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Results
Acid Fracturing Experience In Naturally Fractured – Heavy Oil Reservoir, Bati Raman Field
Gozel, Mustafa Erkin (Turkish Petroleum Corporation) | Uysal, Serkan (Turkish Petroleum Corporation) | Ayan, Cosan (Turkish Petroleum Corporation) | Yuce, Ugur (Turkish Petroleum Corporation) | Ozturk, Egemen (Turkish Petroleum Corporation) | Gune, Huseyin Kerem (Turkish Petroleum Corporation) | Yilmaz, Ismail Sahin (Turkish Petroleum Corporation) | Oymael, Mustafa (Turkish Petroleum Corporation) | Eswein, Edmund (Schlumberger)
Abstract Bati Raman field, with an original oil in place of 1.85 billion barrels, is a naturally fractured carbonate reservoir containing 9-13 °API extra heavy oil with viscosities varying from 300 to 600 cp. Not only a wide range of pilot EOR schemes including gas, thermal and chemical methods, but also novel IOR applications have been tried in the field. CO2 injection was a game changer for this reservoir which has been the main drive mechanism since 1987. Since then, various techniques are applied to further improve the production performance of the field. This study focuses on the design and outcome of the pilot acid fracturing treatments in selected three wells in the tighter and less fractured southeastern part of the reservoir. State of the art planning included full evaluation of well integrity, cement bond and open hole logs, geomechanics studies augmented with rock mechanics laboratory tests. Laboratory tests were also conducted focusing on sludge/emulsion forming tendencies and acid reaction rates. Using these results, expected fracture dimensions were predicted along with production forecasts. In all wells, pre-frac calibration tests were conducted to assess stress conditions and fracturing parameter optimization. The treatments were then executed, improving the procedure between each well for acid fracturing. Injections schemes were operationally efficient and various diversion techniques were used to mitigate the presence of naturally fractured zones. Pre and post-job temperature logs helped to evaluate each treatment. The results from the wells were very positive; total production rate increased about fivefold, observed within one month after the treatments. No considerable change in water or CO2 production in the wells was observed which had been one of the most important objectives during the candidate selection process. One well was suspended, which turned out to be one of the producers of the field after acid fracturing treatment. Each well had a different post-frac production performance because of its geological characteristics and flow dynamics, making the study more valuable for better understanding of the process. The wells are still on critical observation to assess the nature of the created fractures and their longevity in the long run. Even after twelve to fifteen months of production, which is the breaking point period for fracture closure, the overall production level of the wells was double compared to pre-frac rates. One well still has a fracture dominated production while other two changed back into its pre-frac rates. Based on these results, acid fracturing campaign was extended in the area which is currently under evaluation.
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Asia > Middle East > Turkey > Bati Raman Field (0.99)
- North America > United States > Texas > East Texas Salt Basin > Fallon Field (0.94)
A New Environmentally Friendly Technique to Extend the Limits of Transient Pressure Testing and Sampling Using Pipe Conveyed Open Hole Wireline Formation Testing Tools
Ayan, Cosan (Schlumberger) | Mishra, Vinay (Schlumberger) | Eriksen, Kåre-Otto (Statoil) | Van der Hoek, Jeroen (Statoil) | Thorne, Tyson (Statoil)
Abstract Transient well testing is one of the most critical components of reservoir evaluation due to its impact on a project's key economic parameters such as reserves and producibility. A conventional cased hole well test involves casing off the well, installing process equipment, completing the well perforating, flowing the well to surface and flaring the produced fluids. While the data acquired from conventional well tests is very useful; a large number of wells are not tested due to time, cost and regulatory constraints. In such situations with no well test, operators are obliged to take important decisions from a relatively small amount of reservoir information and hence take risks associated with subsurface uncertainties. To help reduce the development risks, a new pipe conveyed testing tool referred as Formation Testing While Tripping (FTWT) was developed. The new testing tool integrates a number of innovations allowing pumping large fluid volumes at higher rates with extended testing time and improved well noise control. This is done by circulating the produced fluids out of the wellbore during pumping out formation fluids. The new hardware can be combined with wireline sampling and downhole fluid analysis modules allowing to achieve overall well testing objectives; including collecting pressure transient data, real time fluid typing and capturing cleaner and larger volume fluid samples, while increasing the radius of investigation for better characterization of any reservoir heterogeneities compared to conventional wireline formation testing techniques. In this paper, we introduce the new testing technique, which has recently been utilized in the Norwegian sector of the North Sea and offshore Canada. In one well, following the FTWT surveys, Drill Stem Tests (DST) were also conducted for comparison. The field examples and comparison with DST's indicated that the new method can provide valuable reservoir information while also showing its current limitations.
- North America > United States > Texas (0.28)
- Europe > United Kingdom > North Sea (0.24)
- Europe > Norway > North Sea (0.24)
- (2 more...)
- North America > Canada (0.89)
- Europe > United Kingdom > North Sea (0.89)
- Europe > Norway > North Sea (0.89)
- (2 more...)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Formation test analysis (e.g., wireline, LWD) (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Mapping and Modeling Large Viscosity and Asphaltene Variations in a Reservoir Undergoing Active Biodegradation
Jackson, Richard R. (Schlumberger) | Zuo, Julian Y. (Schlumberger) | Agarwal, Ankit (Schlumberger) | Herold, Bernd (Cairn India Ltd) | Kumar, Sanjay (Cairn India Ltd) | Santo, Ilaria De (Schlumberger) | Dumont, Hadrien (Schlumberger) | Ayan, Cosan (Schlumberger) | Mullins, Oliver C. (Schlumberger)
Abstract Viscosity is one of the key reservoir fluid properties. It plays a central role in well productivity and displacement efficiency and has a significant impact on completion strategies. Accurately assessing areal and vertical variations of viscosity will lead to more realistic reservoir simulation and optimal field development planning. Downhole fluid analysis (DFA) has successfully been used to measure the properties of reservoir fluids downhole in real time. DFA has excellent accuracy in measuring fluid gradients which in turn enable accurate thermodynamic modeling. Integration of DFA measurements with the thermodynamic modeling has increasingly been employed for evaluating important reservoir properties such as connectivity, fluid compositional and property gradients. The thermodynamic model is the only one that has been shown to treat gradients of heavy ends in all types of crude oils and at equilibrium and disequilibrium conditions. In addition, fluid viscosity depends on concentration of heavy ends that are associated with optical density measured by DFA. Therefore, mapping viscosity and optical density (heavy end content) is a new important application of DFA technology for use as assessment of reservoir architectures and a mutual consistency check of DFA measurements. In this case study, a very large monotonic variation of heavy end content and viscosity is measured. Several different stacked sands exhibit the same profiles. The crude oil at the top of the column exhibits an equilibrium distribution of heavy ends, SARA and viscosity, while the oil at the base of the oil column exhibits a gradient that is far larger than expected for equilibrium. The fluid properties including SARA contents, viscosity and optical density vary sharply with depth towards the base of the column. The origin of this variation is shown to be due to biodegradation. GC-chromatographs of the crude oils towards the top of the column appear to be rather unaltered, while the crude oils at the base of the column are missing all n-alkanes. A new model is developed that accounts for these observations that assumes biodegradation at the oil-water contact (OWC) coupled with diffusion of alkanes to the OWC. Diffusion is a slow process in a geologic time sense accounting for the lack of impact of biodegradation at the top of the column. An overall understanding of charging timing into this reservoir and expected rates of biodegradation are consistent with this model. The overall objective or providing a 1st-principles viscosity map in these stacked sand reservoirs is achieved by this modeling. Linking DFA with thermodynamic modeling along with precepts from petroleum systems modeling provides a compelling understanding of the reservoir.
- Asia > India (0.30)
- North America > Canada (0.28)
- Europe > United Kingdom (0.28)
- Europe > Netherlands (0.28)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.87)
- Geology > Geological Subdiscipline > Geochemistry (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.48)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Fatehgarh Formation (0.99)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
Downhole Viscosity Measurement: Revealing Reservoir Fluid Complexities and Architecture
Mishra, Vinay K. (Schlumberger) | Barbosa, Beatriz E. (Schlumberger) | LeCompte, Brian (Murphy Oil) | Morikami, Yoko (Schlumberger) | Harrison, Christopher (Schlumberger) | Fujii, Kasumi (Schlumberger) | Ayan, Cosan (Schlumberger) | Chen, Li (Schlumberger) | Dumont, Hadrien (Schlumberger) | Diaz, David F. (Schlumberger) | Mullins, Oliver C. (Schlumberger)
Abstract Knowledge of formation fluid viscosity and its vertical and lateral variations are important for reservoir management and determining field commerciality. Productivity and fluid displacement efficiency are directly related to fluid mobility, which, in turn, is greatly influenced by fluid viscosity. Therefore, viscosity is a critical parameter for estimating the economic value of a hydrocarbon reservoir and also for analyzing compositional gradients and vertical and horizontal reservoir connectivity. The conventional methods for obtaining formation fluid viscosity are laboratory analysis at surface and pressure/volume/temperature (PVT) correlations. However, deducing viscosity from correlations introduces uncertainties owing to the inherent assumptions. Surface viscosity measurement may be affected by irreversible alteration of the sampled fluid through pressure and temperature changes, as well as related effects of long-term sample storage. A new downhole sensor for a wireline formation tester tool has been introduced to measure the viscosity of hydrocarbons. The new viscosity sensor uses a vibrating-wire (VW) measurement method with well-established analytical equations for interpretation. Downhole field testing of an experimental prototype has been conducted, with extensive laboratory tests to validate the sensor performance in viscosities ranging from light to heavy oil and at a wide range of well environments. The vibrating wire viscometer sensor meets requirements not only for measurement performance, but also for operations in downhole applications, and possesses the following properties:
- Asia > Middle East (0.93)
- North America > United States > Texas (0.68)
- Africa (0.68)
- South America > Atlantic Basin (0.89)
- North America > Atlantic Basin (0.89)
- Europe > Atlantic Basin (0.89)
- Africa > Atlantic Basin (0.89)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
- (3 more...)
IPTT vs. Well Testing and Deconvolution Applications for the Thinly Bedded Reservoirs: Case Studies from the Gulf of Thailand
Kiatpadungkul, Wiriya (Schlumberger) | Daungkaew, Saifon (Schlumberger) | Chokthanyawat, Suchart (Schlumberger) | Promkhot, Soontorn (Schlumberger) | Ayan, Cosan (Schlumberger) | Houtzager, Johan Frederik (Pearl Oil (Thailand) Ltd) | Platt, Christopher J. (Pearl Oil (Thailand) Ltd) | Storer, Alexander James (Pearl Oil (Thailand) Ltd) | Tabmanee, Piyatad (Pearl Oil (Thailand) Ltd) | Panyarporn, Pantaporn (Pearl Oil (Thailand) Ltd) | Voradejviseskrai, Suttapan (Pearl Oil Thailand Ltd) | Limniyakul, Theeranun (Pearl Oil (Thailand) Ltd) | Last, Nick (Pearl Oil (Thailand) Ltd)
Abstract In Asia Pacific region, there are many thinly bedded reservoirs which are composed of interbedded porous and permeable sands with variable proportions of thin silt and clay beds. These reservoir sand bodies range from millimeters to tens of meters in thickness. Though the reservoirs are highly permeable, reservoir heterogeneity caused by silt and clay laminations affect recovery and sweep efficiency. The typical way to test such formations is to use full scale well testing, even for relatively thin zones. In the Gulf of Thailand (GoT), a Tubing Stem Test (TST) is widely used to test each individual zone for reservoir parameters. During a TST, quartz gauges are run on wireline and the selected zone is perforated. While wireline Formation Testers (FT) have also been increasingly used in the GoT for measuring formation pressure, mobility and collecting reservoir fluids, more advanced FT tools, e.g. dual packers and Downhole Fluid Analyzers (DFA) were recently introduced to test each zone to help defining reservoir characteristics in more detail. A single probe FT deployed for pretests and fluid sampling can be used to obtain transient data during the shut-in periods after sampling in relatively thin zones. The data from these Interval Pressure Transient Tests (IPTTs) can be used to interpret reservoir parameters such as vertical to horizontal permeability ratio and horizontal permeability. This paper discusses the uses of such smaller scale pressure transient data (single probe, dual packer formation testers) and full scale well testing using a simulation model and actual field data from the GoT. First, a single well simulation model is used to investigate the effects of thinly bedded shales at different scales on pressure transient data. The actual field data were then analyzed to obtain reservoir parameters and compared with core and PVT lab results. This paper also investigates the use of deconvolution applied to pressure transient tests of different scales to understand the effect of reservoir parameters using simulated and field data. Introduction Thinly Bedded Reservoirs in the Gulf of Thailand In the Tertiary Basins of the Gulf of Thailand and Northern Malay Basin, thinly bedded hydrocarbon sandstone reservoirs have been encountered in several geological settings. In the northern Gulf of Thailand, Kra Basin, subaqueous lacustrine fan delta sandstones of between 1 to 4 feet have developed as a result of episodic deposition. In the Southern part of the Pattani Basin adjacent to the Narathiwat High, thinly bedded reservoirs of less than 1 to 7 ft were deposited in marginal marine, tidally influence estuarine channel fills settings and also in more proximal fluvial crevasse splay deposits.
- North America > United States > Texas (0.68)
- Asia > Thailand > Gulf of Thailand (0.54)
- Asia > Thailand > Pattani > Pattani (0.24)
- Asia > Thailand > Narathiwat > Narathiwat (0.24)
- Geology > Sedimentary Geology > Depositional Environment (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.39)
- Asia > Vietnam > Gulf of Thailand > Pattani Basin (0.99)
- Asia > Thailand > Gulf of Thailand > Pattani Basin (0.99)
- Asia > Thailand > Gulf of Thailand > Kra Basin (0.99)
- (5 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- (2 more...)
Abstract Production tests are usually taken to be the gold standard by which to appraise the reservoir. The ability to flow the zone after it has been cased and perforated provides the best approximation to what actual reservoir performance will be. The complete interval is perforated, usually with the same completion technique that the reservoir will be developed with. Large volumes of fluid can be flowed which ensures representative samples are acquired and also allows for deep depth of investigation during the pressure transient analysis of the build-up. However, such a wealth of information does not come easily. In certain environments a full production test can takes weeks and cost many millions of dollars. And in addition to the cost is the reduced drilling efficiency – in environments with limited drilling seasons the time taken to perform a production test will reduce the number of wells that can be drilled in a season. An alternative to the above approach is the wireline formation tester (WFT). The pump-out WFT has been in use for over twenty years. Although these tools can never hope to fully replace the production test, a judicious combination of WFT and DST data can answer many of the pertinent issues for reservoir evaluation and in some cases address the requirements of state or financial regulatory bodies. In this paper we present a reservoir analysis based on data acquired with a conventional DST and compare this to an analysis with data acquired using a wireline formation tester. The strengths, weaknesses and applications of each are discussed.
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Summary Reconstructing constant-rate drawdown-pressure response and its logarithmic time (or Bourdet) derivative by deconvolution from multirate pressure-transient data is very important for wellbore-/ reservoir-system identification and interpretation. In recent years, the use of pressure/rate deconvolution has increased considerably because of significant improvement of the algorithms. In this paper, we present a new deconvolution algorithm based on a weighted Euclidean norm in the Tikhonov (1963) regularized objective function so that one can assign weights to individual pressure- and rate-measurement points, and, thus, define different error estimates for different sections of the data. Incorporating such features into the deconvolution algorithm is very useful to mitigate the effects of unreliable pressure and rate measurements and the sections of the data not obviously consistent with the wellbore/reservoir model. We present two applications of the new algorithm using real field pressure/rate transient data sets. In addition to conventional drillstem-test (DST) well-test data, we apply the algorithm to wireline formation-tester (WFT) pressure transients, which are usually also referred to as interval pressure-transient tests (IPTTs). The results show that the new deconvolution algorithm presented in this paper is useful in interpreting pressure/rate transient data from both formation and well tests.
- Europe (0.94)
- North America > United States (0.93)
- Asia > Middle East > UAE (0.28)
Flow Unit Thickness and Permeability Evaluation in Horizontal Wells Using Logging While Drilling and Wireline Formation Tester Transient Data
Cig, Koksal (Schlumberger Middle East) | Ayan, Cosan (Schlumberger) | Mahruqy, Sultan (Petroleum Development Oman) | Al-Shamsi, Khalsa Abullah (Petroleum Development Oman)
Abstract Oil was discovered in a carbonate reservoir which indicated discontinuous and complex geological features. The carbonate field in the Sultanate of Oman is at the early stages of development and reservoir uncertainties are still significant. The uncertain geological features, proximity of possible faults and heterogeneous reservoir properties make horizontal well placement a difficult task. The latest logging while drilling (LWD) technology for well placement was utilized to track the distance to the upper flow unit of the reservoir. It was discovered that the formation was dipping upwards and had separate units. The lower flow unit boundary was uncertain due to the LWD distance detection limit. Flow unit thickness identification became an important task to understand the potential of the reservoir. The objective of this study in the complex reservoir is to present a new way to determine the flow unit thicknesses by utilizing the LWD and wireline formation tester (WFT) interval pressure transient tests (IPTT) data. IPTT tests with a dual inflatable packer in combination with LWD logs resulted in local horizontal and vertical permeabilities and flow unit thicknesses along the horizontal well. Integration of the two distinct logging methods helped accomplish not only the well geometry and local petrophysical properties, but also gave information on large scale properties. The wells were also surveyed with open hole logging tools to obtain sedimentary features, to collect necessary oil samples and to obtain reservoir properties such as faults information, saturations, permeabilities and in-situ rock stresses. Following data acquisition and joint evaluation, an integrated study was conducted for the field development. This paper presents an integrated solution of LWD logs and IPTT data evaluation. The approach had a considerable impact on field development plans and reserve calculations in the new and complex carbonate reservoir. Introduction Reservoir Geology The geology of the reservoir in the study presents a stratigraphic trap in an Upper Shuhaiba carbonate formation sealed by a shale layer above and by argillaceous limestone facies laterally. The reservoir units represent the shoaling and upper slope portion of clinoforms that prograde into the basin. Rudist /stromatoporoid bioherm and reworked facies ranging from fine to coarse grained have been encountered in addition to more common orbitolinid packstones and wackstones. The quality of the reservoir represents a complex relationship between primary depositional facies and subsequent diagenisis in the form of both cementation and leaching (Fig. 1). Obtaining core samples subsequently assists understanding the complexity of the lithology. The thickness and permeability distribution of the reservoir is difficult to foresee without extensive logging and testing. Location and distribution of the reservoir quality facies represent one of the major uncertainties for developing of the reservoir. Formation microresistivity imager logs provide the fracture and facies distribution of the rock textures with the correlation of cores collected (Wang et al. 2008). Seismic data gives some indications of these structures and a recent reprocessing allows partial answers for reservoir units in some areas.
- Asia > Middle East (0.90)
- North America > United States > Texas (0.69)
- Well Drilling > Drilling Measurement, Data Acquisition and Automation > Logging while drilling (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- (4 more...)
Abstract Following the introduction of pressure-rate (p-r) deconvolution techniques in 1960s, they have been investigated continually during the last two decades. Now most p-r deconvolution techniques are stable and have been used increasingly for analysis of pressure transient tests. A successful p-r deconvolution can transform a multirate pressure transient response to an equivalent constant-rate drawdown response for the entire test duration. It can help identify/confirm interpreted reservoir models and eliminates multirate superposition effects. However, the flow rate is usually not directly and continuously measured in conventional pressure-transient well tests, although it is measured reasonably accurately during interval pressure transient tests (IPTT) conducted by wireline formation testers (WFTs). Nevertheless, large uncertainties or errors associated with inaccurate rate data usually hinder the successful use of p-r deconvolution methods. When pressure data are available at both the source/sink and observation location(s), for instance interference tests, then pressure-pressure (p-p) deconvolution techniques, through which the flow rate is eliminated from the formulation, can be utilized for analysis of multipoint pressure transient data. Although p-p convolution/deconvolution was first introduced in 1991 by Goode et al. for interpretation of multi-point wireline formation tester pressure transient data, there have been only a few papers published in the literature about p-p deconvolution. In this paper, we investigate in detail the use of p-p deconvolution for interpretation of conventional multiwell interference and interval pressure transient tests. It is shown that the recent deconvolution algorithms developed for p-r deconvolution can also be used for performing p-p deconvolution by simply replacing the rate data in p-r deconvolution algorithms by the pressure change data recorded at the source/sink location or at one of the observation locations. In this paper, we use the Pimonov et al. (2009) p-r deconvolution algorithm that utilized a more general weighted least-squares objective function compared to previous techniques. We demonstrate the practical utility of p-p deconvolution by considering both synthetic and real (field) transient test data sets from IPTTs and multiwell interference tests. Introduction Focus in deconvolution has recently increased, following the introduction of more stable p-r deconvolution algorithms (von Schroeter et al. 2004; Levitan 2005; Levitan et al. 2006; Ilk et al. 2006; Onur et al. 2008; Pimonov et al. 2009). Ratepressure (r-p) deconvolution (Kuchuk et al. 2005) for decline curve analysis and multiwell p-r deconvolution (Levitan 2007) have also been used. Successful deconvolution of well test data or interval pressure transient test (IPTT) data enables the analyst to identify reservoir behavior without the effects of multirate production, as if the well had been flowing with a constant flow-rate from the start of the test period, but may still be affected by the wellbore storage if the flow rate is not measured at the sandface. This deconvolved constant-rate drawdown data increase the radius of investigation to the duration of the entire multiple flow and buildup tests; consequently it provides data for better reservoir characterization and reserve estimation.
- North America > United States > Texas (0.67)
- North America > United States > California (0.46)
Flow Unit Thickness and Permeability Evaluation in Horizontal Wells Using Logging While Drilling and Wireline Formation Tester Transient Data
Cig, Koksal (Schlumberger Middle East SA.) | Ayan, Cosan (Schlumberger) | Mahruqy, Sultan (Petroleum Development Oman) | Al-Shamsi, Khalsa Abullah (Petroleum Development Oman)
Abstract Oil was discovered in a carbonate reservoir which indicated discontinuous and complex geological features. The carbonate field in the Sultanate of Oman is at the early stages of development and reservoir uncertainties are still significant. The uncertain geological features, proximity of possible faults and heterogeneous reservoir properties make horizontal well placement a difficult task. The latest logging while drilling (LWD) technology for well placement was utilized to track the distance to the upper flow unit of the reservoir. It was discovered that the formation was dipping upwards and had separate units. The lower flow unit boundary was uncertain due to the LWD distance detection limit. Flow unit thickness identification became an important task to understand the potential of the reservoir. The objective of this study in the complex reservoir is to present a new way to determine the flow unit thicknesses by utilizing the LWD and wireline formation tester (WFT) interval pressure transient tests (IPTT) data. IPTT tests with a dual inflatable packer in combination with LWD logs resulted in local horizontal and vertical permeabilities and flow unit thicknesses along the horizontal well. Integration of the two distinct logging methods helped accomplish not only the well geometry and local petrophysical properties, but also gave information on large scale properties. The wells were also surveyed with open hole logging tools to obtain sedimentary features, to collect necessary oil samples and to obtain reservoir properties such as faults information, saturations, permeabilities and in-situ rock stresses. Following data acquisition and joint evaluation, an integrated study was conducted for the field development. This paper presents an integrated solution of LWD logs and IPTT data evaluation. The approach had a considerable impact on field development plans and reserve calculations in the new and complex carbonate reservoir. Introduction Reservoir Geology The geology of the reservoir in the study presents a stratigraphic trap in an Upper Shuhaiba carbonate formation sealed by a shale layer above and by argillaceous limestone facies laterally. The reservoir units represent the shoaling and upper slope portion of clinoforms that prograde into the basin. Rudist /stromatoporoid bioherm and reworked facies ranging from fine to coarse grained have been encountered in addition to more common orbitolinid packstones and wackstones. The quality of the reservoir represents a complex relationship between primary depositional facies and subsequent diagenisis in the form of both cementation and leaching (Fig. 1). Obtaining core samples subsequently assists understanding the complexity of the lithology. The thickness and permeability distribution of the reservoir is difficult to foresee without extensive logging and testing. Location and distribution of the reservoir quality facies represent one of the major uncertainties for developing of the reservoir. Formation microresistivity imager logs provide the fracture and facies distribution of the rock textures with the correlation of cores collected (Wang et al. 2008). Seismic data gives some indications of these structures and a recent reprocessing allows partial answers for reservoir units in some areas.
- North America > United States > Texas (0.95)
- Asia > Middle East (0.90)
- Well Drilling > Drilling Measurement, Data Acquisition and Automation > Logging while drilling (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- (4 more...)