Field Cases - Water Shutoff & Conformance

Over the past five years, 170 water shutoff (WSO) treatments were applied in three major Kuwait Oil Company (KOC) oil-producing assets. Of these, 60% were chemical treatments, and the remaining 40% were mechanical. An extensive examination was conducted to (1) identify where and how these treatments are most effective and (2) develop a road map for future applications. This paper presentsthe major lessons learned from the evaluation of those WSO treatments.

The evaluation incorporated treatment reports, production test data, wireline open-hole and cased-hole logs, workover history, PVT and SCAL data, as well as geo-cellular and dynamic simulation models. The examination included well events (e.g., ESP placements), water injection effects, high-permeability streaks, cement integrity, unintended crossflow, water coning, and natural fractures (Bailey, 2000). A substantial database was developed to systematically organize and analyze the treatment results. Production data before and after the WSO treatments were analyzed, applying a success-criterion to distinguish wells with effective outcomes from those with poor performance (Seright, 2003). Artificial-intelligence/machine-learning methods were also applied to the data (Mohaghegh, 2000). Success and failure drivers were systematically identified and tabulated, supported by insights from full-field geo-cellular and history matched simulation models.

Approximately 50% of the wells showed a favorable response, particularly those with perforations in multiple reservoir sub-zones. The treatments in Asset 1 achieved over 60% success, whereas the treatments in Assets 2 and 3 only had 30-35% success rates. Wells with successful WSO jobs in Asset 1 were dominantly chemical treatments in the crestal areas of the field. Good responses in the Asset 3 occurred when water was isolated in identifiable thin high-permeability layers (Sydansk, 2011). Mechanical methods worked notably better than chemical methods in this asset. Poor responses were attributed to (1) unintended crossflow/uneven injection configurations, (2) short completion intervals, (3) completions in thick permeable layers where the entire interval was water swept, and (4) close proximity of injectors to the waterfront (Willhite, 1998). In Asset 2, good responses were seen (1) with separated perforation sets, (2) large completion intervals, and (3) large standoff between current perforations and current fluid contact. Poor responses were seen (1) when partial WSO in continuous perforation intervals failed to restrict the water movement, and (2) with low standoff between the current perforations and the water contact.

Chemical treatments particularly showed poor performance in short completion intervals. This paper applies logical engineering analyses to understand the results and points towards how these learnings can improve future applications of WSO. Multiple machine-learning models produced debatable success, while basic engineering insights proved more effective (Mohaghegh, 2000). Leveraging years of accumulated field data—rather than relying on unstructured technology deployment—can identify proven success factors, avoid repeating suboptimal practices, and provide actionable guidance for future WSO planning and execution.

Advancement in design and implementation of polymer gel water shutoff treatments in horizontal wells that penetrate fractures or faults have come from empirical improvements in the field and synergism between monitored field treatments and independent laboratory research. One case history will be detailed, followed by a summary of several other treatments. Simple calculations can give at least a rudimentary indication of the width of the fracture or fault that causes excess water production. Using laboratory data coupled with field data collected before, during, and after gel injection, the calculations can also give an indication of how far the gel has actually penetrated into the fracture. Our analyses reveal critical measurements that should be made during field applications and where additional laboratory research is needed.

Previously published field results were examined to determine if they reveal usable guidelines for the selection of wells as candidates for gel treatments. Views of seven gel vendors and experts from eight major oil companies were also examined concerning the selection and implementation of gel treatments in injection and production wells.

This study demonstrates that gel treatments have been applied over a remarkably wide range of conditions. Unfortunately, the success rates for these projects have been very sporadic. Our analysis indicates that the producing water/oil ratio was usually the only criterion used to select candidate wells.

To improve the success rate for future gel applications, the source and nature of the water production problem must be adequately identified. Results from interwell tracer studies and simple injectivity and productivity calculations can be especially useful in this diagnosis. Recovery calculations should indicate that considerable mobile oil remains that could be recovered more cost-effectively if a blocking agent could be realistically placed in the proper location.

Improvements are needed in the methods used for sizing gel treatments. The method of sizing should be tailored to the type of channeling problem encountered. Five different types of channeling problems are discussed.

This paper demonstrates the connection between laboratory measurements and field results from gelant treatments in production wells at the naturally fractured Motatan field in Venezuela. Using a HPAM polymer with an organic crosslinker, laboratory corefloods revealed that under reservoir conditions, the gel provided oil and water residual resistance factors of 20 and 200, respectively. This gel was placed in several production wells in the Motatan field. In Well P-47, 1,000 bbl of this gel reduced the water cut from 97% to 64% and increased the oil production rate by 36%. The success of these treatments depends on the distance of gelant leakoff from the fracture face and the in situ residual resistance factors in the oil and water zones. Analyses were performed to determine these parameters, based on formation permeabilities, porosities, fluid saturations, fluid properties, fluid production rates, and pressure drops before, during, and after gelant placement. Accurate pressure drops before, during, and after gelant placement were particularly important. Sensitivity studies were performed to demonstrate their significance and the impact of measurement errors. A methodology is presented for optimizing the volume of gelant injected for these applications.