutdown in water injection can help to meet the second condition(flow) which will drag the failed material into the wellbore. Figure 12 illustrates the changes in critical drawdown pressures. Conclusions The work carried out allows to conclude that temperature has a significant effect on the strength of sandstone reservoirs, it can either increase or decrease its magnitude depending on the petrophysical properties of the matrix. An extensive core testing program was developed to quantify the effects of temperature changes on rock strength for a number of sandstone reservoirs that Pluspetrol Norte utilises for water injection in blocks 1AB and 8.. Unconfined rock strength was measured using a nondestructive method, measurements on 59 core sampels were taken from 8 fields located in both blocks. Analysis of the data indicates that the changes in strength as a result of changes in temperature are related to the mineral composition of the matrix. The data from the test correlates well with the existing practice of classifying the strength mechanism and source as grain or matrix supported mechanisms. Three(3) zones are identified from the sandstones tested; a grain dominated one, a transition zone and a full matrix supported zone where the non-quartz components exceed ~30 % of the matrix volume. The increasing strength trend appears to occur in sandstones where the strength source is from grain to grain or fully matrix supported. On the other hand the decrease in rock strength is observed in the transition zone. The explanation proposed for these effects is that for the fully matrix supported or for the grain to grain supported strength the matrix expands with temperature in a uniform manner which creates a localized inner confinement effect which increases the strength. The decreasing strength that was measured in the transition zone appears to be caused by non-uniform expansion of the matrix structure which creates inter-matrix stress differentials which tend to reduce the strength. More work is required to investigate this phenomenom.

4 4 J. Tovar, W. Navarro, SPE A model to represent the contribution of temperature to rock strength was developed. It links the changes in rock strength to the thermal expansion coefficient and the temperature change. Integration of the new model into wellbore strength models was carried out and the results evaluated for two particular applications in water injectors; sand production and the determination of thermally induced fracturing. For thermally induced fracturing the simulations carried out using the new model resulted in TIF occurring at much lower pressures than those predicted without the temperature effect particularly for sandstones within the transition zone. For sand production prediction the use of the new model indicates that sanding might ocurr in water injectors earlier than originally predicted, this means that the utilization of sand control methods might be required earlier than originally planned. It must be noted that the calculations presented in this paper do not account for the water hammer effect which if present will cause failure at much lower pressures. Other applications such as wellbore stability can also benefit from the new model as in some drilling environments such as deep water the mud has a cooling effect on the rock which might lead to a reduction of its strength. This might contribute to events such as partial or total loss circulation which can have major consecuences on the well construction process including in some cases productivity impairment and the potential loss of the well. Acknowledgements We would like to thank Pluspetrol Norte S.A.and Innovative Engineering Systems for permission to publish this paper. To Mr. F. Moreno and R.Mancedo for carrying out the laboratory work and data preparation for the development of the models and the publication. Nomenclature σ h Minimum horizontal stress (psi) E Young s modulus (psi) T Temperature ( R) C Constant UCS Unconfined compressive strength (psi) TIF Thermally induced fracturing V Shale Shale volume (%) ρ Formation density (gr/cc) φ Porosity (%) Δ Differential 3. Akana K.: Determination of the impact of changes in thermal gradients on the mechanical properties of sandstones, MSc. Thesis, Friedman M. et al.: Mechanical properties of Rocks at High temperatures and pressures, DE Taylor P.G. and Appleby R.: Integrating Quantitative and Qualitative Rock Strength Data in Sanding Prediction Studies: An application of the Schmidt Hammer Method, SPE/IADC paper presented at the Indian Drilling Technology Conference and Exhibitiion, Mumbai, India, October Detienne J. et al.: Thermally Induced Fractures: A filed proven analytical model, SPE number presented at the Annual Technical Conference and Exhibition, Dallas, USA, Sarda J. et al.: Use of Porosity as a Strength Indicator for Sand Production Evaluation, SPE paper presented at the Annual Technical Conference and Exhibition, Houston, Texas, Santarelli F.: Sand production in water injectors. How bad is it, SPE paper 48678, Appendix A Proposed Strength model Strength ~ φ + ECT Equation A-1 Appendix B Field locaction and Reservoir data San Forestal Jacinto l Ecuador Carme Sh Ecuado Bartr n NE r Perú a Per ú Huayur Shiviyac Tigr i u Capahuari N Jibar e N Jibarit o Dorissa Capahuari a o Pi S Tamb pel o ine Valenci - Nva. a Esperanza 50 Km Chambir a Block 1AB 1AB Pavayac u Capiron a Corrientes s Block 8 8 References 1. Sorrentino Y. et al.: Effective use of Geomechanical Data for Resolving Wellbore Stability Problems in Blocks 1AB and 8, Northern Peru, SPE paper presented at the Latin American Petroleum Conference held in Buenos Aires, Argentina, Chandong C.: Empirical Rock Strength Logging in Boreholes Penetrating Sedimentary Formations, Geophysical Exploration (2004) Vol 7, No. 3, 174. Pipelin Pipeline e Yanayacu u Figure B.1 Location Map - Forestal field

5 SPE The Impact of sandstone strength s behavior as a result of temperature changes in Water Injectors 5 PARAMETER VALUE OBSERVATIONS Block 1AB See map above Depth [feet] 9847 Top of Vivian Number of intervals 2 A4, A3 sands Permeability [D] ~ 2 [0.4 3] Porosity [%] - - Thickness [feet] ~30 Net sands BHT [ F] 244 Static Reservoir press [psi] 3913 Original, 1974 Reservoir press [ psi] ~3300 Current, 2002 Fluid density [API] - Production Q [BFPD] - [ ] per well WOR [%] 97 < 3 months of production Production method - ESPs Table B-1 Reservoir and well data Forestal 4 Pressure (psi) Fig. 2. Measured data versus Log derived strength Depth (ft) Thermal Stress Impact Well Pressure Pore Pressure Original Min H Stress Fig. 1. Reduction of the σ h as a result of water cooling North Sea sandstone Fig.3 - Schmidt Hammer test unit

6 6 J. Tovar, W. Navarro, SPE Strength (psi) Figure 4 Vivian sandstone core material Depth (mts) Base strength!"=#50 $!"=#20 $ Figure 5 Increase/decrease in UCS as a function of mineral content Figure 6 Formation strength changes as a function of delta T

7 SPE The Impact of sandstone strength s behavior as a result of temperature changes in Water Injectors 7 Figure 7 - Vivian sandstone Re-perforated interval for water injection Figure 8 Water injection test results for T > 190 F Forestal 4

8 8 J. Tovar, W. Navarro, SPE Figure 9 Water injection test for water temperature < 165 F Figure 10 Changes in rate and surface pressure with different water temperature

9 SPE The Impact of sandstone strength s behavior as a result of temperature changes in Water Injectors 9 Horizontal stress (psi) Drawdown pressure (psi) Depth (ft) Depth (mts) Initial mimimum horizontal stress Original model New model prediction New model, change in Vshale effect 9870 CDP base!"=#50 $!"=#20 $ Figure 11 - Changes in σ h with and without the effect of temperature on rock strength Figure 12 CDP maximum during well flow back with and without temperature effect