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).

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.

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