Middle East Carbonate Reservoir Research Articles

Pore-to-field scale modeling of residual gas trapping in tight carbonate underground gas reservoirs

The deep saline aquifer and depleted gas reservoirs are suitable candidates for CO2 storage. The estimation of residual gas and corresponding flowing behavior are major parameters for successful CO2 trapping in geological formations. In this article the residual gas trapping phenomenon in pore scale has been studied using Micro-CT images. In macro scale, the results of imbibition experiments on core plug samples have been considered to determine residual gas saturation (RGS) and the corresponding water relative permeability. In the field scale, pressure transient data in water leg has been used to determine the water relative permeability at RGS in a tight carbonate reservoir in Middle East. In the proposed workflow, an artificial intelligence approach is applied to determine absolute permeability profile. Then, a numerical dynamic single well model is built to calculate the water relative permeability. The comparison of core and pressure transient data shows that the absolute permeability and water relative permeability from core imbibition test are significantly overestimated while the results of gas-water simulation in pore scale confirmed the real field transient data. The proposed method can be used by industrial reservoir simulator to define rock/fluid interaction parameters in simulation of CO2 storage in depleted underground gas reservoirs.

Enhancement of Oil Recovery in West Qurna-1 Carbonate Reservoir by Injecting Seawater

Seawater injection is a novel emerging technology for enhancing oil recovery in Middle East carbonate reservoirs. This paper investigated the mechanism of seawater injection in Mishrif formation for the West Qurna-1 oil field. The decline in the pressure of West Qurna-1 needs pressure support by water injection, where it is a supergiant oil field. This study is significant because seawater injection technology is considered a future technology in the south of Iraq for several reasons. One of these reasons is the scarcity of fresh water in the Middle East, especially in Iraq, and the second reason is the availability of seawater, which is close to Basra city. This paper aims to study the essential parameters that influence the oil recovery via sweater injection as well as the inherent mechanisms that help increase the oil recovery. Collected five core plugs from producing units of Mishrif formation, MB1, and MB2, having different petrophysics properties where the permeabilities ranged from 6 to 143 md. Two types of water are used formation water and seawater. We conduct core flood experiments on chosen carbonate core samples and formation water from Iraq's West Quran-1 carbonates. The common belief facts that low salinity flooding of oil recovery gives more producing oil for the same volume of water injected due to wettability alteration. The analysis of injected and producing water indicates that higher concentrations of SO4-2 and Ca-2 ions change the wettability of the rock to more water-wet. Consequently, the oil recovery increases by 10-15 % when using seawater, which is richer in these ions.

A comprehensive performance evaluation methodology for miscible gas flooding: A case study in a giant carbonate reservoir in Middle East

This work focuses on a typical low-permeability carbonate reservoir in Middle East that has been developed by miscible hydrocarbon (HC) gas flooding for more than 10 years. The oilfield is now suffering from gas channeling, high gas/oil ratio (GOR), and invalid gas circulation. To figure out the reasons and propose an optimized development plan, it is necessary to accurately determine the characteristics and behavior of miscible gas flooding. To achieve this, a comprehensive performance evaluation method for miscible gas flooding is established in this work by integrating production data, inter-well gas tracer test, saturation surveillance, pressure surveillance, minimum miscibility pressure (MMP) variation, and streamline simulation. The following miscible HC gas flooding characteristics are interpreted, including typical gas flow path, miscibility behavior, major controlling factors impacting performance, and the main challenges of the current development scheme, which provides a fundament for proposing mitigation plan. By using this evaluation method, the behavior of gas flow in the ongoing miscible flooding process is precisely characterized, which is a “gravity override-gas coning” mode in which gas override is formed by an upward injected gas flow and then gas flows through gas cap to producers that leads to gas coning, resulting in high GOR and invalid gas circulation. This flow mode mainly resulted from the unsatisfied miscibility that led to gas escaping from miscible phase and gas channeling. Furthermore, it was found out that pressure difference is the dominating factor for gas channeling. In addition, we also found that MMP varies during HC gas injection process due to the change in the oil composition, which emphasizes the importance of recovering and maintaining pressure. Based on these findings obtained from extensive dynamic performance analysis and numerical simulations, an optimization strategy is finally proposed for improving the performance of miscible HC gas flooding.

A Comprehensive Performance Evaluation Methodology for Miscible Gas Flooding: A Case Study in a Giant Carbonate Reservoir in Middle East

A Comprehensive Performance Evaluation Methodology for Miscible Gas Flooding: A Case Study in a Giant Carbonate Reservoir in Middle East

Drilling Dynamics, Mechanical Specific Energy Data Help Drill Record Extended-Reach Well

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 203335, “Using MSE and Downhole Drilling Dynamics in Achieving a Record Extended-Reach Well Offshore Abu Dhabi,” by Nashat Abbas and Jamal Al Nokhatha, ADNOC, and Luis Salgado, Halliburton, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. Complex extended-reach-drilling (ERD) wells often present challenges with regard to geological aspects of data requirement and transmittal, reactive geosteering response times, and accuracy of well placement. Such scenarios may require innovative approaches in Middle East carbonate reservoirs. The objective of the complete paper is to illustrate that, by assessing the details of reservoir geology and key operational markers relevant for best practices, drilling approaches can be customized for each reservoir or scenario. Reservoir Background and Geology The planned reservoir section is a single horizontal of approximately 25,000-ft lateral length at a spacing of 250 m from adjacent injectors. The well was drilled from an artificial island. Field A, a shallow-water oil field, is the second-largest offshore field and the fourth-largest field in the world. Horizontal drilling was introduced in 1989, and an extensive drilling campaign has been implemented since then using steerable drilling technologies. This study is concerned only with wells drilled to develop Reservoir B in Field A, which contributes to the main part of initial oil in place and production. The thick limestone reservoir is subdivided into six porous layers, labeled from shallow to deep as A, B, C, D, E, and F. Each porous layer is separated by thin, low-porosity stylolites. The reservoir sublayer B, consisting of approximately 18-ft-thick calcareous limestones, was selected as the target zone for the 25,420-ft horizontal section. ERD, constructed on artificial islands, began on 2014 with a measured depth (MD)/true vertical depth (TVD) ratio approaching 2.2:1 or 2.4:1. A recent ERD well, Well A, was drilled at the beginning of 2020 with a MD/TVD ratio of 5:1. This value is a clear indication of progressively increasing challenges since the start of the project. Mechanical specific energy (MSE) has long been used to evaluate and enhance the rate of penetration (ROP); however, its use as an optimization tool in ERD wells has not been equally significant. This may have been mostly because of historical use of surface-measured parameters, which do not necessarily indicate the energy required to destroy the rock, particularly in ERD wells. Using optimization tools as part of the bottomhole assembly (BHA) downhole close to the bit provides actual weight-on-bit (WOB) and torque-on-bit (TOB) applied to the drilling bit to destroy the rock and, thus, results in more-representative MSE measurements to optimize drilling parameters and ROP in ERD wells.

Comprehensive pore size characterization of Midra shale

Although the Middle East's carbonate reservoirs were the first and most studied rocks in the world, Middle Eastern shale reservoirs are still poorly understood compared with other unconventional formations in the US. We investigate the pore-throat size and pore-body size distributions of Midra shale in Qatar to quantify the pore-scale features that control transport properties at the core scale. We measured the capillary pressure by injecting mercury into samples in drainage. The capillary pressure variation with wetting phase saturation exhibits a plateau-like trend, which differs from the linear trend observed in most shales in the US. The capillary pressure measurements quantify the pore-throat size distribution. We also measure nitrogen adsorption and analyze the measurements to determine the pore-body size distribution. This study shows that the pore-throat size has a narrow distribution, and its average is close to 22 nm. In addition, the pore-body size has a wide distribution, and its average is 18 nm. Thus, the transport properties dependent on the pore-throat size require modifications to account for the pore proximity to represent subsurface conditions. The transport properties, such as density, relevant to the pore volume in the matrix can be estimated with reasonable accuracy from the gas composition in wider conduits. The presented results have applications for the development of unconventional gas, which is the cleanest fossil fuel.

An investigation on water flooding performance and pattern of porous carbonate reservoirs with bottom water

Water flooding is the most common oil recovery technology for carbonate reservoirs in Middle East. However, because of the various reservoir physical properties, serious problems, such as water breakthrough and uncharted distribution characteristics of remaining oil, bring great challenges to successful water flooding development. In this research, the scaled 3D water flooding experiment with an interlayer heterogeneous and anisotropic physical model was performed to achieve quantitative characterization of water flooding performance and pattern and the distribution of remaining oil after displacement in a porous carbonate reservoir with bottom water. Results indicate that the water flooding performance of bottom water varies with the various permeabilities in different layers. It can be divided into two patterns, characterized by smooth spread in high-permeability layers and coning type breakthrough in low-permeability layers. Specifically, in high-permeability layers, the horizontal flow is faster than vertical flow because the bottom water is mainly controlled by higher horizontal permeability and the lower production pressure difference can't overcome the gravity. Therefore, the whole layer is flooded and there is less remaining oil in high-permeability layers. On the contrary, in low-permeability layers, production pressure difference will drive water to climb up near the vertical wellbore and the water cone appears significantly, resulting in the remaining oil between the wells. In conclusion, the main mechanism behind the water flooding performance can be the heterogeneous and anisotropic characteristics of permeability.

Polymer flooding in high temperature, high salinity conditions: Selection of polymer type and polymer chemistry, thermal stability

After 50 years of research and numerous commercial field applications around the world, polymer flooding is considered as a proven EOR technique. However, until recently, its application was limited to reservoirs with temperature not exceeding 100 °C. The development of polymer withstanding harsh conditions such as those encountered in Middle East carbonate reservoirs (temperature higher than 100 °C and salinity up to 280 g/L), would unlock a lot of reserves.In this paper, thermal stability, limits and application range of biopolymers and acrylamide-based polymers are reviewed. It appears that a new class of acrylamide-based copolymers containing high level of 2-acrylamido-2-methyl propane sulfonate (AMPS) fulfills the main criteria for massive field injection: industrial availability, moderate cost, thermal stability (we present aging tests for which 80% of the viscosity is maintained after 3 years at 120 °C in a hard brine) and ability to propagate in a wide range of permeabilities by tailoring the molecular weight.A viscosity model we recently developed is applied for comparing the viscosifying power of hydrolyzed polyacrylamides (HPAM) with a AMPS-rich polymer (SAV10). The latter presents a better salinity tolerance, especially when divalent cations are present and a better viscosifying power in temperature. The model is successfully applied when viscosity is predicted at high temperature from a viscosity measurement at ambient temperature.After reviewing the effect of CO2 and H2S on viscosity and degradation, it is shown that SAV10 viscosity is not sensitive to pH and should remain constant whatever the CO2 content. This insensitivity to pH is taken as an advantage: a method is proposed for minimizing oxidative degradation on solutions sampled manually on the field.

4D Seismic Pilot Successfully Interprets Carbonate Reservoir

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 193063, “A Successful 4D Seismic-Monitoring Pilot in a Middle East Carbonate Reservoir Context,” by F. Cailly, T. Al-Romani, C. Hubans, and A. Lafram, Total, and A. Al Kaabi, ADNOC, prepared for the 2018 SPE Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 11–14 November. The paper has not been peer reviewed. This paper describes interpretation results of a 4D seismic-monitoring program in a challenging Middle East carbonate reservoir. The program consists of a 4D pilot [oceanbottom cable (OBC)] over a giant field divided into two phases. The authors discuss the difficulties faced by both phases of the pilot, and prove that a reliable 4D signal can be extracted over a Middle East carbonate reservoir. Introduction The time-lapse, or 4D, seismic method consists of repeating seismic survey acquisitions over the production time of a field. Newer vintages are compared with previous ones, and the signal differences are interpreted to characterize effects of the production spatially. Though this technique is mature and has been widely used in clastic reservoir environments, it is still used rarely, in operational terms, to monitor carbonate fields. An opportunity for a 4D proof-of-concept program in a Middle East marine carbonate environment was identified during a new OBC seismic acquisition in 2013. While the survey was intended for 3D imaging purposes, the operator decided to acquire a 4D pilot over a test area of approximately 25 km2 (Phase 1) while repeating as best as possible the 1994 acquisition design (baseline for this 4D study). The goal was, first, to process this test, and then, if a reliable 4D signal (above noise level) could be established, to propose interpretation in accordance with the field-production mechanisms. Field-Production and 4D Monitoring Objectives The principal oil-producing reservoir belongs to the Upper Jurassic and is a mixture of limestones, dolomite, and anhydrite. It contains the primary 4D monitoring target for this pilot. First oil was produced in the 1960s, followed by peripheral water injection in the 1970s and crestal gas injection in the 1990s. Thus, the 1994 4D baseline survey is an OBC seismic acquired after a rich and complex production history. Four-dimensional monitoring is justified by the fact that many expensive wells are drilled every year and their positioning is not straightforward. In particular, the crucial fluid-movement prediction (gas and water) is challenging and, thus, is considered the main monitoring objective. Phase 1 Acquisition Status Repeating baseline acquisition parameters during the monitoring survey is crucial. Any deviation from this principle is likely to generate a 4D noise that will be difficult to remove. In this pilot, taking advantage of a seismic crew mobilization for a modern wide-azimuth OBC acquisition, the field operator decided to try to repeat, in a small patch, an older OBC survey as a 4D pilot. In fact, this legacy vintage, which has a very different narrow-azimuth design, only was repeated over three swaths. The geometrical repeatability was good, except in the obstruction areas.

A new approach for determination of carbonate rock electrostatic double layer variation towards wettability alteration

Focus on the molecular scale of low salinity brine effects seems to be necessary to clarify the possible mechanisms of carbonate rock wettability alteration. This study aimed at investigating the effects of different operational parameters such as pH, salinity and types of ions on wettability alteration (WA) during low salinity brine injection as a tertiary recovery process. In the present study, using the electrostatic double-layer concept and molecular behavior, along with a good view of the past studies, led to the justification of the obtained results. The studied reservoir is one of the Middle East carbonate reservoirs which is considered for low salinity brine injection plan. Although the concept of ζ potential is ill-defined in electrostatic or/and electrokinetic topics, nonetheless, to the extent possible, has been tried to use this concept to illustrate and justify underlying mechanism during low salinity process beneficially.Resultant findings have shown that pH value directly affects carbonate rock powder ζ potential and determine the type of surrounding ions that form Stern layer and ion distribution in diffuse layer as well. A close examination at two temperatures of 25 °C and 80 °C, showed that active ions in WA e.g. Ca2+ and Mg2+ and SO42− as an agent facilitator to access active ions to the rock powder surface, have profound impacts on the Stern layer. The obtained optimal ions concentrations, (i.e., 1000 ppm sulfate + 1000 ppm magnesium @ 80 °C) and (500 ppm calcium and 800 ppm sulfate @ 25 °C) have changed the ζ potential of oil wet rock powder in Seawater form −23.6 mV to −6.71 mW and −8.7 mV respectively, using a new designed procedure. In the present study, influence of ion valence on the electrostatic double layer variation of an oil-wet rock powder has been led to directly link this alteration to the wettability state changes. Therefore, this approach could be very helpful to monitor the wettability state of the rock powder in molecular scale.

Optimum development options and strategies for water injection development of carbonate reservoirs in the Middle East

Abstract Through the research on several carbonate reservoirs developed in the Middle East, the basic characteristics of different types of carbonate reservoirs are determined, and a set of high-efficiency water injection development options and strategies are presented. Hidden baffles and barriers exist in carbonate reservoirs in the Middle East, so the reservoirs could be divided into different separated development units based on the baffles and barriers characteristics. Flexible and diverse profile control techniques such as high angle wells and simple and applicative zonal water injection have been introduced to improve the control and development degree of reservoirs. Three principal water injection development methods suitable for different carbonate reservoirs in the Middle East are proposed, including the combination of crestal gas injection and peripheral water injection, bottom interval injection and top interval production (buoyancy underpinning), and “weak point and strong plane” area well pattern. Based on the characteristics of very low shale content, fast and far pressure transmission in the Middle East carbonate reservoirs, a large well-spacing flood pattern is recommended, and reasonable development strategies have been made such as moderate water injection rate and maintaining reasonable production pressure drawdown and voidage replacement ratio, so as to maximize the recovery of reservoirs in the none or low water cut period.

Evaluation of low-salinity waterflooding in Middle East carbonate reservoirs using a novel, field-representative coreflood method

Low-salinity waterflooding attempts to improve recovery by reducing the salinity of the injection water, where the wettability alteration towards more water-wet state of the reservoir rock is believed to be the leading mechanism. This technology has received significant interest and a rich body of unsteady-state coreflooding test data has been reported in the past few years. However, capillary end-effect driven artifacts in conventional unsteady-state coreflooding could hinder proper understanding and interpretation of the measured results. We have developed a modified steady-state fractional-flow method to minimize capillary end effects. The fractional-flow analysis and simulation illustration of the new method has been published earlier by Gupta et al. (2015). In this work, we applied this new method to several Middle East carbonate reservoirs where slight changes in relative permeability consistent with a change in wettability can be observed but the overall uplift in recovery was very small. In addition, the results from the new method and the conventional coreflooding method were compared in selected cases to demonstrate the benefit of the new method in minimizing capillary end effect artifacts. Overall, this work demonstrates an improved laboratory screening methodology for low-salinity waterflood and similar EOR methods. The results of this work highlight the potential as well as challenges in low-salinity waterflooding in carbonates as a practical EOR technology.

Physical Simulation of Colayer Water Flooding in Low Permeability Carbonate Reservoir in Middle East

To study the flow mechanism under different displacement modes of low permeability carbonate reservoir in the Middle East and to improve the utilization of various types of reservoirs, the physical simulation experiments of water flooding by different displacement methods were carried out. Selecting two types of rock samples with different permeability levels, two-layer coinjection and separated production experiments by samples I and III and conventional water flooding experiments by samples II and IV were carried out. In addition, by using low magnetic field nuclear magnetic resonance, the development effect of microscopic pore structure under the different injection-production models was analyzed. Results show that, compared with the coinjection, the recovery rate of sample I was higher than II, 19.30%; sample III was lower than IV, 23.22%; and the comprehensive recovery degree reduced by 3.92%. NMR data also show that the crude oil is mainly distributed in the large pore throat; after water flooding, the displacement is also within the large pore throat, whereas the small pore throat is mainly obtained by the effect of infiltration absorption. The above studies provide a laboratory basis and foundation for the further development of low permeability carbonate reservoir in different Middle East strata.

A Case Study on Miscible and Immiscible Gas-Injection Pilots in a Middle East Carbonate Reservoir in an Offshore Environment

Summary Hydrocarbon-gas injection is one of the most widely applied processes in the oil industry and is a promising enhanced-oil-recovery (EOR) method for use in Middle East carbonate oil fields. Gas injection improves the microscopic-displacement efficiency and generally acts as pressure maintenance; however, unfavorable mobility ratio can negatively affect the ultimate recovery because of viscous fingering and gravity override. This paper describes two gas-injection pilots that have been implemented in offshore Middle East carbonate reservoirs: a secondary and a tertiary gas injection through line drive to assess injectivity, productivity, macroscopic-sweep efficiency, flow assurance, and operational efficiency in a field that has a long water-injection history. A strong monitoring plan, including an observer well, was applied through time-lapse saturation logging, pressure measurements, production testing, and a tracer campaign to evaluate the pilot efficiency and address key uncertainties upfront before full-field application. This paper describes the pilot performance in the context of full-field development, local- and macroscopic-displacement efficiency, flow-assurance issues, and operational learnings. The gas-injection performance is strongly affected by reservoir heterogeneity, gravity segregation, and the existing pressure gradient, and the history match performed indicates near-miscible or miscible behavior depending upon local pressure regimes, which thus govern the ultimate recovery. The history match also shows that for the same pilot, performance can be further improved through water-alternating-gas (WAG) injection, resulting in a viable development scheme for full-field implementation.

Miscible and Immiscible Gas-Injection Pilots in a Middle East Offshore Environment

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 18513, “A Case Study on Miscible and Immiscible Gas-Injection Pilots in a Middle East Carbonate Reservoir in an Offshore Environment,” by Jitendra Kumar, Pawan Agrawal, and Elyes Draoui, Abu Dhabi Marine Operating Company, prepared for the 2015 International Petroleum Technology Conference, Doha, Qatar, 7–9 December. The paper has not been peer reviewed. Hydrocarbon-gas injection improves microscopic-displacement efficiency and generally acts as pressure maintenance; however, unfavorable mobility ratio can affect the ultimate recovery negatively because of viscous fingering and gravity override. This paper describes a gas-injection pilot that has been implemented in offshore Middle East carbonate reservoirs (a second pilot is described in the complete paper) to assess injectivity, productivity, macroscopic-sweep efficiency, flow assurance, and operational efficiency in a field that has a long water-injection history. Introduction The carbonate field is part of the Lower Cretaceous Lower Lekhwair formation. The field is divided into A, B, and C reservoirs, 20 to 35 ft thick individually. Each reservoir is vertically separated by nonpay tight intervals of similar thickness, composed of argillaceous limestone, isolating each reservoir from the others. Depending on the reservoir, oolitic shoal facies can be more abundant. Near the flank area, the formation is water-wet, and, as one moves toward the crestal area, the formation becomes oil-wet. The reservoir fluid is undersaturated at initial pressure of 4,200 psig at datum depth and a temperature of 220°F. Oil gravity is 40 °API, and oil contains 1–2 mol% carbon dioxide and an insignificant amount of hydrogen sulfide. All three reservoirs have common contact and similar oil properties, with a strong compositional gradient. Production from the field started in the late 1960s through natural depletion, which indicated weak aquifer support. Before pilot implementation, laboratory experiments were performed to determine the feasibility of hydrocarbon-gas injection. Pressure/volume/temperature experiments showed that the minimum miscibility pressure (MMP) is approximately 4,500 psia, which is higher than initial reservoir pressure, but the crude oil has a strong swelling effect. Unsteady-state coreflood experiments performed with a 200-cm-long core showed a recovery of 70% for immiscible flood and a recovery of 92% for miscible flood. Full-field compositional simulation of gas injection incorporating a tuned equation of state indicated significant incremental oil and reasonable pressure support.

An integrated approach for relative permeability estimation of fractured porous media: laboratory and numerical simulation studies

Most carbonate reservoirs in Middle East are characterized as porous fractured reservoirs. Estimation of relative permeability of these highly heterogeneous reservoirs is challenging due to the existence of discontinuity in the fluid flow fractured porous media. Although relative permeability is an essential data for simulation of flow in fractured media, few attempts have so far been made to estimate the relative permeability curves. Most notable are the studies by Akin (J Pet Sci Eng 30(1)1–14, 2001), Al-sumaiti and Kazemi (2012), and Fahad (2013). This paper presents an integrated approach to history matching the oil drainage tests, which were carried out by unsteady state, on glass bed models with a single fracture at different orientations and to estimate the relative permeability curve. The integrated approach includes an inversion algorithm coupled with forward numerical modeling of fluid flow. The history matching of the displacement test data was obtained by using the Levenberg–Marquardt algorithm to minimize the error between the simulated and experimental data. In this algorithm, Corey-type power law is used to create relative permeability curves during the optimization procedures. The forward modeling is a 3D multiphase fluid simulator for flow through discrete fractures. Numerical results of fluid flow profiles and the optimized relative permeability curves for single fracture with different orientations and experimental validation with oil drainage tests are presented. The results of the optimized relative permeability data for single fracture are in a good agreement with the data derived by the correlation of Fahad (2013). These results prove that the presented approach can be used to upscale the relative permeability curve from laboratory scale to reservoir grid scale. The work on the upscaling of the estimated relative permeability curve of fractured porous media is under preparation and will be published soon.

Hydrocarbon-Mobility Steering for Optimum Placement of a Power Water Injector

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 164282, ’Hydrocarbon-Mobility Steering for Optimum Placement of a Power Water Injector Above Tar Mats - A Case Study From a Light-Oil Carbonate Reservoir in the Middle East,’ by Craig Saint and Thomas Glowig, Baker Hughes, and Ashis S.S. Swain, Nasser A. Al-Khaldi, Mohd. H. Al-Otaibi, Abdul Aziz Al Ghareeb, and Ahmad Bader Al Bader, Khafji Joint Operations, prepared for the 2013 SPE Middle East Oil and Gas Show and Exhibition, Manama, Bahrain, 10-13 March. The paper has not been peer reviewed. Tar mats are encountered in many Middle East carbonate reservoirs. In cases in which tar acts as a flow barrier between water and light oil, water injectors work most efficiently when placed horizontally immediately above the tar mat to maintain pressure support during production. As this strategy is pursued, a real-time tar-detection method is needed while drilling. The low mobility caused by tar can be detected with a formation-pressure- while-drilling (FPWD) tester, while a nuclear-magnetic-resonance (NMR) tool provides oil-viscosity estimation. Introduction The Ratawi limestone reservoir was discovered in 1963 in the offshore Neutral- Zone Concession area between Saudi Arabia and Kuwait. The production of light sour crude oil commenced in 1966. After an increase in gas/oil ratio and a sharp drop in reservoir pressure occurred, dump-water injection was started in 1975. Until recently, peripheral dump-water injection was used. Geologically, the reservoir is divided into three units, Units A, B, and C from top to base, respectively. Of these, Unit C is the main producing unit. The top of Unit C is considered as a possible sequence boundary/unconformity. Units A and B represent initial flooding over Unit C. The two units are composed of alternating porous limestone and less-porous or tight limestone, and show overall transgressive-system tract sequence. The heavy-oil zone was recognized above the oil/water contact. Additional drillstem tests and investigation of the separation between shallow and deep resistivity indicated fieldwide distribution of the heavy-oil zone. Wireline NMR and pressure data indicated presence of a tar/asphaltene zone in the heavy-oil zone. The operator’s strategy was to carry out peripheral water injection, placing the injectors above and as close as possible to the heavy-oil/tar zones, enabling better sweep and volumetric displacement of light oil toward potential producers. The reservoir characterization around the injector locations is critical for assessing carbonate heterogeneity, diagenetic uncertainty, asphaltene presence, and a transition zone of heavy-to-light oil. Assessment of risk-evaluating conventional- wirelinelog responses, seismic attributes, and nearby well dynamic information resulted in good prognosis of the area for deciding the entry point or landing point of the injectors and was crucial in well.placement. Offshore operations did not allow evaluation of the tar/asphaltene zone in each well because of higher operating costs from drilling a pilot hole. In recent wells, the placement was achieved on the basis of mobility steering as close as possible to the heavy-oil/tar zone.

Well-Log Evaluation of Vuggy Carbonate Reservoir in Middle East

The typical characteristics of carbonate reservoir is heterogeneous. The reservoirs were deposited in slope of marginal neritic carbonate plat form and marginal reefs in Middle East Oil Field. The vuggy carbonate reservoir pore systems include intergranular pores, mould pores, intercrystal pores, micropores and dissolution fracture. I t can be divided into separate vugs and touching vugs on the basis of vug interconnection. The goal of well-log evaluation is to describe the spatial distribution of petrophysical parameters, such as porosity and permeability. Well-log evaluation and core analyses provide quantitative measurements of petrophysical parameters in the vicinity of the well bore. The key for quantifying physics models is buildup the relationship between the log data and the core analyses result. The purpose of reservoir evaluation is to use the Interactive Mineral Solver module of Interactive Physics software to solve for mineralogy, porosity and permeability. The result of the analyses shows that calculated parameters has high coherence with core sample test. For vuggy carbonate reservoir evaluation, It shows that accurate values of physics parameters can be predicted using selected module in well-log data processing and interpretation.

Application of Monte Carlo to Improve the Accuracy of Identifying Fracture by Conventional Logs

Because of the limitation of logging instrument and tools resolution and response characteristics, the accuracy of identifying fracture is relatively low. This gives severe impact on accurate interpretation and evaluation of reservoir. In this paper, Monte Carlo simulation is applied to take its advantage on solving uncertain and stochastic problem to improve the accuracy of conventional logs identifying fracture of Carbonate reservoir in Middle East. According to the contrast result with core and image logging and well test data, this method is proved to be effective. It has an important significance for fracture identification in the situation of lack of image logging data but only conventional logs.

Q&A with Sami Iskander

Oil prices, profits, and capital spending are on the rise, and future hydrocarbon demand appears robust. Do you expect the industry to enjoy a sustained boom? All indicators point to a sustained period of strong activity. Two things are key. First, the industry must add production capacity to meet increasing demand. Second, it must also replace production lost to the decline of the aging production base. With E&P spending increasing to record levels, with only a thin margin existing of excess supply over demand, and with oilfield services' human and equipment resources stretched, we see no immediate drop in activity. How have the sustained high oil prices affected Schlumberger's business and operations? Last year set new records for Schlumberger activity as the price of oil allowed the E&P industry to increase spending. This year looks even stronger as more companies return to exploration-type work, and this is of particular significance to us because we have a wide range of technologies well suited to exploration, such as the Scanner family. What is the significance of the Scanner family of wireline measurements introduced late last year? The Scanner family is a step change in technology and in the benefits it brings to how our clients populate reservoir models with their data. What kind of field test results have you had thus far? Results have been great in a wide range of applications for each technology worldwide. Client acceptance has been very encouraging, and the number of case studies is growing. Where do you see its main applications? Scanner applications are numerous throughout all the oil and gas upstream processes. The Rt Scanner runs with our Platform Express service in standard induction applications, with its major advantages apparent in thin beds, low-resistivity pay, and high-formation-dip environments. The Sonic Scanner is a service applicable to nearly every oilfield discipline: meeting geophysical challenges, detecting anisotropy accurately as low as 2%, delivering a clear understanding of formation-integrity issues likely to happen during production, and allowing completion engineers to make the best decisions on their completion and fracture designs. MR Scanner provides nuclear-magnetic-resonance measurements to help resolve petrophysical challenges in a variety of environments, including unknown or varying salinities, low-resistivity or low-contrast pay zones, and/or thin beds. This is made possible using a single pass with multiple depths of investigation. MR Scanner provides detailed formation evaluation of the near-wellbore region, fluid identification, and in-situ hydrocarbon characterization. In Middle East carbonate reservoirs, which are normally difficult to interpret using conventional resistivity techniques, the MR Scanner service has clearly distinguished hydrocarbon-bearing zones from the water zones by use of patented interpretation techniques. What other technologies are you working on that will address key production issues facing the industry? To address the pressing production issues, we are launching two new cased-hole Scanner technologies: the Isolation Scanner and Flow Scanner. The next-generation zonal-isolation evaluation service is the Isolation Scanner for the latest lightweight and foam cements as well as traditional and heavy weight cements. It measures radially and deeper toward the formation, confirming zonal isolation, pinpointing channels in the cement, and ensuring confident squeeze or no-squeeze decisions. Because of its increased depth of investigation, the Isolation Scanner also provides detailed information about casing and casing-within-casing eccentralization, allowing for better identification of whipstock locations for sidetracking, while its internal-diameter and thickness measurements identify corrosion and drilling-induced wear.