Waterflooding in unconsolidated sands has been observed to frequently result in injectivity decline of injectors when operated under ‘fractured’ conditions, resulting in reduction of waterflooding value creation and potential premature injector failure. Optimization of injector design and operation is currently limited by an insufficient understanding of the mechanics of ‘fracture’ and its associated mechanisms in unconsolidated sands, and the lack of adequate quantitative tools to predict injection performance. Utilizing in-situ CT scanning during large-scale laboratory injection experiments delivered novel insights into generation, closure and re-opening of ‘fractures’ in sand packs built from synthetic sands and highly unconsolidated downhole core material. Cavity formation was identified as main ‘fracturing’ mechanism. The cavities opened at injection pressures exceeding the confining stress and subsequently enlarged against a very low cohesive strength for the downhole core sands. This suggests material fluidization rather than shear failure as the immediate cavity initiation mechanism. Injectivity was found to be controlled by the interplay of fines transportation away from the injection region, resulting in injectivity increase, and the permanent compaction of the sand around the cavity, resulting in injectivity decrease. These first-time insights challenge the current understanding of matrix vs ‘fractured’ injection in unconsolidated sand reservoirs and highlight the role of sand fluidization and cavity formation. Furthermore, the injectivity behaviour is dependent on the combined effects of the sand material, the presence of fines, and the injection flow regime. The knowledge of the sand destabilization and mobilization processes enable design and operation optimizationof water injectors with implications on sand control strategies and remediation measures.
Almost all Malaysian hydrocarbon-bearing sandstone reservoirs contain minerals which are potential sources of mobile fine particles. For this reason, formation damage in injection and production wells has been frequently associated with the migration of fines in reservoir pores. In this work, an effective, novel, environment friendly and cost beneficial fines stabilizer is formulated in-house. The developed chemical works on the principles of coagulation and flocculation. Different coagulant and flocculant chemical combinations are trialed, and the understanding of their performance is shared using turbidity and zeta potential testing. The developed fines stabilizer chemical is later tested for compatibility with reservoir fluids and production chemicals of a field which is planning to apply fines stabilizer. Based on the potentiality in static screening results of turbidity, zeta potential and compatibility, a fines stabilizer is chosen for dynamic testing. The constraint of critical flow rate for fines migration is addressed in dynamic study using core flood experimentation. Critical flow rates are determined by forward and reverse injection into core samples. Accordingly, the performance of in-house synthesized fines stabilizer is judged by enhancement in critical flow rate in comparison to untreated and commercial fines stabilizer treated cores. Since the constraint from the critical rate effects injectivity and productivity, modification of this constraint and increase of the critical rate consequently provides more economic benefit. The additional revenue from oil production by using the in-house developed fines stabilizer chemical is estimated, and the costs are compared with a commercial fines stabilizer. The uniqueness of this endeavor is in developing an in-house fines stabilizer chemical which can be used after acidizing, enhanced oil recovery treatment, in production and injection wells. The synthesized in-house formulation is more effective and cost saving compared to commercial fines stabilizer.
A thorough 3D finite-element (FE) geomechanical study was over undertaken for an oil and gas field offshore Sarawak, Malaysia, to assist the development management. The field comprises eight major reservoirs with three of them planned for water injection to improve recovery. The historical well drilling data, wireline logs, production data, field tests and newly obtained laboratory test data provided inputs for deriving a wellbore-based 1D geomechanical model for the field. The 1D model was calibrated to well drilling observations before being up-scaled and populated in a 3D geomechanical model for the entire field. The model was implemented in an FE simulator to dynamically analyze reservoir compactions, platform site subsidence, fault reactivation potential and cap rock breaches that might be induced by reservoir depletion and injection in the full life cycle planning of the field management. The results showed a maximum subsidence of 0.72 m above the shallowest depleting reservoir and a subsidence of approximately 0.62 m at the seabed in year 2032. Injection slightly reverses the subsidence induced by depletion and the subsidence at the centre of the seabed is approximately 0.58 m in year 2050. The corresponding subsidence at the platform sites reaches 0.58 m in year 2032 and reduces to 0.54 m in year 2050. Depletion tends to reduce fault reactivation potential within the depleting and close underlying intervals, but enhances fault slip likelihood near the upper bounding zones. Faults segments bounding the deepest producing reservoir, which contains the most depletion, is predicted to have the highest potential for fault shearing in the late stages of production. Injection reverses the trend of fault reactivation potential. There are no caprock integrity issues with the three main injection reservoirs for the entire field life. Introduction The study field is in offshore Sarawak, Malaysia and truncated by two sets of major faults with one set (Alpha) in the south and the other (Beta and Gamma) in the north of the field. There are dozens of hydrocarbon-bearing zones separately deposited in the upper to lower coastal plain environments of interbedded sandstones, shales and siltstones. The shallower zones comprise gas reservoirs; intermediate reservoirs exhibit small oil rims; and deep reservoirs show gas condensate. Eight reservoirs, labelled as R1, R2, … and R8, have been either in production, or in water injection, or within future production consideration. Fig. 1 shows the plan and cross-section views of the field structure. After the field discovery in 1967, production commenced in 1972 from three major reservoirs: R4, R5 and R6, with R6 started water injection since 1994 follow by R4 and R5- in 2017. In addition, the other 5 reservoirs, including a deeper overpressured pure gas reservoir, R8, will begin production in 2017. Thereafter, depletion and recharge of pressure is expected from multiple reservoirs undergoing either production or injection. Pressure depletion from production or pressure recharge because of injection induces stress changes in the depleting/injecting reservoirs and their bounding formations. Consequently, the stress changes in multiple reservoirs and bounding zones can induce various geomechanical problems, e.g., wellbore drilling instability, sand production, reservoir compaction, overburden subsidence, fault reactivation and caprock fracturing. Those geomechanical issues can impact well planning, platform facilitating and production management for future field development.
An integrated 3D dynamic reservoir geomechanics model can provide a diverse 3D view of depletion-injection-induced field stress changes and the resulting deformation of both reservoir and overburden formations at various field locations. It enables the assessment of reservoir compaction, platform site subsidence, fault reactivation and caprock integrity associated with multiple production and injection reservoirs of the field. We demonstrated this integrated approach for a study field located in the South China Sea, Malaysia, which is planned for water injection for pressure support and EOR scheme thereafter. Reservoir fluid containment during water injection is an important concern because of the intensive geologic faulting and fracturing in the collapsed anticlinal structure, with some faults extending from the reservoirs to shallow depths at or close to the seafloor. Over 30 simulations were done, and most input parameters were systematically varied to gain insight in their effect on result that was of most interest to us: The tendency of fault slip as a function of our operation-induced variations in pore pressure in the reservoir rocks bounding the fault, both during depletion and injection. The results showed that depletion actually reduces the risk of fault slip and of the overburden, while injection-induced increase in pore fluid pressure will lead to a significant increase in the risk of fault slip. Overall, while depletion appears to stabilize the fault and injection appears to destabilize the fault, no fault slip is predicted to occur, not even after a 900psi increase in pore pressure above the pore pressure levels at maximum depletion. We present the model results to demonstrate why depletion and injection have such different effects on fault slip tendency. The interpretation of these geomechanical model results have potential applications beyond the study field, especially for fields with a similar geology and development plan. This is a novel application of 3D dynamic reservoir geomechanics model that cannot be obtained from 1D analytical models alone.
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