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.

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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).

The Neogene of North Kuwait comprises of unconsolidated sandstone reservoir having viscous crude. The field is to be developed by way of injecting steam into the reservoir. The XRD and SEM studies revealed that variety of the detrital clay minerals like Illite, Smectite, Chlorite, and Palygorskite commonly occurring within the formation. An experimental study was carried out to understand the implications of steam injection on the clay bearing formations and to determine temperature-dependent water-oil relative permeability to provide an indication of the recoverable reserves under steam injection. Sensitivity to different pH and salinity were also analyzed.Detailed laboratory study was conducted on nine plugs to determine the effect of hot water and steam injection on the permeability, relative permeability, residual oil saturation and mineralogical changes in the reservoir. The baseline steamflood was carried out to determine the residual oil saturation and evaluate the permeability changes due to clay swelling/dispersion in contact with brine and steam. The other six sensitivity steamfloods were carried out to determine the potential permeability damage resulting from clay swelling/dispersion when contacted with different pH fluid, salt concentrations (TDS) and clay stabilizers. Pre and post XRD and SEM analysis were done to see the effects of each steamflood on the core sample.This paper presents the discussion on results of core flood experiments conducted on nine preserved core samples at reservoir conditions. The results show that clays when contacted with steam induce significant permeability reduction. High salinity and pH control may not be sufficient to eliminate the loss of permeability. However, some clay stabilizers are found to be useful to improve the permeability and recovery.

A heavy oil field (Field X) in Northern Kuwait is in the early stages of development but it is clear from production pilots that tight units (baffles) of variable lithology, thickness and continuity, within the reservoir will play a key role in influencing steam conformance and recovery efficiency. The high well/core density of the field’s production startup area allows re-evaluation of baffles in light of cross-discipline integration of pilot production data, petrophysical data and detailed core review. A process was followed to update and calibrate all core descriptions against logs, follow a consistently picked set of petrophysically defined markers, compare visually defined lithofacies with log defined ones, and then map out key surfaces. The key next step is to define appropriate reservoir properties by facies/rock types, apply these to understanding pilot behaviour and predict steam conformance for Well, Reservoir and Facilities Management (WRFM) and the next phases of the wider field development planning. The field’s baffles play a role far beyond just understanding steam conformance, they are a first barrier for cap rock integrity and their presence/absence will also influence the path and rate of the aquifer influx. The petrophysical redefinition (Baffle Quality Index) of a "semi-stratigraphic" interval - which will stop or slow steam migration depending on its quality and lateral extent - has enabled efficient communication about the baffle, and allowed the wider team of petroleum engineers from a number of subsurface disciplines to focus on dynamic properties impacting recovery – steam conformance, aquifer influx, windows between isolated reservoir units – and then evolve the development strategy, effectively respond to WRFM issues, optimize observation and infill well placement and increase UR in a cost effective way.

Cyclic steam stimulation (CSS) and steamflood performances are strongly influenced by shaly barriers and cemented baffles in the heavy oil reservoir. Marine shales do act as a permanent barrier in most conditions, while non-marine shales and diagenetically altered cemented siltstone baffles may not act as barrier under different operating and reservoir settings. In this paper an investigation was made to understand the impact of barriers and baffles on performance of a reservoir operating under CSS and steamflooding.Out of several hundred wells drilled, seven isolated wells were selected for CSS on a trial basis. Two of them were completed in the Upper-A layer and three in the Upper-B layer. Marine cap shale as barrier exists on top of Upper-A while a cemented sandy siltstone baffle separates Upper-A and Upper-B layers. Wells completed in Upper-A performed better than those completed in Upper-B in the first cycle though sand thickness of Upper-A is much less than that of Upper-B.Production performance of the CSS wells was analysed considering the geological nature of baffles and shale barrier, and from results obtained during steamflood experiments conducted on plugs from baffles, and it was concluded that the main reason for the better performance of Upper-A layer compared to Upper-B layer was the presence of impregnable cap shale barrier. Cap shale does not allow the steam to migrate upward, thus forcing it to remain in Upper-A layer while when injecting steam in the Upper-B layer, some of the steam passes through the baffle above it, resulting in poor production performance and higher steam oil ratio. This analysis suggests that the aspect of competent shale being barrier to steam and baffle not so effective barrier should be given due consideration during commercial application of the CSS and steamflooding processes in the field.

Lower Fars is a shallow unconsolidated sandstone reservoir with high inter-granular porosity filled with heavy oil in southern part of Ratqa Field in Kuwait. The shallow depth (500' to 800'), friable sand laminated with shale and high viscosity heavy oil in pores have made coring this sand quite challenging. Last recovered core with rubber-sleeved core barrel in the eighties was only up to 60%. This paper describes how thoughtful mix-up of technology, innovative techniques and proper coordination by aligning all concerned has helped in meeting the challenge of coring unconsolidated sand and it's processing. Using low invasive core fluid, shorter core length, Aluminum inner core barrel, separate core bit to cut major sand / shale, full core catcher system, vertical slabbing at well mouth and on-site freezing have improved core recovery in excess of 85%. While low-solid content coring fluid with a pH of 9 resulted in low mud invasion, reduced WOB, ROP and SPM ensured fewer washouts during coring. Low abrasive core head with clam shell full closure core catcher produced good recovery. Core barrel length was reduced from standard 30' to 10', which was slabbed to 3' size keeping barrel vertically at well mouth. At well site it was frozen vertically with foam on top to minimise lateral movement and transported in freezer. At Core Lab it was kept frozen with dry ice, slabbed and plugged with liquid N2. It is expected that the obtained core plugs from similarly cored 6 wells shall lead to meaningful Routine and Special Core Analysis, which was suspected in old cores. This would help in developing the depositional geological model in conjunction with the image logs. Introduction The success of core analysis depends largely on how good the coring operation and well site core preservation are made. Conventional Coring in the unconsolidated formation is always problematic. The shallow sandstone reservoir filled with heavy oil in southern Ratqa Field of Kuwait is a challenge by itself. Earlier attempts in the eighties with rubber-sleeved core barrel had resulted in maximum recovery only up to 60%. When new wells were drilled as part of development plan, it was decided to core some early wells using modern coring technology. Low invasive core fluid, shorter core barrel length, Aluminum inner core barrel, separate core bit to cut major sand / shale and full core catcher system had helped in core recovery in excess of 85%. While low-solid content coring fluid resulted in low mud invasion, reduced WOB, ROP and SPM ensured fewer washouts during coring. Low abrasive core head with clam shell full closure core catcher resulted in better recovery. Core barrel length was reduced from standard 30' to 10', which was slabbed to 3' size keeping barrel vertically at well mouth. At well site it was frozen vertically with foam on top to minimise lateral movement before it was transferred to a chest freezer. The freezer was transported in running condition to Core Lab where it was kept frozen with dry ice for atleast 2 weeks. Core slabbing and plugging were performed using liquid N2. The obtained core plugs helped in meaningful Routine and Special Core Analysis, which was suspected in old cores. The good core recovery had also helped in characterization of depositional facies leading to the geological model in conjunction with the image logs. Unconsolidated sand coring- a new ball game The main areas of concern for unconsolidated formation coring are:minimising mud invasionusing proper coring assembly so as not to lose low strength rock capture during coringcore handling process so as not to jeopardize core preservation andnon-reactive preservation material.

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.