Middle East carbonate reservoirs. South America and Caribbean. North America. Asia. Australasia

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3 the inside story A large proportion of the oil and gas in the Middle East is contained in carbonate reservoirs, including several supergiant fields. The traditional techniques for developing and assessing clastic reservoirs are less effective or even counter-productive in carbonate rocks. Geoscientists need a clear understanding of their reservoirs because predictions about future behaviour can only be based on current performance and an understanding of the mechanisms controlling that performance. In this article, Roy Nurmi and Eric Standen investigate the new nuclear magnetic resonance (NMR) technology, and the fresh insights it offers into the complexities of carbonate reservoirs and pore systems. The logging of borehole NMR in Kuwait has provided a wealth of new data on the geological and production potential of complex carbonate reservoirs. With important contributions from: Ahmed A Latif and Dogan Sungur of Kuwait Oil Company, along with Ian Stockden of British Petroleum and Chanh Cao Minh of Schlumberger Middle East, whose SPE paper for the recent Middle East Oil Show (MEOS) in Bahrain is featured in this article.

4 Middle East carbonate reservoirs contain around 50% of the world s oil (figure 2.1). As reserves in other regions are depleted, this proportion will increase and the Middle East giants will come to dominate the global oil and gas supply in the 21st century (see 2020 vision, Middle East Well Evaluation Review, issue 14). Clearly, the industry must evaluate these reservoirs accurately. However, characterizing carbonate reservoir sequences using borehole logs presents a special challenge. Existing systems for log interpretation are based on clastic shaly sand facies and are of limited use in carbonates, where the pore structure is usually much more complex than in clastic rocks (figure 2.2). These fundamental problems hamper attempts to develop successful production strategies in carbonate reservoirs. Evaluating hydrocarbon saturation from measured electrical conductivity in carbonate rocks is one of the most fundamental problems. In carbonate reservoirs it is fairly common for dry oil to be produced from zones where borehole logs show high water saturations. Several new techniques are being introduced to overcome this type of problem. Of these, the Combinable Magnetic Resonance (CMR*) tool has provided the most dramatic improvements by distinguishing effective from non-effective pore space in carbonates. Better porosity measurements have long been a focus for research in the industry. In the 1950s some reservoir engineers proposed complex models of sinuous, constant cross-section flow tubes to estimate fundamental reservoir properties such as permeability (figure 2.3). These early attempts to model pore dimensions and permeability in reservoirs were not very successful, either as representations of fluid movement or as tools to predict production rates. Concepts such as pore sizes, pore size distributions, tortuosity and constriction factors could be assumed and incorporated into equations, but not measured independently (figure 2.4). Modern carbonate studies attempt to assess large-scale effective porosity - the extensive network of fluid-conducting pores. Once a network has been recognized and its connectivity evaluated, the geoscientist can choose the most suitable methods to drain the reservoir and develop waterflooding procedures to enhance production. Drill cuttings and well logs provide the geologist s first glimpse of the reservoir s pore system. However, they cannot represent the full complexity of carbonate reservoirs, which often leads to frustration rather than understanding. Oil and gas reservoirs of the world Western Europe South America and Caribbean Eastern Europe Microporous ooid Middle East carbonate reservoirs North America Ooid outer layer Asia Australasia Africa Types of microporosity In pore-filling calcite mud Between pore-filling crystals Skeletal fragment and intraparticle mesopores Other Middle East reservoirs Former Soviet Union Pelletal grain with microporosity Fig. 2.1: BIG NAMES: The list of giant carbonate reservoirs in the Middle East (e.g. Ghawar Field, Zakum Field, Kirkuk Field, Marun Field and North Field) includes some of the world s largest and best known oil and gas accumulations. Fig. 2.2: The range of pore sizes and the distribution of porosity through matrix and grains in carbonate rocks makes determination of effective porosity very difficult. In this example, micropores are distributed throughout the rock; although the water they contain will not flow, it will be recorded in logs and may lead to incorrect formation evaluation and completion decisions. 28 Middle East Well Evaluation Review

5 Until recently, thorough evaluation of carbonate reservoirs using standard well logs was hampered by the complex and often heterogeneous nature of limestones and other carbonate rocks. Standard logs run in carbonate sequences over the past 20 years have provided estimates of porosity and saturation, but have not been adequate to predict which fluids will flow from any given zone and at what rates. Geologists working with carbonate rocks quickly realised that a simple porosity measurement is not enough to characterize the reservoir. Secondary, diagenetic or tectonic porosity characteristics, including moulds, vugs, channels, fractures, open faults and microporosity, can all give rise to unexpected behaviour. In the Middle East, borehole electrical imagery has revealed that there are more fractures and vugs (figure 2.5) within the region s reservoirs than was previously suspected. These studies have also revealed the presence of major heterogeneities including large open faults. How can the information from these electrical images be combined with other techniques and used to improve overall reservoir performance? One of the major challenges in carbonate formations is to analyse and quantify non-effective porosity. If this can be achieved, permeability evaluations will be more accurate. Large pores and heterogeneities can be defined by core and/or borehole imagery. Geologicallyguided pressure-transient testing can quantify the connectivity and production potential of heterogeneous pore systems. Reservoir engineers can integrate geological information with cased-hole, production and water monitoring data in older fields to improve their understanding of poorly-defined areas and identify bypassed oil zones. Pore space within the rock is only useful if it is part of a large-scale network. Isolated pores cannot contribute fluids during production, even if they have been filled with hydrocarbons earlier in their development. Unfortunately, the non-effective pores in carbonates can be smaller, equal in size or even larger than the effective intergranular or intercrystalline pore spaces. These non-effective pores in carbonate rocks include micropores, intraparticle pores, moulds and vugs. Well testing will probably always be needed in addition to any logging or coring if the large-scale connectivity of a carbonate pore system is to be defined. Fig. 2.4: FROM PORE TO PORE: Porosity and permeability are the fundamental controls on the reservoir potential and properties of a rock. Grain size, compaction, sorting and crystal growths all determine pore sizes and, therefore, porosity and permeability. Initial particle Mould Progressive solution Solution-enlarged mould Vug Fig. 2.3: Early attempts to model permeability as sinuous tubes of constant cross-section were not successful, either as representations of fluid movement within a reservoir rock or to calculate oil and gas production rates. Pore size and distribution are needed to define permeability in carbonate reservoirs. Fig. 2.5: INNER SPACE: Pore shapes and sizes in carbonate rocks sometimes reflect the original particles, but most vugs are moulds which have lost all trace of original particle shape. Modified after A.J. Lomando. Number 18,

6 CARBONATES CLASSIFIED Most carbonate rocks are formed from accumulations of skeletal fragments - the remains of carbonate-secreting animals and plants. Although the animals are better known to geologists, it is the plants, particularly blue-green and red algae, which, as a major food source for marine micro-organisms, control the distribution of carbonate sediments. Numerous methods for carbonate rock classification have been proposed over the past 40 years. The most widely accepted method, devised by R.J. Dunham in 1962, concentrates on the features which control porosity and permeability, i.e. grain-matrix relationships and mud content (figure 2.6). Boundstone The components in any boundstone were organically bound together during deposition. Blue-green algae and corals play a major role in this type of carbonate sedimentation, producing laminated carbonates and coral reefs respectively. Grainstone Grainstones are grain-supported carbonates containing less than 10% lime mud. With very little mud blocking the pore space, grainstones often Mudstone Less than 10 % grains Mud-supported Wackestone Packstone Grainstone Boundstone Crystalline More than 10 % grains Grainsupported Contains mud, clay and fine silt-size carbonate Lacks mud and is grainsupported Original components not bound together during deposition Depositional texture recognizable exhibit high porosity and permeability at time of deposition and after diagenesis. They have the potential to become excellent reservoir rocks. Many of the Middle East s biggest and best known carbonate reservoirs (e.g. Ghawar Field in Saudi Arabia and Zakum Field in Abu Dhabi) are grainstones. The pore systems are predominantly interparticle, but microporosity is present in the grains and in the mud fraction of some grainstones Original components were bound together Depositional texture not recognizable Fig. 2.6: The classification of limestones devised by Dunham (1962) is based on internal features such as mud content which control the porosity and permeability of the rock. Effective pore throat radii defined by Hg capilliary pressure Apparent progressive decrease in pore sizes Chalk small pores Reservoir grainstone with micropores or isolated macropores 1 Good reservoir grainstone % Hg saturation of pore volume 5 Non-reservoir rock Hg pressure (psia) Rock type pu md Good reservoir grainstone Reservoir grainstone with micropores or isolated macropores Chalk small pores Heterogeneous pore size distribution Non-effective pores Fig. 2.7: The relationship between effective pore throat radii and pore volume for some typical reservoir types (grainstones, wackestones and chalks) with a non-reservoir rock for comparison. All of these sediments could be encountered in the same carbonate sequence. 30 Middle East Well Evaluation Review

7 Open littoral Open reef-shoals Fore-reef transition zone Open basin (a) Ramp Back-reef shoals Reef wall Reef talus slope Fore-reef shoals Fore-reef transition zone Fore-reef basin (b) Reef shelf Littoral zone and sabkha clastics and evaporities Back-reef and top-reef grainstones and wackestones Reef talus grainstones Upper shelf slope (fore-reef) packstones and wackestones Reef boundstones Lower shelf slope and basin wackestones and mudstones Fig. 2.8: Carbonates can be deposited in a wide range of marine environments. They typically occur in sequences which can be characterized as ramp (a) or reef shelf (b) settings. Low-energy environments, such as the back reef shoals, which are protected from wave and current action, are characterized by higher concentrations of lime mud while clean rocks with high original permeabilities are found in high-energy zones at the shoreline or around the main reef wall. If the basin area associated with either of these sections generates hydrocarbons the oil and gas should migrate up the structure (green arrow) into the porous carbonate rocks. Packstone Packstones also have a grain-supported texture, but the rock contains large amounts of mud, so the original porosity is lower than in grainstones. Packstones are typically found in lower energy environments than grainstones. Wackestone In wackestones the carbonate grains float in an extensive mud matrix. This rock type is distinguished from mudstones by the proportion of grains - more than 10% of total volume. Wackestones are typically found in low-energy environments behind a reef or in deeper parts of a carbonate shelf. The mud and grain fractions may contain microporosity. Mudstone The low-energy environments in a carbonate sequence are characterized by lime-rich mudstones with less than 10% carbonate grains. Reservoir rocks - ramps and reefs The variations in reservoir performance for carbonate rocks (figure 2.7) make it critical that the producing zone is examined in detail and characterized accurately before major production decisions are made. These rocks do not become reservoirs unless fractured or affected by dolomitization. However, carbonates, like sandstones, occur in identifiable sequences which reflect changing marine conditions and environments (figure 2.8). The best interpretations place each carbonate unit in a sequence context. This allows the geoscientist to predict what type of changes in permeability and porosity may be anticipated above or below the zone of interest. R.J. Dunham (1962) Classification of carbonate rocks according to depositional texture. In: Classification of Carbonate Rocks (ed. W.E.Ham), pp Mem. Am. Ass. Petrol. Geol. (1) Tulsa. Number 18,

8 Grainstone shoaling-upward cycles Shoaling-upward sediment sequences with grainstone deposits at the top are common within some Jurassic and Cretaceous reservoirs of the Middle East. Rocks in the sequence are generally dominated by one type of grain - skeletal fragments, ooids, pellets or a large foram species. Whatever the grain type, the shoaling-upwards sequence usually begins with mudstones at the base which grade into wackestones. In many sequences the proportion of grains increases through the succession until mud-free grainstones develop. Migrating tidal bars may have a thinner or less predictable vertical transition from mudstone to grainstone. Microporosity within the grainstone sequence can be predictable, but is usually distributed throughout a reservoir. The micropores may have a relatively simple diagenetic origin, resulting from the leaching and incomplete reprecipitation of metastable calcite, or may be influenced by tectonic events such as uplift exposing the sequence to fresh water leaching and diagenesis. Borehole CMR measurements of pore size distributions in grainstone sequences can be very helpful for the geological analysis of depositional environments, and can be used to identify major diagenetic modifications in a sediment. Dealing with microporosity For more than 40 years microporosity has been a recognized feature of carbonate reservoirs. However, it was not until the development of the chalk reservoirs in the North Sea that the importance of this type of porosity became apparent. Pore systems dominated by very small pores can contain large oil and gas volumes, but their behaviour is very different to macro- and mesopore systems. Experimental programmes to evaluate microporosity using reservoir rock are time-consuming and typically consist simply of scanning electron microscope (SEM) inspection of small spot samples with little emphasis on how porosity distributions change through the sequence (figure 2.9). The CMR tool offers a cost-effective way to accelerate the process of defining microporosity (figure 2.10) and irreducible water saturation, while providing semiquantitative pore size distributions. Fig. 2.9: Pore size and type vary through this Jurassic grainstone sequence. Porosity in the wackestones is similar to that in the grainstones above, but permeability is lower because individual pores are smaller. The CMR tool can identify small pores and so improve formation evaluation. micrite crystal x ft. Depth micropore Pore size distributions Pore size (microns) Pore size distribution (similar to CMR T2) Fig. 2.10: Microporosity in a typical reservoir carbonate. If these pores contained water, standard well logs might indicate a water saturation too high for oil production. Nuclear magnetic resonance techniques can characterize these pores quickly and efficiently. Microporous dolomite Ooids with micropores within particles and also intergranular pores Ooids with oomoulds and some intergranular pores 30 pu The upwards increase of pore size and pore volume may be due to grain size decreasing down the sequence Position where a packstone facies might be expected Wackestone with micropores and moulds Wackestone with micropores grain x385 x µm 100µm 1000µm W. Kenyon (Schlumberger Doll Research), H. Takezaki (ADOC - Japan) et al. (1995) A laboratory study of nuclear magnetic resonance relaxation and its relation to depositional texture and petrophysical properties - carbonate Thamama Group, Mubarraz Field, Abu Dhabi. SPE MEOS. 32 Middle East Well Evaluation Review

9 Bound fluid Water Possible free water Water Moved hydrocarbon Volume of water from RT Moved hydrocarbon Oil Porosity Perfs 0.0 (PU) 25.0 CMR bound fluid Oil Diff. Caliper Calcite Dolomite 1:200ft (IN) 20 Anhydrite Irreducible water Moved oil Residual oil X900 Residual oil Fig. 2.11: Some zones which appear to contain too much water for cost-effective oil production actually produce dry oil because all of the water in the zone is irreducible (i.e. bound in the rock s micropores). Modified from M. Petricola and H. Takezaki (1996) Nuclear Magnetic Resonance: It Can Minimize Well Testing. SPE th ADIPEC Conference. In the Middle East, the potential problems associated with microporosity first became apparent as a result of difficulties with wells in the Lower Cretaceous Thamama Group. Predictions about oil or water production, based on logderived saturation calculations, were consistently incorrect because irreducible fluids in non-effective micropores were being included in porosity calculations (figure 2.11). Younger rocks have more micro porosity (figure 2.12) than their older counterparts. The Tertiary carbonate reservoirs of Egypt and India are more likely to be affected by microporosity than the deep Permian Khuff carbonate reservoirs of the Arabian peninsula. This probably reflects the ease with which micropores can be closed by overburden pressure following deep burial. Fig. 2.12: Plots for young reservoir rocks which have been altered by gradual and uniform cementation. The relationship between particle size and this pattern of diagenetic effects is very complex. The graph indicates a general trend in permeability and porosity reduction. Modified from R. Nurmi, GEO/96 Number 18,

10 DOLOMITE DEFINED AND DESCRIBED Dolomite is a highly-ordered mineral consisting of calcium and magnesium ions in separate layers alternating with carbonate ions. The chemical transformation of calcite (CaCO 3 ) into dolomite CaMg (CO 3 ) 2 can have a profound effect on reservoir properties such as porosity and permeability. The conversion process may occur at any time in the diagenetic history of a rock sequence - soon after sediments have been deposited or long after deposition, when cementation has already affected the rock. Dolomite may replace the whole rock or only grains or matrix. To further complicate rock characterization, dolomite can be replaced by a latestage calcite influx. This process may retain the morphology and porosity of the dolomite rock, while changing its chemistry back to calcite. Early, late or not at all? Supratidal and hypersaline dolomite is produced through evaporation and it precipitates at high Mg/Ca ratios. This ratio is increased by the precipitation of calcium-rich minerals which leaves a calcium deficit in the pore water. Late stage dolomitization tends to cut across depositional units rather than being tied to particular limestone facies. In most cases the late stage dolomite destroys the existing limestone fabric. Late stage dolomitization may be pervasive, where all of the limestone is converted to dolomite with only relics of the original components, or selective, where, depending on pore water, sediment chemistry etc., only the matrix or grains of a particular limestone are replaced. Dolomite also occurs as randomly distributed rhombs in limestones (figure 2.13) and may occur as a cement in cavities. The most important consequence of late stage dolomitization is an accompanying increase in porosity. Dolomite has a more compact crystal structure than calcite, so in theory the total dolomitization of a limestone should result in a porosity increase of 13% so long as there is no subsequent compaction or cementation. Dolomitization generally creates greater effective porosity, but most diagenetic changes tend to reduce overall porosity. Studies have shown that the planar grain surfaces of dolomites create polyhedral pores. Consequently, as the rhombs develop they produce sheet pores and throats rather than the tubular pores and throats which characterize limestones. Fig. 2.13: Scanning electron micrograph showing rhombs of dolomite growing over crystals of calcite which contain high concentrations of magnesium. 34 Middle East Well Evaluation Review

11 Depth (km) (a) Sealevel (b) Sealevel Limestone Dolomite Supratidal hypersaline pond Hypersaline marine water Porosity (%) Beach ridge Freshwater lens Evaporative dolomite crusts Meteoric-marine mixing zone and location of dolomite precipitation > 75% limestone > 75% dolomite Intense evaporation Tidal flat Seepage Reflux Lake Area of dolomitization Fig. 2.14: Dolomitization involves the movement of magnesium-rich fluids through carbonate rocks. The details of dolomite formation are unclear, but two possible mechanisms are (a) precipitation around hypersaline ponds as a result of marine and meteoric water mixing and (b) seepage reflux where seawater seeping into supratidal lakes is subjected to intense evaporation and gypsum precipitation which raises the Mg/Ca ratio in solution. Several mechanisms have been proposed to account for dolomitization (figure 2.14). One critical aspect of the process wherever it occurs is that dolomite preferentially replaces mudsized particles rather than the sand-sized grains in the original limestone. Consequently, the best oil and gas reservoirs are seldom found in (mud-free) rocks with high primary permeability. In intertidal and subtidal environments permeable units such as skeletal and oolitic limestones display secondary (leached) porosity that has converted moulds into irregular vugs and fractures into solution channels. If dolomitization occurs at this stage the calcium ions Fig. 2.15: Compaction in dolomites is typically less than in limestones, so although dolomites start with lower porosity at the surface they retain reservoir levels of porosity to greater depths. released from the limestone may form anhydrite which plugs the permeability, creating a dense rock from a porous one. Farther down the slope, very low permeability micrites (usually aragonitic lime muds) are dolomitized, yielding intercrystalline or matrix porosity, so the best reservoir units are those with the poorest original permeability. In the Arab-D zone in the Jurassic of Saudi Arabia, principal production comes from detrital, bioclastic or oolitic limestones. Where oil is produced from dolomites, however, the rocks which have been dolomitized were predominately micrites. In addition to their capacity to produce porosity in less promising settings, dolomites retain their porosity better than carbonates during burial (figure 2.15). Microdolomites that fill limestone micropores can help to preserve porosity in deeply-buried carbonates (figure 2.16). Reefs are particularly susceptible to dolomitization, because the quiet shallow waters of the backreef environment are an ideal site for evaporite deposition. The distribution of dolomites in the stratigraphic record is not equal. The proportion of dolomites in older sequences is higher than in their more recent counterparts. In Mesozoic rocks the limestone:dolomite ratio is around 10:1, in the Palaeozoic it is 3:1 and in the Precambrian 1:3. It may be that typical dolomite-forming environments were more common in the Precambrian or simply that the older sequences have had more time to be exposed to solutions capable of causing dolomitization. All change, again Dolomite may be replaced by calcite to produce a limestone again. This process is referred to a dedolomitization and usually occurs when the rock is exposed to fresh surface water during periods of tectonic uplift. Identifying dedolomites involves noting characteristic dolomite crystal shapes (usually rhombohedra) which have been replaced by calcite or calcite crystals with small dolomite remnants. In some cases the original limestone texture is partly regenerated by dedolomitization; in other cases layers and concretions of fibrous calcite completely replace the dolomite. Fig. 2.16: Micropores in limestone are often closed by diagenetic effects or burial. The tiny grains of dolomite which form in these pores can preserve microporosity. Number 18,

12 As one pore closes... When sediment is deposited the intergranular pores are almost always considerably smaller, on average, than the rock particles. Burial makes the situation worse as compaction and cementation combine to reduce pore size (figure 2.17). If no major phase of cementation occurs, intergranular carbonate pores generally remain well-connected until pressure solution effects at great depth close them completely. Intraparticle pores are usually independent of the effective pore system and may be preserved to greater depths. They are also very variable: their maximum size is limited only by the dimensions of the rock grains. Intraparticle porosity may occur as several small pores within a rock particle or as microporosity spread throughout a grain (see figure 2.2). Making more of micropores According to the long-established carbonate classification system devised by Choquette and Pray (1970), micropores are those with diameters below 1/16mm while a pore with a diameter above 4 mm is a megapore (figure 2.18). Pore diameters can be difficult to visualize, so for a comparison of relative size it is useful to enlarge the pores. If a 4 mm megapore was enlarged to the size of a basketball hoop, a typical micropore - at the same scale - would be the size of the eye of a needle. Micropores are frequently overlooked in core and cuttings, which can have detrimental effects on production plans and field development. Microporosity can also cause barriers and/or baffles to fluid flow. In the Hanifa reservoir in the Berri Field, for example, microporosity led to significant volumes of oil being bypassed. In conventional logging techniques microporosity is not distinguished from other porosity types. Micropores are usually water-filled, so well logs may indicate that a reservoir zone is not suitable for (d) fracturing (c) cementation 0 15 production because it contains too much water. However, the water in micropores is often irreducible water that will not be produced - the micropores are non-effective - so the zone would be suitable for completion and produce dry oil after all. To reduce the risk of missing productive zones the CMR tool should be used in conjunction with a Fullbore Formation MicroImager (FMI*) tool to characterize sedimentary sequences. Preliminary use of the CMR tool has shown that best results are achieved if rocks are examined as part of a sequence, allowing the geoscientist to predict probable pore size distribution and check results against it, rather than dealing with each sample independently of its depositional framework. (b) compaction (e) leaching of cement Porosity (%) (f) leaching of grains (a) deposition Permeability (md) Fig. 2.17: After deposition (a), sediments are compacted (b) which reduces interparticle pore space. Cementation effects (c) also reduce interparticle porosity as material from solution is deposited around the grains. Fracturing (d) and leaching of cement (e) or grains (f) (usually by fresh water when sediments are returned to surface or shallow depths by tectonic movements) will increase porosity. From R. Nurmi, 1984, AAPG Bulletin Pore size terminology and examination Macropores (visible) Classes mm microns Megapore large >4 >4000 Outcrop small core Mesopore large small 1/ 2 1/ 16 Units Examination Core, hand-lens thin section Borehole imagery CMR log Fig. 2.18: If a typical 4mm megapore was enlarged to the size of a basketball hoop, a typical micropore, after the same enlargement, would be the same size as the eye of a needle. Micropore (individually invisible to naked eye) SEM,Hg capillary CMR log 36 Middle East Well Evaluation Review

13 Moulds and vugs Moulds are solution voids which retain the shape of the dissolved fossil or rock particles. Vugs are enlarged solution voids that no longer resemble the original particle or fossil. Both can be very important for oil production. However, in some cases, the presence of vugs and moulds has no effect on production. The most important questions to ask about them are: do they form a continuous network? is the rock around them porous? If the network is continuous the vugs will contribute to production directly. However, if the moulds and vugs do not form a network, but the surrounding rock is permeable, then these large secondary pores simply provide additional storage in the rock. If the vugs are not part of a network and the rock around them is impermeable they will not produce oil. Megapores, large vugs and moulds are best identified using electrical imagery and their attributes can be defined using a computer workstation. Unfortunately, electrical imagery does not help to assess connectivity away from the wellbore. A computer technique has been developed to assess vertical connectivity, but alongbedding connectivity (perpendicular, rather than parallel to the wellbore) is more common. Porosity around the wellbore The porosity and permeability ranges of typical carbonate rock types, and the geological processes (e.g. fracturing, compaction, cementation and leaching) which lead from one to another, can be represented graphically (figure 2.19). There are often discrepancies between porosity distributions derived from core samples and those from logs. The most important source of this variation is that core and well logs typically examine and average different volumes and, because the two techniques are measuring slightly different pore populations, they produce different results. One of the most effective solutions to this problem is to use the advanced borehole magnetic resonance technology of the CMR tool which samples a very small formation volume (figure 2.20), and to cross-reference its results with electrical imagery. This solution is of enormous benefit in wells where rock types vary over short distances, e.g. from one side of the borehole to the other, or where two distinct rock types are intimately mixed but behave as separate units. Borehole magnetic resonance is the latest borehole technology to be introduced in the Middle East. The technique has been under development for more than 15 years and even then some oil 1000 Permeability (md) Leached channels in metal rock Wackestones Mudstones Porosity (%) Fractures Grainstone, pore diameter declining Core Particle diameter = 500µ Wellbore CMR measurement volume 1" x 1" x 6" Particle diameter = 300µ Vuggy dolomite Wackestone companies knew it would be essential to characterize complex reservoirs. From years of exploration and production, geologists have amassed a huge compendium of information (thin sections, SEM photos, cores, NMR results, pore casts and detailed sample descriptions) about the pore systems of carbonate reservoirs in the Middle East. Using this library to guide CMR surveys will help to ensure a unique and accurate assessment of effective and non-effective pores, and so improve saturation and permeability calculations. The CMR tool also offers the possibility of routine evaluation of microporosity and irreducible water saturation values. To get the most from Particle diameter = 100µ Packstones, Lime mud Compaction and cementing Moldic grainstone Coccolith chalk pore diameter < 1µ Leaching Fig: 2.19: The relationship between porosity and permeability for various carbonate rocks. From: R.Nurmi (1986) Middle East Well Evaluation Review, issue 1. Land of the giants. Wellbore cross-sectional view 8 1/4" diameter borehole CMR measurement volume 1" x 1" x 6" Fig. 2.20: The CMR tool offers precise examination of the borehole wall. Its small measurement volume is in contrast to other tools which can only provide averaged porosity values for a much larger volume. the CMR tool, core petrophysicists, log analysts and geologists must cooperate. Combining the CMR tool with a FMI survey, the geoscientist can detect and quantify pore sizes ranging from micropores to megapores, which in the most general sense includes open faults which may extend up into a gas zone or down into an aquifer. Oriented CMR tool measurements reveal whether vugs and fractures that are not connected to each other will contribute to production through the rock surrounding them. P. Choquette and L. Pray (1970) Geologic nomenclature and classification of porosity in sedimentary carbonates. AAPG Bull., (54) pp Number 18,

14 CARBONATE LOGGING - THE WAY AHEAD The complex pore systems found in some carbonate oil reservoirs in West Kuwait (figure 2.21) have proved difficult to evaluate. Borehole imagery has helped to define fractures and faults in wells and, thus, to remove a major uncertainty from formation evaluation. Standard open hole well logs provide porosity and saturation information which is often insufficient for the evaluation of these complex, high-resistivity carbonate sequences. In some cases, apparent porosity and saturation can be misleading, giving a false indication of which fluids will flow and of flow rates from a particular zone. Low porosity layers can have the highest permeability in a reservoir, and the highest porosity interval may be composed entirely of micropores and, therefore, be impermeable. In some wells, zones which are assessed as having high water saturation may flow dry oil, and tar mats may be incorrectly interpreted as oil zones. Tests in West Kuwait In a recent study, three Jurassic carbonate reservoirs from Minagish and Umm-Gudair fields in West Kuwait were selected to test the new logging technique (figure 2.22). The Upper Jurassic Najmah and Middle Jurassic Sargelu formations are overlain by Kimmeridgian Gotnia Formation and rest on the Bathonian Dharuma Formation. The Najmah is composed of limestones, usually argillaceous, carbonaceous and interbedded with thin black shales. The Sargelu reservoir consists of an upper unit of clean, densely cemented peloidal packstones and packstonewackestones deposited in higher energy, shallow water, plus a lower unit of more argillaceous wackestones from a deep water environment. Primary permeability is generally too low for economic flow rates. However, some intervals in the Najmah and Sargelu formations are extensively fractured, with these large open fractures supporting high fluid flow rates. Below the Dharuma Formation lies the Marrat Formation, a limestone reservoir divided into three members and composed of carbonate grainstones and packstones interbedded with wackestones and mudstones from a shallow shelf setting. Triassic Jurassic West Kuwait Minagish Upper Middle Lower Upper Kuwait City Umm-Gudair Upper middle Lower Triassic Upper Permian Permian The Gulf Tithonian Kimmeridgian Oxfordian Callovian Callovian Bajocian Bathonian Bajocian Toarcian Rhaetian Carnian Ladinian Anisian Scythian Tatarian Kazanian Log interpretation of sequences such as this has always been difficult. In the organic-rich Najmah Formation, conventional resistivity-nuclear logs often indicate apparent high porosity and resistivity zones, but these are often found to be non-reservoir zones. At the other extreme, the shaliness, dolomitization and organic content of the Najmah and Sargelu formations can reduce porosity estimates dramatically in zones that will flow oil from welldeveloped fractures. Porosity is generally better in the Marrat Formation than in the Sargelu Formation, but there are fewer fractures. However, the widespread development of micropores makes permeability estimates from porosity values very unreliable. Decisions on where to perforate these units are, clearly, not simple, and there are often marked variations in production rates from intervals where the rocks have the same porosity range. In an effort to resolve these problems nuclear magnetic resonance (NMR) survey techniques were introduced into Kuwait early in Fig. 2.21: KUWAIT AND SEE: Some of the carbonate oil reservoirs of West Kuwait contain very complex pore systems. Borehole imagery and nuclear magnetic resonance have helped to answer the questions posed by anomalous production rates and contradictory results from standard well logs. Hith Gotnia Najmah Sargelu Dharuma Marrat Minjur Jilh Sudair Khuff Fig. 2.22: The Jurassic reservoirs of West Kuwait, in the Najmah, Sargelu and Marrat formations, are complex carbonate sequences. Production-related decisions about these units are never simple, so they provide a perfect test for any new logging technique. Porosity and production The problem described below is frequently encountered in the Najmah reservoirs. Traditional logs indicate an apparent porosity of 20% and deep resistivity values of 100 ohm-m or more, resulting in a water saturation (S w ) value below 10%. Despite these clear indications of a suitable reservoir zone, production tests yielded no hydrocarbon. A CMR log was run and showed that there was no effective porosity and permeability in the Najmah Formation. Close core examination showed that organic content reached 50% in some instances. The high organic content is the source of the readings which normally indicate an oil-saturated and porous reservoir zone. The low matrix porosity values recorded by the CMR were too low to explain the flow rates seen in this reservoir. Using an Ultrasonic Borehole Imager (UBI*) tool, Kuwait Oil Company assessed the importance of fracture porosity and permeability. 38 Middle East Well Evaluation Review

15 x430 x450 x470 x490 Fig. 2.23: This example is taken from the Najmah Formation. Beneath the fault at X450, there is a packstone-wackestone series that grades into mudstone (as indicated by the decreasing poresize trend in the CMR). DSI permeability values are affected by the mudstone laminations and are incorrect. The CMR-derived porosity value is correct. Fig. 2.24: This example from the Marrat Formation. shows that in the lower part of the sequence porosity decreases upwards, but this change is accompanied by a permeability increase. The CMR tool (track 2) identifies pore size distributions, helping to explain this apparent anomaly. The CMR tool can be used to check other permeability measurements For example (figure 2.23), where a packstone-wackestone series grades into mudstone (as indicated by the decreasing pore size trend in the CMR), the Dipole Shear Sonic Imager (DSI*) toolderived permeability values are affected by mudstone laminations and give an incorrect value below the fault at X450. The CMR-derived porosity value is correct. Predicting permeability The porosity of the Marrat Formation is in the range 0-15 % and permeability is variable. The estimation of permeability is of vital importance in this major reservoir. This is a clean carbonate with a complex pore structure as indicated by the T2 distribution log of the CMR. The Marrat carbonate sequence has a complex pore size distribution (figure 2.24). The CMR tool indicates where there is a high proportion of microporosity (and a reduction in effective porosity and permeability). The lower section shows porosity decreasing upwards, but permeability increases in this direction, contrary to the usual relationship between these parameters. However, when CMR permeability is used to calibrate results from the DSI tool the results agree with drawdownderived permeability. A new approach in West Kuwait Integration of borehole NMR responses and other open hole logs can be used to better quantify the reservoir properties and lead to optimal completion of wells in the West Kuwait carbonate reservoirs. Borehole NMR has allowed an improved interpretation of: Effective porosity in complex lithologies: it is essential to determine effective porosity in the organic-rich Najmah Formation and the Sargelu Formation to quantify the matrix support to the fracture systems in these reservoirs. Permeability: NMR-derived permeability allows the correct interpretation of permeability in complex pore geometries. Further, the integration of NMR and DSI tool-derived permeabilities with ultrasonic borehole images has highlighted the importance of fractures in well productivity. Pore size distribution: an indication of the pore geometry allows a better understanding of permeability variation in these complex carbonates. Ahmed A Latif, D. Sungur, I. Stockden and C. Cao Minh (1997) Borehole nuclear magnetic resonance: experience and reservoir applications in West Kuwait Carbonate Reservoirs. SPE Number 18,

16 Key: Reef Shelf carbonate Deep carbonate Carbonate oil province Fig. 2.25: ALL OVER THE WORLD. Modern carbonate deposits are found in all of the world s major oceans and seas but modern reef carbonates are restricted to tropical and subtropical latitudes. In the right environment Modern carbonate sediments are found in all major world oceans, but modern reef deposits are restricted to tropical and subtropical latitudes (figure 2.25). Changing climatic zones tied to tectonic movements mean that reefs have developed in every continent at some stage in geological history (e.g. Canada s Devonian reef reservoirs). Chalks and limestones are lithified carbonate formed by the dissolution, reprecipitation, recrystallization and compaction of biogenic carbonate particles. Initial porosities of 70% have been recorded in unconsolidated sediments, although these are rapidly reduced during burial, typically falling to around 10% in limestones. Chalks, which form under relatively shallow burial (a few hundred metres), can be considered an intermediate step to limestones. The additional cementation that produces limestones from chalks typically occurs at depths in excess of 1000 m. Pores and diagenesis The most important stage of diagenesis for a possible carbonate reservoir is cementation. Early cementation can help to preserve pore space in a sediment during burial. In carbonate rocks, pores may be of any shape from irregular to perfectly spherical. Carbonates, in contrast to sandstones, do not usually have the complete range of grain sizes from large particles down to clays: sandstones contain sand, silt and clay particles, but silt size particles are usually missing from carbonate deposits. Carbonates can, therefore, be considered better sorted at time of deposition. However, this benefit must be weighed against the fact that carbonate particles undergo more post-depositional changes than quartz grains. Two common carbonate reservoir sequences, chalks and shoaling grainstone sequences, are end members of carbonate deposition and have very different pore systems. One of the most unusual properties of porous chalks is their tendency to retain microporosity well after burial. Chalk reservoirs often have high porosity, relatively uniform pore size and very wellconnected pore space. They are composed of micron-sized particles and fragments of disarticulated planktonic nanofossils. Pore size typically ranges from 10 microns to a fraction of a micron and the pore throats are usually an order of magnitude smaller. Superficially, chalk units may appear very similar but two chalks with identical porosity values may behave in very different ways. For example, a chalk composed primarily of foraminiferal bioclasts will generally display a higher permeability than one composed of coccolith microfossils (figure 2.26). As depth of burial increases, cementation, compaction and recrystallization of the low magnesium calcite decrease pore size and volume. Ultimately, this process will damage the pore system to the point where the loss of permeability means that Fig. 2.26: Chalk pore size data and porosity/permeability crossplot of various samples in a sequence. Grain composition is very important in determining the porosity retention of various chalks. Coccolith chalks, for example, will generally have lower permeability values than equivalent chalks composed of more coarse-grained foraminiferal bioclasts. Modified from R. Nurmi, GEO/ Middle East Well Evaluation Review

17 100 Cumulative % pore space Pore apertures (Hg-injection data) Whole pores (image data) Average porosity 30% 50 p.u Diameter (microns) Fig. 2.27: Comparison of Hg injection and image-derived whole-pore data (from SEM) shows that pore throats are about one tenth the size of whole pores. The CMR tool measures similar features but presents results for all pore space in the rock. the rock is no longer of reservoir quality. Early entry of hydrocarbons can halt or slow down this process. The CMR tool identifies the total pore space in a reservoir rock and its results can be crossreferenced with mercury-injection analysis and whole-pore data derived from scanning electron microscope (SEM) studies (figure 2.27). If the original pore system of the carbonate has not been modified by diagenesis, then the CMR pore size distributions can be used to infer particle size at time of deposition. However, where diagenesis has modified the pore system significantly, the CMR should not be used to infer depositional characteristics. In all cases, even with complex diagenesis, the CMR-derived free fluid volume is the key to assessing the effective porosity volume. The industry now accepts that carbonate reservoirs are much more complicated than early models suggested. Rock type is not a firm indicator of reservoir quality and the essential factors - porosity, permeability and pore size distribution - can change dramatically through the postdepositional history of the unit. Even high porosity chalks may be poor reservoir rocks at time of deposition if their pores are small (figure 2.28). Any fall in permeability may have disastrous consequences for production potential. The current focus of research in chalk reservoirs is on wettability. This research is being pursued through laboratory and borehole NMR methods. Unexpectedly high permeability in chalks is usually caused by either another rock/pore type mixed in the sequence or the presence of fractures or faults. Open fractures and faults are identified by borehole imagery, especially in horizontal wells where many more discontinuities are intersected by the borehole. Depth Average porosity 30% Shale with no effective pores Micropores Pore size (microns) Pore size distribution (similar to CMR T2) In some reservoirs thin, coarsegrained beds with relatively large pores can be interbedded with the chalks. These beds may produce surprising and unwelcome effects, including early water production from edge water encroachment. Rather than relying on samples taken in isolation, geoscientists are now turning to methods that suggest the lateral extent of depositional facies and diagenetic overprints for each reservoir unit. The CMR tool allows the interpreter to account for the microporosity which can disguise effective pore systems. When related to well-designed well tests, this approach will ensure that production and field development strategies reflect the full extent of reservoir complexity. -?- Mesopores (a) Fig. 2.28: This chalk sequence contains a shale unit with no effective pores. The carbonate rocks above and below have average porosities of 30% but most of this is concentrated in small pores (less than 10 microns). Larger pores are concentrated at (a) and it is from this layer that fluids are likely to flow. Number 18,