Heavy oil contribution is considered a key requirement for delivering the challenging 2030 strategic production targets of Kuwait. Different production technologies have been considered for meeting this challenge. Initially the cold production technology of CHOPS (Cold Heavy Oil Production with Sand) has been tried through a pilot. The present paper summarizes the performance of the first CHOPS pilot performance and analysis of the pilot results. The analysis of the performance data from the pilot provides important clue for understanding the reservoir description issues as well as sand production characteristics. The result of the study has relevance for sand management strategies in the planned future thermal development of the field as well. The wealth of information available from the pilot helps developing an improved dynamic reservoir description. The paper demonstrates that the CHOPS process has an intimate relationship with rock mechanics, fluid viscosity and the flow potential of the formation. It is also demonstrated how the field surveillance data can be used to investigate the enigmatic subject of "Foamy Oil" (Alshmakhy et al. 2007). The results can also help in developing an improved completion strategy for the wells, especially in the area of sand management. The paper provides important field performance data and analysis of the CHOPS pilot performance from Kuwait that can be used for taking decisions on applicability of the process in other similar reservoir set ups. The analysis also helps firming up an optimized sand management strategy for this reservoir.
An unconsolidated clastic reservoir of Middle Miocene age is under full field development plan in the State of Kuwait. Underlying the shale cap rock, main hydrocarbon bearing reservoir consists of two sand bodies separated by predominantly shale interval present throughout the field. To determine the role of facies and depositional environment in controlling the orientation and quality of the reservoir, an integrated analysis of borehole images, open hole logs and core data from wells spread across the field was successfully attempted. Fifteen identified generic image facies principally based on lithology and reservoir quality with core data validation were grouped into six genetically related associations. Facies recognition used criteria of image textural variations, dip patterns, direct recognition of features and relationships of cementation, bioturbation and sediment deformation. Statistical analysis of the identified sandy facies of upper reservoir unit indicated high abundance ratio and preferred distribution trend while no significant distribution trend observed for the lower reservoir unit. Observations from the image and core data helped to define depositional environment and sub-environments. Results indicate that depositional setting was created by succession of several depositional environments such as shore face, coastal plain of fluvial & distributary channels and lagoon. The high angle cross-bed features distinctly noticed are interpreted to be deposited in confined depositional environment of channel sand bodies, suggesting a major paleo sediment transport orientation. The marine shale deposited during a major flooding event on top part of the hydrocarbon bearing reservoir acts as cap rock. Tight carbonate cemented sandstone intervals also identified at various levels within the reservoir. In general, the formations exhibit distinct episodes of regression and transgression events marked by erosive and flooding surfaces. The identified rock facies relationship and depositional environment provided significant lead in formulation of full field geological model.
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.
Downhole fluid sampling in shallow unconsolidated reservoir having high inter-granular porosity and filled with viscous oil is quite challenging. The dominant formation properties, relevant to fluid flow, like low pressure, rock’s mechanical weakness, drilling damage and fluids mobility ratios, despite very high permeabilities, have resulted in the failure or impracticality of the conventional and most obvious methods- for example the sampling with Dual/Straddle Packers. The problems faced during sampling are: i) plugging of flowline, ii) emulsion generation iii) sand production- leading to caving around sampling tool and iv) marginal operating limit of pressure drawdown-dictated by extremely low formation pressure and little difference between hydrostatic and formation pressures. Mostly, the flow happens in surges and any increase in flow rate causes large drag on sand grains and excess pressure drawdown. A thoughtful mix-up of technology, understanding of rock mechanics, innovative operating techniques and proper coordination by aligning all concerned has helped in meeting the challenge of sampling viscous oils in the unconsolidated sand. A log-based Geo-Mechanical study suggested very low unconfined compressive strength for the sand, restricting the flow rate to as low as 2 cc/s. Dual/Straddle Packers, with its large volume at this low flow rate, would require very long hours of pumping. Typically, the volume between packers would take 5 to 6 hours of continuous pumping at the suggested maximum rate of 2cc/s; just sufficient to start pumping out from the formation. A normal probe would cause sanding at probe head due to the reduced cross section to flow. The most successful approach was the selection of: a) probes with enlarged cross section to flow, which reduce the drawdown by decreasing the flow velocity at the sand face, b) ultra slow pump out rates to negotiate drawdown, formation weakness and mobility ratios of water/filtrate and viscous oil. Multiple sand filters in the flow line, segregation of emulsified filtrate through innovative techniques and state-of-the art fluid analysis methods helped to determine exactly when the viscous oil started to flow. However, the surge nature of flow still resulted in 20 to 30% contamination in the sampled oil. The obtained PVT-quality downhole sample helped in determining the in-situ fluid properties of the viscous oil.
The Jurassic carbonate reservoirs in Minagish Field of West Kuwait have undergone significant pressure depletion (up to 4,000 – 5,000 psi) over the last two decades. However, during the last few years at least two wells showed sudden and significant reservoir pressure increase despite no injection in the reservoir for pressure support. The asset team plans to develop these reservoirs with more horizontal wells in order to increase the reservoir contact and thereby productivity and reservoir recovery. However, drilling and deepening the infill development wells in this area is becoming increasingly challenging due to uneven differential depletion across the field. Unprecedented drilling complications including mud-loss, well kicks, and differential sticking are observed. This paper discusses how a field scale 3D reservoir geomechanical model integrating all available data was built and used to evaluate the impact of production induced stress changes on reservoir behaviour. Furthermore it details how geomechanical characterization provided inputs for the field development planning. The dynamic 3D reservoir geomechanical modelling of this field integrated: the structural geological model, well based 1D geomechanical models, rock mechanical test results from core, production data, reservoir simulation model as well as selected petrophysical and geophysical data. This model was initially built at original reservoir pressure. After proper assignment of both stratigraphically verified mechanical properties and boundary conditions of far field stresses, the finite element stress simulator was utilized to establish a representative initial stress state within the reservoir and its surrounding formations. The history matched and future predicted reservoir pressures at various time steps were coupled to the finite element mechanical simulator to map the changed stresses and strains over the reservoir interval. The finite element analysis helped to investigate the associated changes of the in-situ stress field, pore pressure and rock properties across the field and specifically around the planned wells in order to capture the 3D effect of reservoir depletion such as arching effects. This analysis improved the field development planning by integrating wellbore stability risk assessment, fault slippage and other related aspects. The 3D Geomechanical model also distributed the shear-to-normal stress ratios over the interpreted faults/fractures and explained the dynamic behaviour of certain faults due to depletion. Field scale distribution of in-situ stress changes provided inputs to risk assessment due to further depletion. Understanding the stress induced response of reservoir due to depletion helped to plan new infill wells in due consideration of geomechanical risks and production efficiency. The 3D Geomechanical modelling approach demonstrated that it is technically feasible to incorporate the complexity of 3D geological structure of a reservoir, fault network and other variables within the in-situ stress field. Using appropriate modelling simulations with realistic in-situ conditions, it was possible to explain the behaviour of pressure in wells, faults and also wellbore stability risks.
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