Water management has always been a challenge especially in mature fields. Consequently, mechanical, chemical shutoff and other water reduction techniques have been developed and deployed to curb the menace in the hydrocarbon industry. However, poor diagnostic work can be a leading reason for the low success rate for any water control method. This paper introduces a holistic workflow to understand the candidate selection, filter the wells based on priority and determine the water breakthrough mechanism to eventually select the optimal remedial action. In this paper, 7 wells are selected and prioritized to undergo a workflow to diagnose water breakthrough and characterize it. The first analytical tool is Chan correlation, which incorporates the water-oil ratio for determining the water signature. For determining the water entry zone, Production Logging Tool (PLT) will be used as the second investigative tool. Water source identification plays another major role in assessing whether the water is coming from an aquifer, nearby injector or native reservoir fluid, which can be determined by the frequent sample collection and lab analysis for ionic concentration. These three investigative tools will provide a basis to select the proper water management strategy. The results of the diagnosis have revealed several facts regarding the aforementioned parameters. A number of the diagnosed wells have shown a steep increase in oil-water ratio and oil-water ratio derivative, which hints to a possible nearby thief zone according to Chan correlation. Reviewing the produced water ionic concentration suggests low salinity and that the water's chemistry is closer to that of an injected water than reservoir water. Finally, Production Logging Tool showed multiple water entries in the open hole section. According to the diagnosis, Inflow Control Device deployment for those wells are recommended. Couple of multilateral wells completed with Inflow Control Valves (ICV) showed rapid channeling of water, which can be caused by a thief zone or a lateral dominating the flow and contributing high water cuts. These wells were subjected to ICV optimization and it confirmed that a latera was dominating the flow with high water cut and was optimized. The water cut for those two wells dropped by 58%. The workflow enables engineers to understand the water breakthrough mechanism in a timely-matter, which allows them to categorize the wells based on the different water signatures such as water coning, thief zone, and near wellbore breakthrough. The proposed workflow can be adopted and adjusted based on the water management problems associated to any field in order to find the optimal remedial action. This outcome played a role in the planning of placing and drilling new wells in the field.
Conformance control via near-wellbore mechanical and chemical treatments is well established. However, for extreme heterogeneities, effective conformance control mandates deep treatments. Such deep treatments or diversion would sustain sweep enhancement far from wells, deep into the reservoir. Deep diversion is even more mandatory for enhanced oil recovery (EOR) to assure the expensive injectants optimally contact the remaining oil. In this paper, we comprehensively present efforts to research, develop, and trial a crosslinked-gel system for deep diversion. We started by reviewing conformance control options including crosslinked systems. The review supported the immaturity of deep conformance control. Various gel-based solutions, especially preformed particle gels (PPGs) and colloidal dispersed gels (CDGs), were proposed; however, diversion effects were not clearly illustrated. For crosslinked-gels, all systems exhibited fast gelation, something suitable for near-wellbore treatments. We then studied the key crosslinked systems. We characterized their behavior using rheometry, bottle tests, and single-phase corefloods. We assessed their potential through oil-displacement corefloods in artificially fractured cores with and without in-situ imaging. In-house studies, on key gel systems demonstrated the feasibility of gels to affect diversion and enhance recovery but corroborated the extreme challenge to design systems with delayed gelation. To assure representative gelation, we developed, and utilized a continuous bi-directional injection protocol to assess gelation times in-situ. From there, we collaboratively developed, and characterized a unique delayed-gelation formulation. The collaborative study addressed this challenge where systems with delayed gelation were developed. In-situ gelation time estimation confirmed this delayed gelation capacity. Further corefloods addressed the key uncertainties including injectivity losses, limited propagation, and ineffective blockage. Simulations were performed to assess the process feasibility.The simulation studies supported the utility of deep diversion treatments. Simulation also guided the initial design of a trial. We focused on the design of a practical field trial.For further derisking, the first trial was optimized to serve as a practical proof-of-concept. Taking into account economics, success measurement, flow assurance, and depth of placement, we diverged from a trial where we observe deep diversion (and infer delayed gelation and effective blockage) then converged into a trial where we infer deep diversion (by observing delayed gelation and effective blockage). With that, we screened candidates with a clear hierarchy of screening criteria. Through this program, and for the first-time in the industry, we demonstrate the potential utility and feasibility of a crosslinked-gel system for deep diversion applications. This potential is supported by comprehensive experimentation including novel in-situ estimation of gelation times. Finally, a consistent workflow to design a practical field trial is laid out. This, in terms of design considerations and hierarchal screening, is believed to be of extreme value to the practicing reservoir engineers.
Carbonate reservoirs are challenging for chemical EOR, particularly in selecting fine-tuned chemical formulations which combine high performance, stable behavior, and trouble-free operations. The design of suitable formulations requires substantial laboratory work and a solid methodology. In this paper, a systematic all-inclusive laboratory workflow to design a surfactant-polymer (SP) formulation for a carbonate reservoir is presented. In this work, a complete process for development and evaluation of an SP formulation for high-salinity high-temperature conditions is proposed and adopted. For which, a high throughput robotic platform is used for efficient and robust formulation design. The process is illustrated on an actual case with harsh reservoir conditions (i.e. a high temperature of 100℃ and high connate salinity of 213,000 mg/L). The SP design methodology consisted of five steps: surfactant design, polymer selection, surfactant/polymer verification, topside assessment, and oil-displacement evaluation. The surfactant formulation design consisted of four substeps: solubility scans, phase-behavior scans (salinity scans), IFT measurements, and static adsorption tests. The sourced polymers were screened based on three key performance indicators: viscosity, filter ratio, and thermal stability. The selected surfactant formulations and polymers were then assessed as sloppy slugs in terms of compatibility and injectivity. Then, the unique topside assessment was conducted where it consisted of two components focusing on: separation kinetics and separated water quality. Finally, an oil displacement study was performed using a preserved composite plug, in which the SP formulation developed through the outlined process was used. The results demonstrate the potential of a mixture of Olefin Sulfonate (OS) and Alkyl Glyceryl Ether Sulfonate (AGES). The results also illustrate couple of polymers with stabilities suitable for high temperature conditions: an associative polymer, and an AM/AMPS copolymer. In addition, injectivity corefloods supported the SP slug transportability across the porous media. Corefloods also demonstrated the SP slug capacity to recover around 62% ROIC (remaining oil in core). Finally, SP in produced brines improved the separation kinetics but lead to a slight deterioration in separated water quality. A key novelty of the adopted workflow is the integration of topside assessment. In addition, the experimental steps were clearly delineated including the preparation of representative oils. Beside a clear layout of the methodology, the work demonstrates that a surfactant-polymer formulation can successfully be designed for high temperature carbonate reservoirs and provide encouraging guidelines with respect to SP impact on topside facilities.
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