Stock Tank Oil Research Articles

Comprehensive Basin Analysis and Petroleum Potential Evaluation of Ayoluengo Oil Field, Basque-Cantabrian Basin, Spain

This study presents a comprehensive basin analysis and petroleum potential evaluation of the Ayoluengo oil field in the Basque-Cantabrian Basin, Spain. Using an integrated approach combining geological, geophysical, and geochemical data, we analyzed the basin's evolution and petroleum system elements. The dataset included 2D and 3D seismic data, well logs, formation tops, and geophysical maps. Our analysis revealed a complex structural framework characterized by salt diapirism and halokinetic structures. Well log interpretation and sequence stratigraphic analysis identified two genetic sequences with associated systems tracts. Four reservoir units were mapped, with the main structural traps related to salt diapirs. Seismic facies analysis highlighted high-amplitude convergent (CBH) and high- and low-amplitude convergent (CBHL) facies as the most promising for reservoir quality. The study identified one play (Jurassic) and two prospects: Lias Limestone (80% geologic chance of success) and Carniolas Dolomite (85% geologic chance of success). Volumetric calculations estimate significant hydrocarbon potential, with STOIIP (Stock Tank Oil Initially In Place) ranging from 3.4 to 4.2 x 10^16 barrels for the Lias Limestone reservoir and 1.26 to 1.56 x 10^16 barrels for the Carniolas Dolomite reservoir.

A Systematical Review of the Largest Alkali-Surfactant-Polymer Flood Project in the World: From Laboratory to Pilots and Field Application

Summary This paper presents a systematical review of the largest alkali-surfactant-polymer (ASP) flood project in the world, applied to the largest oil field in China. First, reservoir and fluid characteristics are highlighted. Next, project history is summarized, including laboratory studies, pilot tests, industrial-scale tests, and fieldwide application. Third, typical ASP flooding performance and reservoir management measures from more than 30 years’ experience are presented. In addition, performances of ASP flood and polymer flood in the same field, which is also the largest project in the world, are compared. The Lamadian-Saertu-Xingshugang (La-Sa-Xing) Field in the Daqing Field Complex (including the La-Sa-Xing Field and three smaller satellite fields) is the largest oil field in China. The Upper Cretaceous Saertu-Putaohua-Gaotaizi reservoir has an average porosity of 25% and average permeability of 610 md. The reservoir consists of more than 100 flow units with an average gross and net thickness of 1,377 ft and 394 ft, respectively, and is characterized by significant heterogeneity, both vertically and laterally. The reservoir lies at a depth of 2,566–2,585 ft true vertical depth (TVD), with original reservoir pressure of 1,534–1,740 psi and a reservoir temperature of 113–122°F. Crude oil has an API gravity of 33° and a viscosity of 9 cp at reservoir conditions. The discussed ASP flood project mainly targets high-quality reservoir sands. The field was brought on-stream in 1960 with immediate waterflood. Crossflow and water breakthrough became common issues during water injection, calling for a suitable enhanced oil recovery (EOR) method. The Saertu-Putaohua-Gaotaizi reservoir features favorable conditions for ASP flood, such as temperature, viscosity, permeability, and formation water salinity (7000 mg/L). In addition, the heterogeneous reservoir (permeability variation coefficient of 0.6–0.8) is suitable for ASP flood. ASP flood was studied in the laboratory from 1987 to 1993, followed by five small-scale pilots from 1994 to 1999, all being successful with incremental recoveries of ~20% stock tank oil initially in place (STOIIP). As a result, industrial-scale tests were conducted from 2000 to 2007, resulting in substantial improvement in production from ~4,000 BOPD to greater than 19,000 BOPD. Encouraged by those successes, the ASP project was expanded to fieldwide since December 2007, which is the largest ASP flood project in the industry worldwide. By 2021, daily oil production by ASP flood had reached 96,000 BOPD through 4,825 producers and 4,825 injectors. The actual average incremental recovery factor is 20% over waterflood and 8–10% over polymer flood, resulting in ultimate recovery factor of >60%. Zonal injection and profile modification are effective measures to further improve sweeping efficiency. Scaling is the major challenge during the operation of ASP flood, which is mitigated or remediated by adopting weak alkali ASP, progressive cavity pumps (PCP), scale inhibitor treatment, and fracturing stimulation on damaged wells. As of 2022, oil production by ASP flood is still ongoing at 88,635 BOPD, accounting for 39.9% of total field production. The world’s largest ASP flood project in the La-Sa-Xing Field proved the fieldwide applicability of ASP flood, both technically and economically. The effective reservoir management measures and lessons learned from more than 30 years’ experience provide valuable experiences for large-scale ASP flood projects in the industry.

Analysis of Reservoir Properties and Quantification of Hydrocarbon Volumes Within LK Field, Niger Delta, Nigeria

This work analyzes and estimates the qualities and volumes of hydrocarbons in the identified reservoirs (Thin Sand and Sand B) of the LK field in the Niger Delta, Nigeria. The LK field is a promising hydrocarbon reservoir located at the border of the Greater Ughelli Depobelt in the Niger Delta Basin. The data utilized encompassed a 3D seismic survey, which was analyzed to delineate faults, identify stratigraphic horizons, and generate maps illustrating the time and depth structures within the subsurface. Well log data, including gamma ray, resistivity, and density/neutron measurements, were analyzed to evaluate and describe the petrophysical characteristics of the subsurface rock formations. The Thin Sand reservoir unit contains natural gas, while the Sand B reservoir is divided into two separate zones: the first zone (Z1) contains natural gas, and the second zone (Z2) contains oil. For Sand B, Z1, and Z2, the gross thicknesses are 13.16m and 57.46m, net thicknesses are 11.32m and 45.39m, NTGs are 0.86 and 0.79, shale volumes (Vsh) are 0.13 and 0.21, effective porosities (?e) are 0.28 and 0.21, water saturations (Sw) are 0.11 and 0.39, and hydrocarbon saturations (Sh) are 0.89 and 0.61, respectively. For the Thin Sand reservoir, the gross thickness is 6.00m, net thickness is 4.74m, NTG is 0.79, Vsh is 0.21, ?e is 0.23, Sw is 0.12, and Sh is 0.88. The stock tank oil initially in place (STOIIP) in the Sand B, Z2 reservoir is estimated to be 46.8 million barrels, with a recoverable oil volume of 9.4 million barrels, assuming a 20% recovery factor. The stock tank gas initially in place (STGIIP) is estimated at 10.4 billion cubic feet (Bcf) in the Thin Sand reservoir and 30.6 Bcf in the Sand B, Z1 reservoir, with recoverable gas volumes projected at 8.3 Bcf and 24.5 Bcf, respectively, assuming 80% recovery factors. After estimating the volume of hydrocarbons in the known reservoirs, significant and economic amounts of gas and oil for commercial purposes were discovered. However, this research study faces challenges such as uncertainty, unreliability, and varying scales due to different origins within the field. Further research using unconventional computational tools together with high-resolution simulating software is needed to produce more detailed and accurate results.

Integration of Seismic and Well Log Data for Reservoir Characterization in Offshore Niger Delta, Nigeria

The demand for fossil fuels is continually increasing due to the growing global population and industrialization. It is thus necessary to find hydrocarbon prospects in new fields and those that have previously been classified as marginal fields in order to maximize production. An integrated approach is required to effectively characterize hydrocarbon reservoirs and assess their ability to store and produce hydrocarbons. 3D seismic reflection data and well log data were combined to quantitatively estimate hydrocarbon reserves in a field, offshore Niger delta, Nigeria. The reservoirs were delineated on the gamma ray and resistivity logs which penetrate four wells selected from the field. The petrophysical analysis provided information about the net-to-gross thickness ratio, porosity, shale volume and water saturation of the reservoirs, deduced from well log suites comprising gamma, resistivity, density and neutron-porosity logs through four wells. The seismic interpretation involved mapping of horizons and faults across the wells on the seismic section. Check shot data were used to tie the seismic data to the well log data to generate the synthetic seismogram. The time structural and depth structural maps were generated. The volumetric analysis entailed derivation of the Gross rock volume from the depth structural map, and estimation of the Stock Tank Oil Initially In Place (STOIIP). Four reservoirs were delineated in each of the four wells. The average thickness of the reservoirs ranges from 56.6 m to 232.7 m while the water saturation varies from 0.29% to 0.57%. The average porosities of the reservoirs ranges from 0.18% to 0.22%. The structural interpretation of the eight faults mapped reveals synthetic and antithetic faults, and rollover anticlines. The time- and depth structural maps generated from the mapped horizons show that the reservoirs are penetrated by the different faults. The Stock Tank Oil Initially In Place (STOIIP) of the reservoirs range from 25 MMstb to 468 MMstb. The study shows that the integration of 3D reflection data and well log data can be used effectively to estimate hydrocarbon reserves. The results of the study are expected to contribute to the development of new exploration and production strategies in the Niger delta basin and similar sedimentary environments.

High-pressure phase equilibrium and volumetric properties of pseudo-binary mixtures of stock tank oil + nitrogen/carbon dioxide up to 463K

High-pressure phase equilibrium and volumetric properties of pseudo-binary mixtures of stock tank oil + nitrogen/carbon dioxide up to 463K

Movable and non-movable hydrocarbon fractions in an oil-depleted sandstone reservoir considered for CO2 storage, Nini West Field, Danish North Sea

The Paleocene–Eocene quartz- and glauconite-rich reservoir sandstones of the depleted Nini West oilfield in the Siri Canyon, Danish North Sea, are considered a CO2 storage site. Mobilization of the remaining oil in the reservoir by the injected supercritical CO2 (scCO2) can cause oil displacement and potentially clogging of pore throats by the non-soluble heavy oil fraction. This study focuses on the movable and non-movable oil and solid bitumen/asphaltenes fractions present in the Nini West reservoir, including the effect of scCO2 injection on the residual oil. The residual oil in 14 samples from 13 core plugs from the oil-leg of the Nini-4 well was analyzed, as well as the extracted oil from preserved samples and the Nini stock tank oil (STO). The samples were acquired from preserved, cleaned, restored, and scCO2 flooded core plugs and were analyzed by organic geochemistry, including extended slow heating pyrolysis (ESH®) and organic petrography. The STO is paraffinic with a fairly high asphaltene content, and the preserved samples show that the residual oil occurs in association with glauconite clasts. The extracted oil consists mainly of movable oil fractions and a smaller amount of non-movable oil and solid bitumen/asphaltenes. The organic solvents used in different cleaning methods could remove most of the oil in the samples, but none of them can completely remove the solid bitumen/asphaltenes adhered to the glauconite clasts. The orange-brownish fluorescing solid bitumen/asphaltenes occur in the interior of the glauconite clasts, as coatings on the surface, and in small cracks in the surface, as well as between the laminae of glauconised mica. A sample from a cleaned core that has been restored to original wettability condition while controlling oil and brine saturations, and aged for a month at reservoir conditions, has an oil composition akin to the preserved samples. By scCO2 flooding, the movable oil fractions are entirely removed while the solid bitumen/asphaltenes coatings and remnants in the interior of the glauconite clasts are not mobilized. The presence of solid bitumen/asphaltenes in the organic solvent cleaned samples and in the scCO2 flooded sample suggests that these compounds are highly non-movable. Furthermore, a low proportion of heavy non-movable oil in the scCO2 flooded samples indicates minor asphaltenes precipitation, perhaps due to the high permeability and homogeneity of the sandstones.

Study Reviews Largest ASP Project From Laboratory to Pilots and Field Application

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 215058, “A Systematic Review of the Largest ASP Flood Project in the World: From Laboratory to Pilots and Field Application,” by Yunan Wei, SPE, Xiaoguang Lu, SPE, and Jianhong Xu, SPE, C&C Reservoirs, et al. The paper has not been peer reviewed. _ The complete paper presents a systematic review of the largest alkaline-surfactant-polymer (ASP) flood project in the world, applied in the largest oil field in China. First, reservoir and fluid characteristics are highlighted to understand heterogeneity of the reservoir. Next, project history is summarized, including laboratory studies, pilot tests, industrial-scale tests, and fieldwide application. Finally, typical ASP flood performance and reservoir management measures from over 30 years of experience are presented. Performances of ASP flood and polymer floods in the same field also are compared.​​​​ Introduction In the La-Sa-Xing Field, ASP flooding was studied in the laboratory from 1987 to 1993 and followed by five small-scale pilots from 1994 to 1999, all successfully achieving incremental recoveries of approximately 20% stock-tank oil initially in place (STOIIP). As a result, industrial-scale pilots were conducted from 2000 to 2007, resulting in increased production by ASP flooding from 3,887 to greater than 19,000 BOPD in 2007. Fieldwide ASP expansion was launched in December 2007. By 2021, the ASP-flooded blocks registered a STOIIP of 1.9823 billion bbl. Daily production was approximately 96,000 BOPD through approximately 9,650 wells. Average incremental recovery factor was 20% STOIIP with waterflooding and 8% with polymer flooding, providing an ultimate recovery factor of 60%. Cumulative oil production by ASP flooding had reached 316 million bbl by 2021, making it the largest ASP flooding project in the world. Geological Background and Reservoir Characteristics The La-Sa-Xing Field is in the north of the Songliao Basin of northeast China, comprising the majority of the Daqing field complex. The field was placed onstream in 1960. The hydrocarbon-bearing reservoir has a gross thickness of 1,377 ft and a net thickness of 394 ft. Net pay averages 150 ft. Initial reservoir pressure ranges from 1,523 to 2,585 psi. Reservoir temperature varies from 113 to 122°F. Crude oil has an API gravity of 33°, a viscosity of 8.5–10.3 cp at reservoir conditions, an initial gas/oil ratio of 258 scf/STB, and a bubblepoint pressure of 1,291 psi. Formation water salinity is 7000 mg/L. Reservoir rock initially shows water or weak oil wettability. Depending on permeability, three types of reservoir sand (Type I, Type II, and Type III) have been identified. Currently, ASP flooding is mainly applied to Type I sand, with partial application to Type II Sand.

Efforts Lead to Formulation of High-Performance ASP

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 22729, “ASP Formulation Development Journey: Optimization, Validation, and Quality Control for Mangala Field,” by Nitish Koduru, Dhruva Prasad, SPE, and Amitabh Pandey, SPE, Cairn Oil and Gas. The paper has not been peer reviewed. Copyright 2023 International Petroleum Technology Conference. Reproduced by permission. _ Mangala is a large low-salinity, high-quality fluvial oil field in India with stock-tank oil initially in place (STOIIP) of more than 1 billion bbl of waxy and moderately viscous crude. Aqueous-based chemical enhanced oil recovery (EOR) has been identified as the most suitable technique to improve recovery over waterflooding. The objective of the complete paper is to describe alkaline/surfactant/polymer (ASP) formulation development for Mangala, which involved more than 30 corefloods at the time of writing, with formulation design changing over time. Field Background The Mangala field has been regarded as an excellent chemical EOR candidate since its discovery in 2004. The main reservoir unit is divided into the Lower and Upper Fatehgarh formations. These units are subdivided into five reservoir units, FM1 to FM5 from top to bottom. Mangala contains waxy sweet crude oil with gravity ranging from 20 °API near the oil/water contact to 28 °API in the oil column. The crude has in-situ viscosity of 9–17 cp. The crude has good napthenic acid content and reacts with alkali to produce in-situ soap. Immediately after the field’s appraisal stage, work to identify the most suitable EOR process began. First, a polymerflooding pilot was conducted during 2011–12. The encouraging results led to full-field polymerflooding implementation in November 2014. The ASP pilot performed well; incremental oil recovery over polymerflooding was estimated to be in the range of 20–25% of the pilot STOIIP. The initial development plan involved implementing a hot waterflooding production startup to maintain reservoir pressure and effective sweep. The Upper Fatehgarh FM1 and FM2 units were developed with inverted nine-spot patterns, while the more-homogeneous lower Fatehgarh (FM3 and FM4) were developed with downdip injectors and updip horizontal producers. The Mangala field began producing under a hot waterflood in 2009, with the injected water heated to approximately 80–85°C to avoid wax deposition. Injection was started within a few months of first production. At the time of writing, the field is under polymerflooding, with results largely in line with expectations. The field, which has already produced approximately 37% of the STOIIP, is on a declining production trend, and large-scale ASP flooding is being considered as the next development initiative to arrest production decline and increase overall recovery. The complete paper discusses EOR screening studies; ASP formulations, including the initial formulation; the method adopted for selection of chemical suppliers for the pilot test; optimization of ASP formulations tested in the pilot; validation of the developed formulation to other layers of the field; and planned quality-control processes to be used during procurement of chemicals for larger applications of ASP floods in the field. This synopsis concentrates on the last three of these factors, rather than the formulations considered, which, in addition to the initial formulation, included the following: - Formula 2: ASP formulation with a sacrificial surfactant - Formula 3: ASP formulation with a single surfactant - Formula 4: Formulation with a highly hydrophilic, large-hydrophobe surfactant

Lithofacies, Deposition, and Clinoforms Characterization Using Detailed Core Data, Nuclear Magnetic Resonance Logs, and Modular Formation Dynamics Tests for Mishrif Formation Intervals in West Qurna/1 Oil Field, Iraq

Summary This study considered the complexity of Mishrif geology and its effect on fluid movement within and across Mishrif reservoir intervals. For this purpose, we analyzed the following items: the multiple interval communication with high permeability contrast, the geological setting of the upper Mishrif (mA) interval, the channel structure in the Lower Mishrif-Part 1 (mB1) interval, the thin layers in the upper part of Lower Mishrif-Part 2 (mB2U) of very high permeability, and the microporous interval of the lower part of Lower Mishrif-Part 2 (mB2L); none of them were well defined before this work. The bottom interval of Mishrif or Rumaila (mC) is predominantly microporous, and the best reservoir is at the top of intermediate quality. Two high-porosity layers are systematically found in the mC unit, which is casually referred to as “rabbit ears.” The mB2L contains grainstones in the far north of the West Qurna/1 oil field (WQ1). In the south of mB2L, some of the toe sets from the clinoforms in a distal depositional setting have developed into rather important vertical pressure baffles and barriers to vertical flow. The mB2U generally consists of grainstones with thin streaks of mudstone high flow layers (HFLs), and the rocks underneath are described generally as grainstone shoals. About 80% of stock tank oil originally in place (STOOIP) in mB2U exists in grainstones. There are no known microporous reservoirs in mB2U. The pressure difference across the boundaries between mB1 and mA can be positive or negative. At the base, mB1 channels are always in pressure communication with the mB2U below. The best flow from the mA comes from HFLs, which are found around faults. Reservoir quality within mA is generally best in the first section of the upper Mishrif (mAa), and the majority of STOOIP in mA exists in microporous rocks, while some 30% of STOOIP is contained in grainstones.

Estimating electrical resistivity from logging data for oil wells using machine learning

Formation resistivity is crucial for calculating water saturation, which, in turn, is used to estimate the stock-tank oil initially in place. However, obtaining a complete resistivity log can be challenging due to high costs, equipment failure, or data loss. To overcome this issue, this study introduces novel machine learning models that can be used to predict the electrical resistivity of oil wells, using conventional well logs. The analysis utilized gamma-ray (GR), delta time compressional logs (DTC), sonic shear log (DSTM), neutron porosity, and bulk density. The study utilized a dataset of 3529 logging data points from horizontal oil carbonate wells which were used to develop different machine learning models using random forest (RF) and decision tree (DT) algorithms. The obtained results showed that both models can predict electrical resistivity with high accuracy, over 0.94 for training and testing data. Comparing the models based on accuracy and consistency revealed that the RF model had a slight advantage over the DT model. Based on the data analysis, it was found that the formation resistivity is more significantly impacted by GR logs compared to DTC logs. These new ML models offer a low-cost and practical alternative to estimate well resistivity in oil wells, providing valuable information for geophysical and geological interpretation.

Petroleum system analysis-conjoined 3D-static reservoir modeling in a 3-way and 4-way dip closure setting: Insights into petroleum geology of fluvio-marine deposits at BED-2 Field (Western Desert, Egypt)

Imperfect determination of petroleum system processes coincidence, entrapment and charge timing, along with reservoir heterogeneity can considerably cause high risks throughout exploration and development phases of petroleum. Therefore, a complete subsurface visualization of the petroleum system nature, elements and processes, is badly required. To this end, we corroborated, in this study, static reservoir modeling with petroleum system analysis workflows, to better characterize the Cenomanian fluvio-marine reservoir, sandstones of Bahariya Formation, at Bed-2 Field, Abu Gharadig basin (Western Desert, Egypt). We used dataset of 2D seismic profiles and well logs of eight wells. The geometry and property of the reservoir were acquired performing static reservoir geocellular modeling approach. The geohistory, timing of charge, migration pathways, and accumulation sites were identified performing 1D and 2D basin modeling approaches. Combining both approaches was aimed at identifying new petroleum prospect areas, and estimating the hydrocarbon volumes, that are the need for such poorly-defined petroleum systems area. As indicated by the constructed, robust, reservoir and 1D-2D basin models, an additional hydrocarbon prospect, to the north central part of Bed-2 Field, is proposed to be drilled during the further oilfield development phases of the area. This prospect has all features that adequately lead to reliable inferences regarding the ultimate petroleum potential of the area. • Reservoir modeling delineating geometry and property, with depositional facies analysis unlocking reservoir heterogeneity • Petroleum system analysis workflow defining the hydrocarbon charge timing, confirming the hydrocarbon potential of the area • Pixel-based stochastic simulation algorithms modeling the rock property. • Hydrocarbon volumes assessment, gas initially in place (GIIP) and stock-tank oil initially in place (STOIIP), in the area • Defining new prospect areas, justifying future oilfield development plans

Seismic Interpretation and Reservoir Static Model: A Case Study in Block MFK, Riau Province, Indonesia

MFK Block was located between Kampar and Rokan Hulu, Riau Province and 135 from Pekanbaru City, Indonesia. There are 33 wells in Field X, MFK Block with 27 active wells. This field has an area of about 79.65 km2 that located in Central Sumatra Basin. The field was discovered in 1976 and began to be produced in January 1979. Our research is focused on AK reservoir intervals, which is also part of Bekasap formation. The main aims of this study are to interpret field structure model, determine the distribution of reservoir properties, develop static reservoir model for field as a reference for field performance enhancement, estimate oil reserves in the field reservoir, and the prospect of hydrocarbons in the AK reservoir. The available data are 2D seismic data, mudlog descriptions, well log data, and perforation data. The methods used in this study are stratigraphic sequences, electrofacies analysis, geological structure analysis, static reservoir modelling, and estimation of hydrocarbon reserve volumes. Based on mudlog and electrofacies analysis, the study interval was arranged into 2 lithofacies units, namely sand channel and sand bar. The depostion environment of Bekasap Formation is estuarine environments. The interval of the study has an association of fasies moving northeast to southwest. Based on the results of property reservoir analysis, facies that have good reservoir quality is sand channel facies. Based on the static modeling method approach, the estimated stock tank oil initially in place (STOIIP) for AK reservoir interval is 728 MBBL.

Decoding the Impact of Injection-Induced Fractures on the Sweep Efficiency of a Mature Polymer Flood through Pressure Falloff Analysis

Summary Polymer flooding is one of the most popular chemical enhanced oil recovery processes in the world, with many large-scale commercial field implementations. It improves mobility ratio and sweep efficiency over waterflooding. However, injection of high volumes of viscous fluid at high injection pressures almost inevitably induces fractures. Induced fractures are not necessarily negative for the flood, and they are documented to improve injectivity and reduce shear degradation of polymer. The big question is on their effect on areal and vertical sweep efficiency. Mangala is one of the largest and most commercially successful polymer floods in the world. The FM-1 unit has the highest stock tank oil initially in place among all the layers of Mangala. Polymer flood sweep efficiency in FM-1 is excellent despite the presence of injection-induced fractures and geological layering. Pressure falloff (PFO) studies are an important and inexpensive source of monitoring the growth of induced fractures in mature polymer floods. Extensive work has been done in the past to derive analytical solutions and numerically assisted solutions for polymer PFOs for non-Newtonian rheology and induced fractures with variable storage. There is also extensive and sometimes contradictory literature on polymer rheology in porous media at both high and low flux rates. Most of the work on polymer PFOs have published a few field examples or synthetic examples and addressed specific issues in depth. We have interpreted 40 PFOs carried out over a period of 1 year. All relevant data sources in the field on geomechanics, polymer rheology in core and rheometers, temperature logs, and saturation logs were integrated to get a consistent estimate for fracture half-length. The results provide insight into the role of induced fractures in improving the sweep efficiency of FM-1. The arguments are backed with literature survey. The work can be used by operators around the world to manage mature polymer floods. The observations mentioned in the work can be used by researchers to fine tune their work. Secondary hypothesis on polymer rheology in porous media is also derived out of the work, which may be of academic interest and merit further work. There are other important aspects of polymer flood PFOs, such as impact of suspended solids and rock dilation near wellbore, which have not been explored in the paper.

Probabilistic Approach Guides Field Development Plan in Niger Delta

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 207146, “Conceptual Field Development Plan for X Field,” by Khadijah Ibrahim, SPE, Petrus Nzerem, and Ayuba Salihu, SPE, Nile University of Nigeria, et al. The paper has not been peer reviewed. _ The development plan of a new oil field discovered in a remote offshore environment in the Niger Delta was evaluated. Because the oil in place was uncertain, a probabilistic approach was used to estimate the stock-tank oil originally in place (STOOIP) using low, base, and high cases. The base model is recommended for further implementation. The quantity of oil produced is estimated at 15,000 STB/D, which will require a separator that has the capacity of holding a liquid rate of approximately 20,000 STB/D. The authors find that this developmental plan is cost-effective. Introduction Field X is offshore Nigeria in water depths of 330 ft. The field has an uncertain oil in place, with a possibility of low, base, and high cases. The field reservoir information is available from the exploration and seismic well data provided. The field size (i.e., STOOIP) is estimated at 95 million (low), 145 million (base), and 300 million (high) STB, with an irreducible water saturation of 22%. The reservoir depth is 7,400 ft true vertical depth subsea (TVDSS), with a net pay thickness of 45 ft. The aquifer supporting the reservoir has a strength of 9, with a permeability of 200 md and a porosity of 18%. Generally, the reservoir has permeability and compressibility of the rock formation obtained from the log results of 250 md and 3.5×10–6 psi–1. The reservoir pressure is measured to be 3,400 psia. The field development plan will incorporate production forecasts from the target date of first production, 1 January 2023, through 1 January 2038, for a 15-year field life. The complete paper presents the field development strategies and economic analysis of different well models to evaluate the most-efficient modeling profile for the new field. Methodology Well-Modeling Profile and Performance Analysis. It is assumed that the field will be produced using a platform with a wellhead reference depth of 20 ft above the rotary kelly bushing. The well is assumed to be a vertical well with no deviation. The skin value is estimated to be 1, thereby having a slight effect on the productivity index. Pressure/volume/temperature (PVT) data were available for the oil in place. Using commercial software, the fluid parameters for bubblepoint pressure, oil volume factor, and oil viscosity were matched in the PVT analysis at a reservoir temperature of 170°F and a pressure of 3,400 psia. The measurements of formation volume factor, gas/oil ratio, and oil viscosity at this pressure were used to provide a single match point for the generation of PVT data.

Technology Focus: Field Development (September 2022)

In this month’s Field Development feature, SPE conference authors place an emphasis not only on original research and findings but also on validation and refinement of existing techniques that may not have received thorough attention in the literature. As operators strive to achieve the greatest returns possible from technically, environmentally, and economically challenging plays, they are driven to innovate new approaches and to fine-tune existing ones. In paper SPE 206267, the authors investigate the performance of a distributed quasi-Newton (DQN) derivative-free optimization (DFO) method, which, they write, had not yet been validated by realistic applications or compared with other DFO methods. They integrate DQN into a versatile field-development optimization platform designed for iterative work flows enabled through distributed parallel flow simulations. The method was field-tested on two realistic applications and identified the global optimum with the least number of simulations and the shortest run time on a synthetic problem with a known solution. The authors of paper SPE 207146 create and evaluate a development plan for an oil field discovered in a remote offshore environment in the Niger Delta. Because the oil in place was uncertain, a probabilistic approach was used to estimate the stock-tank oil originally in place using low, mid, and high cases. Keeping in mind governmental regulations to maintain the reservoir pressure above bubblepoint, the authors propose a development plan that is marginally base modeled and, despite the uncertainty of oil prices in the market, able to cover any unforeseen situations. Finally, the authors of paper SPE 208882, addressing the challenge posed by cumbersome integrated technical work flows for multiwell fracture modeling and reservoir simulation, use tools existing in the literature to quantify the effect of changing well spacing on well productivity for a given completion design using a simple, intuitive empirical equation. After describing and qualifying the use of their approach, they apply it to a case study from the Permian Basin. Recommended additional reading at OnePetro: www.onepetro.org. OTC 31151 - Autonomous Subsea Field Development—Value Proposition, Technology Needs, and Gaps for Future Advancement by Giorgio Arcangeletti, Saipem, et al. SPE 206533 - Field Development Optimization Using Machine-Learning Methods To Identify the Optimal Waterflooding Regime by Alexey Vasilievich Timonov, Consultant, et al. URTeC-2021-5301 - Unconventional Reservoir Development Performance Reviews—the Northern Midland Basin Case Study by Hongjie Xiong, University Lands, et al.

Pattern-Review Technique Maximizes Hydrocarbon Recovery in Complex Brownfield

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 203100, “Maximizing Hydrocarbon Recovery and Water-Injection Support Through Pattern Reviews Between Injector/Producer Pairs in a Large, Complex, and Faulted Brownfield in Southeast Asia,” by Arfan Ali, Manish K. Gupta, and Reza Salleh, Brunei Shell, et al. The paper has not been peer reviewed. _ Large, complex, faulted structures often pose substantial challenges in maximizing hydrocarbon recovery. The work presented in this paper has used what the authors call a “pattern-review” technique in a brownfield containing more than 500 well penetrations in southeast Asia. For the first time in field history, pattern reviews have been used extensively as a tool to understand reservoir connectivity and dynamic fluid movements across the field. An integrated effort involving different data sources and disciplines has provided fresh insights into the reservoirs that would have otherwise been difficult in heterolithic stacked reservoirs. Introduction The Champion field is 40 km offshore Brunei Darussalam in water depths of approximately 40 m. The field has a long, complex development history spanning almost 50 years. The field contains more than 45 platforms and well jackets. There are approximately 700 conduits in approximately 450 wellbores. For simplification, the field history has been divided into three main phases: - Phase I: Period of rapid expansion (focus on development of the Champion field main area) - Phase II: Period of consolidation (focus on waterflood initiation and development away from the main field area) - Phase III: Period of rejuvenation (focus on expansion in waterflood development) Because of the field’s complexity and unmappable flank areas, Phase I progressed outward from the center of the field. Appraisal wells from the existing platforms and other, isolated locations were targeted into unappraised blocks. This method of appraising and developing from known to less-known areas worked well in the initial development of the field. Phase II saw an increased emphasis on drilling water injectors in addition to infill oil producers. The lack of water injection and the resulting depletion in the main producing reservoir sands escalated the need for a Phase III development of the field. This phase heavily emphasized ramping up water injection in the field with the aim of forming a line-drive waterflood pattern between injector/producer pairs. The primary structure in the Champion field is a large anticline feature that is interpreted as a rollover into a regional west-heading growth fault system. Fault throws and transmissibilities vary across the entire field, with faults sealing increasingly from shallower to deeper reservoirs. Multiple sets of 3D seismic data have been acquired over the history of the field. In early 2020, a seismic ocean-bottom node survey was acquired over the field. In addition to the main bounding faults, several small-scale faults present randomly within the individual fault blocks. Ant-track maps have been used along with the seismic fault-structure map to understand these barriers. The reservoirs in the field consist of Miocene shallow marine, coastal, and deltaic sediments. The shallow reservoirs are heterolithic in nature. Not many wells have targeted these shallower reservoir intervals. A considerable amount of uncertainty surrounds the oil/water contact (OWC) in the field. As a result, a significant proportion of standard stock-tank oil initially in place remains in the ground.

Mangala Polymer Flood Performance: Connecting the Dots Through In-Situ Polymer Sampling

Summary The Mangala field contains medium-gravity viscous crude oil. Notably, it is the largest polymer flood in India and 34% of the stock tank oil initially in place (STOIIP) has been produced in 11 years. Mangala was put on full field polymer flood in 2015, 6 years after the start of field production on waterflood in 2009. Polymer flood added nearly 93 million barrels above the anticipated waterflood recovery in 6 years. Reservoir simulation models could replicate the initial Mangala polymer flood performance. However, the performance of the lower layers of Mangala (FM-3 and FM-4) continued to progressively deviate from modeling estimates. Importantly, the observed polymer breakthrough deviated significantly from predictions. As the polymer flood matured, the trend of field water cut with time indicated that in-situ polymer viscosity was equivalent to only 50 to 60% of the surface polymer viscosity. For better predictions and corrective actions, it was necessary to understand the nature of degradation, the progressively deteriorating field performance, especially of the lower layers, and the deviation of polymer breakthrough trends from predictions. Carefully designed in-situ polymer sampling, laboratory studies, and reservoir modeling studies helped connect the dots to understand the field performance. There are several excellent publications on accelerated aging studies and some on polymer sampling. This paper offers an opportunity to directly compare experimental results with field data. The procedures used and lessons learned during field sampling can be useful for other operators for management of polymer floods.

Construction of Comprehensive Geological Model for an Iraqi Oil Reservoir

The paper generates a geological model of a giant Middle East oil reservoir, the model constructed based on the field data of 161 wells. The main aim of the paper was to recognize the value of the reservoir to investigate the feasibility of working on the reservoir modeling prior to the final decision of the investment for further development of this oilfield. Well log, deviation survey, 2D/3D interpreted seismic structural maps, facies, and core test were utilized to construct the developed geological model based on comprehensive interpretation and correlation processes using the PETREL platform. The geological model mainly aims to estimate stock-tank oil initially in place of the reservoir. In addition, three scenarios were applied based on sensitivity and uncertainty of five variables to determine an accurate estimation of stock-tank oil initially in place of the reservoir. The oil-water contact appeared to be the major uncertain parameter for stock-tank oil initially in place estimation because the available geological and field data was not enough to demonstrate it confidently, and only 13% of the total wells have penetrated the water zone in the Mishrif formation. The results of all scenarios indicate that the reservoir has huge stock-tank oil initially in place. The importance of developing this oilfield is validated by its very high stock-tank oil. This is where the value of this study becomes obvious.

The effect of asphaltene molecular characteristic on the instability of Kuwaiti crude oils

Asphaltene precipitation and subsequent deposition are challenging problems that hinder the continuous production of crude oil in many fields worldwide. In the present work, advanced technologies were implemented to effectively assess the effect of asphaltene characteristics on its stability in different Kuwaiti oils. Physical and chemical properties of stock tank oils (STO) have been measured. The extracted asphaltenes from the different STOs were characterized using X-ray diffraction (XRD) and Fourier Transform Infrared (FT-IR) spectroscopy techniques. The results showed that asphaltene with the lowest H/C ratios, the greatest aromaticity, and the highest degree of condensation exhibited a higher tendency to precipitate due to extreme variations in thermodynamic factors. The onset of asphaltene precipitation for crude oil was determined by the indirect method using three different n-alkane solvents. The onset of asphaltene precipitation was found to be around 40, 50, and 60 vol% of n-pentane, n-heptane, and n-octane, correspondingly. Thus, indicating that low molecular weights alkanes have a higher tendency to precipitate a wider range of soluble asphaltene in the crude. Moreover, asphaltene that was characterized to be the least stable showed the lowest asphaltene onset point detected by the indirect method.

Hydrocarbon Reservoir Characterization of ‘Khume’ Field, Offshore Niger Delta, Nigeria

The integrative approach of well log correlation and seismic interpretation was adopted in this study to adequately characterize and evaluate the hydrocarbon potentials of Khume field, offshore Niger Delta, Nigeria. 3-D seismic data and well logs data from ten (10) wells were utilized to delineate the geometry of the reservoirs in Khume field, and as well as to estimate the hydrocarbon reserves. Three hydrocarbon-bearing reservoirs of interest (D-04, D-06, and E-09A) were delineated using an array of gamma-ray logs, resistivity log, and neutron/density log suites. Stratigraphic interpretation of the lithologies in Khume field showed considerable uniform gross thickness across all three sand bodies. Results of petrophysical evaluations conducted on the three reservoirs correlated across the field showed that; shale volume ranged from 7-14%, total and effective porosity ranged from 19-26% and 17-23% respectively, NTG from 42 to 100%, water saturation from 40%-100% and permeability from 1265-2102 mD. Seismic interpretation established the presence of both synthetic and antithetic faults. A total of six synthetic and four antithetic faults were interpreted from the study area. Horizons interpretation was done both in the strike and dip directions. Time and depth structure maps revealed reservoir closures to be anticlinal and fault supported in the field. Hydrocarbon volumes were calculated using the deterministic (map-based) approach. Stock tank oil initially in place (STOIIP) for the proven oil column estimated for the D-04 reservoir was 11.13 MMSTB, 0.54 MMSTB for D-06, and 2.16 MMSTB for E-09A reservoir. For the possible oil reserves, a STOIIP value of 7.28 MMSTB was estimated for D-06 and 6.30 MMSTB for E-09A reservoir, while a hydrocarbon initially in place (HIIP) of 4.13 MMSTB of oil equivalents was derived for the undefined fluid (oil/gas) in D-06 reservoir. A proven gas reserve of 1.07 MMSCF was derived for the D-06 reservoir. This study demonstrated the effectiveness of 3-D seismic and well logs data in delineating reservoir structural architecture and in estimating hydrocarbon volumes