Hess Corporation

Abstract Injection wells play a vital role in reservoir management and production performance in Guyana’s Stabroek development. This paper highlights how early learnings from Guyana’s Liza Phase 1 injectors led to improved injector performance for the Liza Phase 2 project. Although the first three Liza Phase 1 injectors achieved their designed water injection rates, a joint study by the subsurface and wells teams was initiated to analyze early performance and identify improvement opportunities. Analysis of early step-rate tests and fall-off pressure data from Liza Phase 1 injectors revealed signs of plugging during the ramp-up phase, resulting in an elevated near-wellbore pressure drop and partial penetration effect. Subsequently, the reservoir drill-in fluids (RDIFs) for Liza Phase 2 was optimized to streamline operations and improve well performance. A novel well performance analysis method was also developed to track and compare injector behavior across Liza Phase 1 and Phase 2 wells, which enabled validation of the revised completion procedure. The revised drilling-fluid design and procedures for Liza Phase 2 injectors led to a marked improvement in water-injector performance compared with Liza Phase 1, with Phase 2 injectors exhibiting significantly less flow-path plugging and partial-penetration effects. The performance analysis tool revealed that Liza Phase 2 injectors have consistently higher injectivity and lower near-wellbore pressure drop. These marked improvements increase individual well capacity and provide greater flexibility in reservoir management. The learnings have been applied to subsequent Stabroek developments, including Payara and Yellowtail projects, delivering substantial value. This paper highlights the importance of early performance diagnostics and multidisciplinary collaboration in identifying and implementing effective solutions. It introduces a novel well performance analysis method that tracks reservoir pressure and injectivity trends over time while distinguishing between rate-dependent and time-dependent behaviors on a consistent basis, which provides a robust tool for well performance analysis in deepwater developments.

Palynological analysis of the Bakken Formation in three wells drilled by Hess Corporation in Mountrail and Williams counties, North Dakota, USA, has shed new light on the potential role of palynology in understanding the chronostratigraphic relationships and deposition of oil-bearing strata in the Williston Basin. A detailed sampling program examining palynomorphs and particulate organic matter yielded variable assemblages of sphaeromorphs, acritarchs, miospores, and plant fragments. Broadly, the Lower Bakken and Upper Bakken members are dominated by organic-walled sphaeromorphs (of possibly algal affinity) with a low diversity suite of acritarchs. Particulate organic matter consists mainly of structureless organic matter, most likely of marine origin, although some may be terrestrial but highly degraded. The upper and lower members are marine deposits. Variability in the size of the sphaeromorphs suggests that differences in productivity, ocean chemistry, light, and temperature, may have occurred during deposition, as evidenced by results of isotope and biomarker studies. The Middle Bakken Member samples yielded a mixed assemblage of miospores and acritarchs with minor occurrences of sphaeromorphs. Land plant-derived particulate organic matter dominates the Middle Bakken Member which was deposited under nearshore marine conditions as corroborated by the consistent, although rare, occurrence of acritarchs. Age-diagnostic palynomorph taxa are rare, although the key latest Devonian miospore, Retispora lepidophyta, appears consistently in the Middle Bakken Member and last occurs near the top of the unit, where the Devonian-Mississippian boundary is placed. Distinct distribution patterns of acritarchs at the genus level may prove to be of chronostratigraphic value with species of Gorgonisphaeridium common in the Middle Bakken Member and species of Micrhystridium dominant in the Upper Bakken Member. Although there is broad similarity with other studies from North America, examination of more wells in the Williston Basin are needed to better understand these relationships.

Operators face many challenges as a well approaches end of life. Decisions must be made in regard to the economic feasibility of performing a stimulation treatment to prolong well production verses P & A. This is the situation that a Gulf of America (GOA) operator was facing for a well in their field that was plagued with multiple issues including organic deposition, barium sulfate scale deposition in the screen/near wellbore area, fines migration and water management. The restimulation design consisted of a multiphase approach that included: Phase I -a screen/near wellbore soak to remove organic deposition and barium sulfate scale. Phase II- a diverted mud acid treatment that included specialty stimulation chemistry to address, organic deposition, acid soluble scale, and fines issues. Phase III- a diverted scale squeeze to help to delay the onset of scale deposition. Phase IV- water management was discussed but since water handling is not currently an issue on this platform this treatment was dropped from the program. The challenge for this well treatment was the inclusion of the high pH barium sulfate removal treatment and the pH sensitive scale squeeze in conjunction with the low pH acid job. The low pH acid has potential compatibility issues with both treatments. Special design considerations were taken to prevent the compatibility issues and place an effective treatment that minimized the amount of vessel mobilizations to the field making the treatment economical. The operator performed multiple treatments on a well that would not have been able to pass the economic hurdle had standalone treatments been recommended. The effectiveness of the treatment was evaluated via formation responses and production rates. This paper will provide information related to the design, execution, and outcome of this unique multi-phase treatment.

Aqueous solutions of gas nanobubbles (NBs) possess unique properties that make them a promising alternative to traditional water flooding and enhanced oil recovery (EOR) methods. NBs are stable for weeks to months, which is crucial for practical deployment, and their nanometer size enables penetration into narrow porous spaces in tight formations, which are particularly important targets for EOR. This study presents the first experiments testing of N2-based NBs for oil recovery enhancement using spontaneous imbibition, comparing the NB performance to that of distilled water (DW). The tests were conducted on two rock samples: Minnesota Northern Cream (MNC) carbonate and Berea sandstone, under two wettability conditions (strongly water-wet for both rocks and strongly oil-wet for MNC) and a wide range of temperatures and pressures (ambient to 90 psi and 120 degrees C). For both rocks and wettability conditions, NBs generally enhance the oil recovery compared to DW at most temperatures and pressures, except for the highest tested pressure (90 psi), where the difference was not statistically significant. The greatest enhancement was obtained from oil-wet MNC at 45 psi and 120 degrees C, which neared the recovery from water-wet MNC under the same conditions. Additional experiments with N2 NB solutions of varying gas-liquid quality (amount of N2 gas per unit liquid volume) revealed that higher gas-liquid ratios led to lower NB stability and progressively lower oil recoveries. The study further explores potential mechanisms for the recovery enhancement by NB solutions, discussing the effects of wettability, temperature, pressure, and gas quality and considers the implications for practical NB-based EOR applications.

In this study, our primary objective is to introduce a novel approach for estimating permeability and reservoir pressure during the after-closure period of pump-in/flowback tests. While existing techniques primarily focus on Diagnostic Fracture Injection Tests (DFIT) for formation parameter estimation, no methods have been developed for analyzing the shut-in period following pump-in/flowback tests. We extend the after-closure analysis based on the Soliman and Craig model to make it applicable to pump-in/flowback tests. Our analysis involves studying after-closure data to calculate formation permeability and reservoir pressure. During the after-closure period, we introduce a model to identify the flow regime and estimate permeability, particularly during the pseudo-radial flow period. To validate our model, we compare its performance with conventional DFIT cases using a finite difference numerical simulator. Our simulations reveal a time advantage for pump-in/flowback tests over traditional DFIT in permeability estimation. This pioneering approach represents a significant advancement in the field, providing a unique and efficient method for estimating reservoir properties during radial flow in pumpin/flowback tests.