Implementation of Streamline Derived Rate Targets Improved Oil Production of Mature Field

Adamson, Scott I.; Giden, Ilhami; Matzka-Pöll, Ronald

doi:10.2118/209679-ms

Cited by 3 publications

References 4 publications

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Pressuredrop Response Characteristics for Multi-Injection Well Interfered Vertical Well in Heterogeneous Fractured Anticline Reservoirs

Shi

Liu

Gao³

et al. 2023

Journal of Energy Resources Technology

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Fractured anticline reservoirs are mostly developed by a line production well located at the top position and a line injecting well located at the bottom position. The production well is often interference with by multiple injecting wells, but there is little related research about multiple injecting well interference. To solve this problem, an extended bottom-hole pressuredrop (BHPD) response model for production well interfered with by multiple injection wells was presented to capture the injection interference and gravity effect. The proposed model's correctness is validated by the software numerical simulation, and low regimes were identified by the BHPD and its derivative curve. Research results show that: (i) The BHPD derivative curve has a 1/2 slope line, V-shape, and 1 slope line in reservoir linear flow regime, inter-porosity flow regime, and interference flow regime, respectively. (ii) The drop rate of pressure increases with the increase of formation transmissibility and storability. The bigger the fracture storability, the more obvious the V-shape feature in the derivative curve of BHPD. As the inter-porosity flow coefficient increases, the V-shape feature emerges later. (iii) The beginning time of the interference flow becomes later when the interference distance increases. When the injection rate trends to the production rate, the BHPD curve shows a slight drop and its derivative curve has an intermittent rupture. (iv) The influence of the gravity effect is not ignored. Due to the gravity effect, the BHPD interfered by constant injection well like the BHPD's behavior interfered by the closed boundary. This work provides technical support for capturing the source and degree of interference from well group in the heterogeneous fractured anticline reservoir.

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Pressuredrop Response Characteristics for Multi-Injection Well Interfered Vertical Well in Heterogeneous Fractured Anticline Reservoirs

Shi

Liu

Gao³

et al. 2023

Journal of Energy Resources Technology

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Application of Streamline-Based WAG Injection Rate Management to Improve Oil Recovery of GLSAU CO2 Flood

Kalitsun,

Fazelipour,

Thiele

et al. 2023

Day 2 Tue, October 17, 2023

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The Goldsmith-Landreth San Andres Unit (GLSAU) in the Permian Basin has been under waterflood since 1963, and CO2 WAG flood since 2009. In January 2020, the asset team initiated a flood management workflow using a numerical Streamline Surveillance (SLSV) model approach. Starting in March 2020, because of the oil price collapse due to the pandemic, only produced CO2 was reinjected (harvest operation). Reduced availability of CO2 led to the field-wide voidage replacement ratio (VRR) declining and injectors unable to maintain their pre-harvesting CO2 rates. The approach described in this work outlines how SLSV was used to prioritize CO2 usage in the water-alternating-gas (WAG) scheduling process and to manage water and CO2 injection rate targets to improve the effectiveness of CO2 and minimize oil decline despite the reduction in VRR. Before using SLSV, injection targets were calculated assuming fixed geometric (FG) defined injection patterns and a per pattern processing rate of 10% to 15% HCPV/Yr. The WAG scheduling was then derived from the total injection volume by using a predetermined number of days of water and CO2 injection. In this work, we describe a novel WAG management approach by including injector efficiencies (offset oil produced per volume of fluid injected) computed from an SLSV model able to quantify injector-producer relationships. Fifty-three injectors were included in the Area of Interest (AOI) as candidates for new rate targets. The estimated incremental tertiary oil recovery on January 2020 was 3.9% at a CO2 maturity of 53.3%, slightly above the target defined by the field prototype curve. After applying SLSV as of this writing, incremental tertiary oil recovery is 4.9% at a CO2 maturity of 58.5%. Using the SLSV model, injection rates were increased or decreased depending on the efficiency of each injector-producer pair and additionally constrained by surface facility limits, the availability of CO2 volume to inject, and individual well injectivities. The injection rate target calculations were repeated in March and August of 2020, in January and August of 2021, and in January and June of 2022 using the latest measured well responses as a starting point. Due to the limited volume of CO2 available for re-injection with the start of harvest operation, all injectors that were scheduled to be switched to CO2 cycle (based on the water injection time and designed WAG ratios) were prioritized using injector efficiencies calculated by the SLSV model. The higher an injector efficiency, the higher the probability that a well would be switched to a CO2 cycle. Incremental oil recovery has outperformed the field's prototype for the given CO2 maturity using the SLSV approach. Across the 53 sets of injector rate targets, some injectors had rate increases up to 25%, while other injectors had rate decreases of 25%. During this same period of incremental oil response, overall CO2 injection volumes were reduced from 40.5 MMscf/d to 11.6 MMscf/d (a 71% decrease), water injection volumes were reduced from 38,400 stb/d to 26,400 stb/d (a 31% decrease), and total produced voidage rates dropped from 60,000 rb/d to 33,000 rb/d (a 45% decrease). GLSAU went from an established VRR > 1 (~1.09) before March 2020 to a constant VRR of 0.98 after March 2020 due to CO2 harvesting, yet oil recovery improved.

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Miscible Wag Management of a Mature CO2 Flood: A Streamline-Based Approach

Selveindran,

Razavi,

Patel

2024

Day 4 Thu, April 25, 2024

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The Postle field is located in Texas County in the Oklahoma Panhandle and has been waterflooded since 1960 and CO2 flooded since 1996. In 2022, a streamline-based flood management workflow was initiated to optimize flood performance and improve cashflow. Initial recommendations included cutting existing CO2 purchases by 50%, generating a savings of $7.5MM. In 2023, due to a deterioration in profitability, the field went through several iterations of cost-cutting measures culminating in the elimination of purchased CO2 and a reduction in workover job. The loss of purchased CO2 effectively reduced the volume of injection volumes by about 20%, reducing the VRR from 1.5 to 1.2. This reduced the processing rate in the reservoir from 7% to 5% per year. This work outlines a streamline-based flood management approach, and results achieved from the implementation of this new workflow. The new flood management approach was adopted across the entire Postle field that consists of 4 units. This encompasses nearly 250 producers and 100 injectors. A streamline surveillance model was built for the entire field across the 3 main producing zones. The results from the surveillance model were used to identify interwell connections between producers and injectors. This allowed the injection impact or value of each injector to be properly quantified. The injection efficiencies were used to allocate the limited volume of CO2, where higher efficiency injectors were allocated more CO2. WAG parameters were also calibrated based on rate targets from the surveillance optimization module (floodOPT). The combination of rate targets and ranking of injectors based on efficiencies were used to determine WAG cycle lengths, WAG ratios and injection volumes. The injector efficiencies (or volume of oil associated with each injector) proved an accurate measure to the engineering teams to accurate rank injectors in order of priority for workovers and determine whether an injector was worth repairing or plugging. The initial results from the streamline model was obtained in 2022 and validated and verified with other measurements. The surveillance model produced a connectivity map between injectors and producers (FMAP) that was consistent with flow path directions from a tracer study in 2021. Furthermore, the interwell connectivities in the model across multiple patterns were consistent with well connections from production-injection data and field staff experience. This highlighted the challenge with using classical geometrical pattern allocations that are time-invariant, compared to dynamic patterns that are influenced by geology and rate. The model also flagged underperforming injectors i.e. injectors with low efficiencies that were in relatively immature areas. These injectors were known to have vertical conformance issues. The streamline model-based recommendations continued to be used through 2023. The models were updated with production and injection data quarterly. Injection rates were adjusted based on the updated injection efficiencies calculated from floodOPT with constraints based on the availability of injection volumes, well injectivity limitations, well failures and field facility limits. WAG parameters including cycle lengths and WAG ratios were set based on injection efficiency, area maturity and available CO2. Injectors with higher efficiency and lower maturity were allocated lower WAG ratios. CO2 allocation became more critical when purchases were eliminated in 2023. When the new flood management workflow was implemented, the field oil cut declines were approximately 14% pa with increasing GOR and WOR. Over a period of 6 months, favorable results were seen in these trends; GOR and WOR trends stabilized and reduced, and the oil cut decline was mitigated to less than 10% pa. Despite losing 20% of the available CO2 for injection, the oil rate in multiple patterns increased. The impact of the oil rate increase was difficult to observe on a field level because of multiple well failures and operational challenges. Nevertheless, field oil rate declines reduced from 14% pa to 9% pa; at the current decline rate, the improved management would yield an additional 300,000 bbls of oil production.

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Implementation of Streamline Derived Rate Targets Improved Oil Production of Mature Field

Cited by 3 publications

References 4 publications

Pressuredrop Response Characteristics for Multi-Injection Well Interfered Vertical Well in Heterogeneous Fractured Anticline Reservoirs

Pressuredrop Response Characteristics for Multi-Injection Well Interfered Vertical Well in Heterogeneous Fractured Anticline Reservoirs

Application of Streamline-Based WAG Injection Rate Management to Improve Oil Recovery of GLSAU CO2 Flood

Miscible Wag Management of a Mature CO2 Flood: A Streamline-Based Approach

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