A shallow, unconsolidated, sour heavy oil reservoir in North Kuwait is under primary production. Due to rapid decline in reservoir pressure, a development scenario was selected consisting of 10 years of water injection secondary recovery followed by enhanced oil recovery (EOR) polymer flood for which a pilot is being implemented. This pilot will provide vital information to establish feasibility for full-field implementation and in this paper, we describe the application of Interference Pressure Transient Test (IPTT) and stress testing. IPTT is utilized for proper understanding of the vertical permeability and permeability anisotropy (Kv/Kh) which are key for evaluating heavy oil sweep efficiency under injection. Stress testing will provide essential information about the cap rock integrity to monitor that water and polymer flooding is contained across the required reservoir. A combination of IPTT and stress testing utilizing the Wireline Formation Testing (WFT) tool and laboratory core analysis were the basis of a selected method for vertical permeability and permeability anisotropy determination. Laboratory measurement for permeability anisotropy has its own challenge due to unconsolidated nature of the formation. IPTT under such conditions can provide reliable and fast measurements, which can also help to calibrate the laboratory measurements later. Four EOR pilot vertical injectors wells were drilled in a symmetric 5-spot pattern, with a central vertical producer. Distance between the injectors is 60 meters, whereas each injector is at 50 meters spacing from the central producer. IPTT was carried out in all four EOR pilot wells, whereas this study involves only three of the injectors. Three-probe configuration along with advanced three-dimensional probe provided comprehensive evaluation for the sand and shaly reservoir intervals. It was observed that main sand body under consideration showed Kv/Kh ranging between 0.05 to 0.15. Some of the main shaly intervals were observed to be either fully isolating the sub-layers or have some vertical communication. It should be noted that downhole fluid analysis and sampling was conducted in one of the wells utilizing WFT. The obtained fluid properties were included in the IPTT analysis for more accurate results. The acquired data from three pilot wells were used to update the reservoir simulation models to have a more representative sweep efficiency evaluation utilizing polymer flooding for the planned EOR. It provides an efficient way to derive the vertical permeability and permeability anisotropy in the challenging unconsolidated formation. This paper adds to the literature of case studies where vertical permeability and permeability anisotropy have been obtained in the challenging environment of unconsolidated formation. It demonstrates how accurate planning combined with advanced technology and innovative workflow yielded the required input data for the dynamic reservoir simulation model.
Viscosity is driven by asphaltene content and is a key parameter in the development of heavy oil fields. Understanding fluid composition and temperature and pressure-induced changes in fluid viscosity is vital for an optimized production strategy and surface facility design. A recent field and laboratory study exemplifies the steps necessary to obtain the fit-for-purpose data from heavy oil samples. This paper presents the case study of a new downhole optical composition analysis sensor used during real-time downhole fluid analysis and sampling for the first time in a Kuwait heavy oil formation. The primary objectives of a sampling program are to confirm fluid indications on the openhole logs and collect crucial pressure/volume/temperature (PVT) samples. The downhole optical composition analysis sensor provides the information necessary to estimate a sample contamination level. It also indicates when the sample is sufficiently clean for PVT analysis. The samples should be acquired from the reservoir and maintained as single phase throughout transport to the laboratory. The pressure should be maintained higher than the asphaltene precipitation onset pressure and much higher than the bubblepoint. If the sample is not maintained higher than the asphaltene onset pressure, asphaltenes precipitate in the sample chamber and cannot be reconstituted as single phase in the laboratory. The new optical composition analyzer can also identify fluid stream components and their relative concentration in real time with laboratory-quality accuracy downhole. Near-infrared (NIR) sensors are most commonly used to identify fluid in the wireline formation tester (WFT). The sensors work well in light hydrocarbons. However, in heavy oil, the sensor performance degrades and fails to identify the contamination level accurately. The new multivariate optical computing (MOC) technique for downhole optical composition analysis overcomes this by performing a photometric detection with the entire relevant spectral range compared to spectroscopic analysis, which is only performed over a narrow band or sparse set of channels while traditional sensors are configured. The MOC sensor also recognizes in real time the chemical nature (optical fingerprint) of analytes (e.g., methane, ethane, propane, carbon dioxide, hydrogen sulfide, water, asphaltene, aromatics, and saturates) using all of the useful information in the optical spectrum. The real-time analyte chemical composition provided by the sensor is comparable to laboratory tests conducted on the collected PVT sample. Laboratory measurements on representative fluid samples from the correct locations early in the field development stage help develop an optimal field-development strategy. At the same time, sample integrity is maintained from the reservoir to the laboratory, which is vital. This paper discusses how the new optical compositional analysis sensor in combination with a high-resolution fluid identification sensor provides comprehensive and accurate downhole fluid composition in real time. This compares well with the laboratory-measured PVT analysis of heavy oil samples. The compositional analysis sensor optimizes pumpout time, thus helping obtain practically ideal contamination levels to begin the single-phase sampling process, which saves valuable rig time.
A heavy oil field in Northern part of Kuwait has developed which requires appropriate disposal of produced formation water. Some important questions for water disposal well planning include: Where to inject?Where to inject?What is the maximum operation pressure (MOP)?How far away the disposal wells should be spaced?How much water can be inject in each well? Integrated subsurface evaluation performed to address above questions. Seismic data provide a good overview lof the structuration and imporatant insight where sweet spots for injection may be found. Wireline logs and core information are used to derive petrophysical properties, characterize fracture, and gather geomechanical information. Injectivity tests established the injection rate and confirmed the estimated minimum horizontal stress. Analogue water injection data from nearby fields are used to provide information on the dynamic behavior of the reservoir, to reduce uncertainties owing to the limited injection rate data available. The integrated analysis of the relevant, available subsurface data reveals that the Tayarat formation has significant variations in lithologies, mineralogies, and mechanical properties. Important information such as the receiving zone thickness, fracture orientation, injection rate, and storage capacity have been derived. Based on this information, we have made important recomemndations on disposal well spacing and maximum operational operating pressure (MOP).
Challenging aspects to heavy oil field development are the large volume of data which is collected, in particular from cored evaluation wells, and the difficulty in evaluating of the quality of such data. This paper outlines an approach to summarize coring data and procedures from two heavy oil fields in North Kuwait, and then to compare those summaries with similar heavy oil operations in other countries, in order assess their quality and degree of representativeness. For two North Kuwait heavy oil fields, data was tabulated for the cumulative amounts of core cut and recovered relative to their field areas. This data was then further analyzed to summarize recovery by rock type, and assess the quality and quantity of plug samples collected. Benchmarks were established by summarizing core data from similar heavy oil operations in other countries, and the North Kuwait heavy oil data was then compared with those benchmarks. In a similar manner, documented core handling procedures for North Kuwait Heavy Oil operations were compared with procedures from similar heavy oil operations in other countries. The benchmarks which were used to compare North Kuwait Heavy Oil data summaries with other countries include the following: 1) Coring Well Area Coverage Densities; 2) Coring Well Vertical Coverage of Cap Rock and Reservoir Intervals; 3) Core Plug Sample Rate and Survival Rate; and 4) Core Handling Procedures and Volume of Coring. For many of the benchmarks used, North Kuwait heavy oil operations compare favorably with similar operations from other countries. However areas of improvement were identified from these benchmarks in terms of areal core coverage, vertical core coverage, core plug rates and core handling procedures. It is expected that these improvements, when implemented, will lead to a more representative sampling of the areas and rock types (reservoir rocks, baffles and cap rocks) in North Kuwait. This in turn should lead to a better understanding of fluid volumetrics, reservoir characterization and subsequent life of field development. As well by applying a focused approach to future coring operations, a significant cost savings is expected relative to original evaluation well plans. A significant product from this study is a large summary database of all coring information for two North Kuwait heavy oil fields, which can be queried by area, rock type and sample type. This data base has been compared with similar operations in other countries using a series of benchmarks. Planned future coring and sampling operations have been modified through the use of this benchmarking tool.
Free gas along with heavy oil production affects the progressive cavity pump (PCP) performance. This necessitates the strategy to perforate away from the free gas zone. To be able to do this, it requires an integrated approach to evaluate and map the spread of the free gas accumulation in the field. The paper shall present how this resulted in improved well performance with less free gas interference. The methodology included the understanding of the production data, sub-surface geology and petrophysics; reservoir heterogeneity and free gas presence from wireline logs, core data and isotope analysis of gas collected during mud-logging and creation of maps and cross-sections showing both vertical and aerial spread of free gas accumulation. This was then integrated with existing production and well management practices, along with numerical simulation results. Such in-depth analysis helps to bring significant changes in well completion strategy and is a vital contribution to the WRFM strategy. Unlike in conventional fields where depth is more and buoyancy pressures are large, gas can easily displace oil to accumulate in structural highs, in shallow heavy oil fields, free gas accumulation is a result of combination of structural and stratigraphic entrapment process. Vertical migration and lateral migration of gas is likely restricted by non-reservoir facies. As a result a consistent gas-oil contact (GOC) may not be present across large distances. Gas oil contact separates heavy oil by possible structural spill point and lithological boundary, dipping from south to north. Structurally higher areas are prone to localized gas accumulation. The completion stand-off from the gas base has a direct correlation with gas production. So the well management and production practice is to increase the stand-off from gas base to top perforations in future wells and to perform gas shut-off job in current wells to avoid free gas production. The novelty of the current approach is that it will proactively help in completion strategy to reduce future free gas production, subsequent loss in natural reservoir energy and maintain the oil production target.
Steam injection by Cyclic Steam Stimulation (CSS) and Steamflood (SF) are the selected enhanced oil recovery methods in a Kuwait shallow formation. Initial single wells and recent 5-spot pilots for CSS has production affected by sanding issues from the unconsolidated formation. A robust reservoir geomechanical model and cap rock integrity characterization on a field scale is a prerequisite for successful design and implementation of the two target steam-based EOR techniques for commercial exploitation. Conventional geomechanical modeling approaches normally depend on history matching of the in-situ rock failure. However, lack of quality data measurements for minimum and maximum horizontal stress was major challenge for soft sediment rock. Unconsolidated formation have their own inherent issues. Rock being weak and soft, it has low strength, as exhibited by the unconfined compressive strength (UCS). It also has comparatively lower values for the elastic moduli. Most of the time, the Leak Off Tests (LOT) carried out in such formation lead to inconclusive and questionable interpretation, as the pressure regime used is extremely low and this leads to uncertainty in stress measurement. Any thermal EOR project in such shallow-depth and unconsolidated formation heavily relies on a competent cap rock in place, whose integrity under the combined effect of thermo-mechanical-stress can be put to severe test. To overcome the challenges of: a) weak soft sediments having low rock strength and elastic moduli, b) uncertainty in the stress measurement, c) inconclusive interpretation of leak off tests (LOT), a novel method was suggested. An Integrated Stress Analysis (ISA) approach was used for geomechanical modeling to evaluate magnitude of horizontal stresses from advanced sonic measurements and 3D dipole radial profiles. Data can be further used for estimating rock mechanical properties, stress orientation and Transverse Isotropy of Vertical symmetry axis (TIV) parameters. A comprehensive anisotropic geomechanical model was built from the ISA and advanced 3D sonic output, which was validated using results from independently acquired minifracs run in offset wells. This model could accurately predict potential drilling hazards and wellbore breakout. More than 10% acoustic anisotropy in horizontal stress was also found in sand intervals, which requires more careful approach while deciding the injection parameters. Multi-well analysis and geomechanical modeling also indicated variation in horizontal stresses ratio and direction across the field. This paper provides a new approach for stress estimation of shallow heavy oil formation demonstrating how rock can behave as anisotropic material from sonic measurements, resulting in better constrain of tectonic and effective stresses. As special tool required to conduct minifrac in each wells and it is costly, using this novel approach to estimate stress magnitude is preferred.
Routine and Special Core analysis (RCAL and SCAL) are the cornerstone of Petrophysics Modeling and Formation Evaluation. In order to obtain the required information, it is important to have quality core, its processing and analysis. This paper summarizes current practices vis-à-vis improvements made in key technical areas. Coring and core analysis are cost-intensive processes. Only quality data from representative core plugs can offset the high cost and can help to achieve the objectives of coring and core analysis. To obtain consistent quality core plugs, coring practice, on-site handling and plugging procedure have to be the best in class. Coring and core analysis in the shallow-depth Heavy Oil Fields in Northern Kuwait have been in place for some time. The processes like i) coring operation ii) on-site core handling and preservation iii) core slabbing iv) core plugging and finally v) core analysis are continually improved. In order to be efficient and cost-effective, all the above processes were re-visited, quality gaps identified and improvements implemented by incorporating unconsolidated formation characterization from the available extensive petrographic studies. For example in the coring practice front, coring and core handling protocols were modified for sour heavy oil-bearing formations noticed in parts of the fields. On-site dry ice was used in addition to the prevalent practice of normal freezing. In the laboratory analysis front, obtaining representative plugs and getting useful results from them were the key challenges. Compared to the previous practice of liquid N2 injection from top only during core slabbing by band saw, liquid N2 injection from both top and bottom resulted in improved core integrity. The previous practice of plunge cutting of plugs with liquid N2 was continued. Before any analysis, Computer Tomography (CT) scan of the plugs was performed to discriminate plug-integrity related issues. This paper discusses lessons learnt from past coring and core analysis processes and their impact on heavy oil development. Improvements to these processes as cost-effective measures are presented through real examples. Recommendations for improvement include field procedure, laboratory process, and usability of the tests performed, which may be useful to the industry where heavy oil core analysis is used.
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