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Results
Integration of NMR Factor Analysis, Multifunction LWD Measurements, and T2 Modeling Improve Fluid Identification in Complex Carbonate Reservoirs
Permanasari, Dian (Schlumberger) | Ernando, Zeindra (PC Ketapang II Ltd.) | Nordin, Taufik B (PC Ketapang II Ltd.) | Johari, Azlan Shah B (PC Ketapang II Ltd.) | Muhammad, Fierzan (PC Ketapang II Ltd.)
Abstract Carbonate environments are complex by nature and the characterization, based on their petrophysical properties, has always been challenging due to the pore heterogeneity. In this paper, we present the integration of factor analysis applied to while-drilling Nuclear Magnetic Resonance (NMR) data, full-suite data from a multifunction logging-while-drilling (LWD) tool, and modeling of the NMR T2 transverse relaxation time to improve the fluid typing interpretation in complex carbonate reservoirs. The interpretation results are essential for perforation and completion decisions in a high-angle development well. The carbonate reservoirs in this case study are within the Kujung formation in the East Java Basin. Kujung I is a massive carbonate reservoir with abundant secondary porosity, while Kujung II and III consist of interbedded thin carbonate reservoirs and shale layers. High uncertainty in identifying the fluid type existed in the Kujung II and III formations due to the presence of multiple fluids in the reservoir, the effect of low water salinity, as well as pore heterogeneity and diagenesis. Due to the high-angle well profile, LWD tool conveyance became the primary method for data acquisition. NMR while drilling and multifunction LWD tools were run on the same drilling bottomhole assembly (BHA) to provide complete formation evaluation and fluid identification. The NMR factor analysis technique was used to decompose the T2 distribution into its porofluid constituents. Thorough T2 peaks modeling was performed to interpret the fluid signatures from the factor analysis results. Borehole images, caliper, triple-combo, density-magnetic resonance gas corrected porosity (DMRP), as well as time-lapse data were evaluated to identify the presence of secondary porosity and narrow down the T2 fluid signatures interpretation. Each of the porofluid signatures were identified and validated in the Kujung I formation with its proven gas and thick water zone. These signatures were then used as references to interpret the fluid types in the Kujung II and III formations. Gas was identified by a low-amplitude peak in the shorter T2 range between 400 ms to 1 s. Oil or synthetic oil-based mud (SOBM) filtrate was indicated by a high-amplitude peak in the longer T2 range (>1.5 s). The water signatures are very much dependent on the underlying pore sizes. Larger pore sizes will generate longer T2 values, which could fall into the same T2 range as hydrocarbon. For that reason, it is important to combine the NMR porofluid signatures interpretation with other LWD data to restrict the fluid type possibilities. This integrated methodology has successfully improved the fluid type interpretation in the Kujung II and III thin carbonate reservoir targets and was confirmed by the actual production results from the same well. This case study presents excellent integration of LWD NMR with other LWD data to reduce fluid type uncertainties in complex carbonate reservoirs, which were unresolved by conventional interpretation methods. Based on this success, a similar integrated NMR factor analysis method can be applied to future development wells in the same field.
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.50)
Single-Phase Retarded Inorganic Acid Optimizes Remediation of Drilling Formation Damage in High-Temperature Openhole Horizontal Carbonate Producer
Fawzy, Ahmed Mohamed (ADNOC Onshore) | Talib, Noor Nazri (ADNOC Onshore) | Makhiyanov, Ruslan (ADNOC Onshore) | Naseem, Arslan (ADNOC Onshore) | Molero, Nestor (Schlumberger) | Khan, Rao Shafin (Schlumberger) | Enkababian, Philippe (Schlumberger) | Belkadi, Wafaa (Schlumberger) | ElAttar, Ahmed (Schlumberger) | Ibrahim, Amer (Schlumberger)
Abstract In high-temperature carbonate producers, conventional hydrochloric (HCl) acid systems have been ineffective at delivering sustainable production improvement due to their kinetics. Retarded acids are deemed necessary to control the reaction and create effective wormholes. This scenario is even more critical in wells completed across long openhole horizontal intervals due to reservoir heterogeneity, changing downhole dynamics, and uniform acid placement goals. Out of the different retarded acid options, emulsified acid is one of the preferred choices by Middle East operators because of its excellent corrosion inhibition and deep wormhole penetration properties. However, it also brings other operational complexities, such as higher friction pressures, reduced pump rates, and more elaborate mixing procedures, which in some cases restrict its applicability. The recent introduction of a single-phase retarded inorganic acid system (SPRIAS) has enabled stimulation with the same benefits as emulsified acids while eliminating its drawbacks, allowing friction pressures like that of straight HCl and wormholing performance equivalent to that of emulsified acid. A newly drilled oil producer in one of the largest carbonate fields in onshore Middle East was selected by the operator for pilot implementation of the SPRIAS as an alternative to emulsified acid. The candidate well featured significant damage associated with drilling, severely affecting its productivity. The well was completed across 3,067 ft of 6-in. openhole horizontal section, with a bottomhole temperature of 285°F, permeability range of 0.5 to 1.0 md, and an average porosity of 15%. Coiled tubing (CT) equipped with fiber optics was selected as the fluid conveyance method due to its capacity to enable visualization of the original fluid coverage through distributed temperature sensing (DTS), thus allowing informed adjustment of the stimulation schedule as well as identification of chemical diversion and complementary fluid placement requirements. Likewise, lower CT friction pressures from SPRIAS enabled the utilization of high-pressure jetting nozzle for enhanced acid placement, which was nearly impossible with emulsified acid. Following the acidizing treatment, post-stimulation DTS showed a more uniform intake profile across the uncased section; during well testing operations, the oil production doubled, exceeding the initial expectations. The SPRIAS allowed a 40% reduction in CT friction pressures compared to emulsified acid, 20% optimization in stimulation fluids volume, and reduced mixing time by 18 hours. The experience gained with this pilot well confirmed the SPRIAS as a reliable option to replace emulsified acids in the region. In addition to production enhancement, this novel fluid simplified logistics by eliminating diesel transportation, thus reducing equipment and environmental footprints. It also reduces friction, thus enabling high-pressure jetting via CT, leading to more efficient stimulation with lower volumes.
- North America > United States (0.70)
- Europe (0.68)
- Asia > Middle East > UAE (0.29)
Tight Jurassic Carbonate Reservoir Characterization and Fluid Typing Identification by Integrating Magnetic Resonance, Elemental Spectroscopy and Micro-Resistivity Image Data in Umm Ross Field, West Kuwait, Case Study
Mohamed, Said Beshry (Weatherford) | Ali, Sherif (Weatherford) | Fahmy, Mahmoud Fawzy (KOC) | Al-Saqran, Fawaz (KOC)
Abstract The Middle Marrat reservoir of Jurassic age is a tight carbonate reservoir with vertical and horizontal heterogeneous properties. The variation in lithology, vertical and horizontal facies distribution lead to complicated reservoir characterization which lead to unexpected production behavior between wells in the same reservoir. Marrat reservoir characterization by conventional logging tools is a challenging task because of its low clay content and high-resistivity responses. The low clay content in Marrat reservoirs gives low gamma ray counts, which makes reservoir layer identification difficult. Additionally, high resistivity responses in the pay zones, coupled with the tight layering make production sweet spot identification challenging. To overcome these challenges, integration of data from advanced logging tools like Sidewall Magnetic Resonance (SMR), Geochemical Spectroscopy Tool (GST) and Electrical Borehole Image (EBI) supplied a definitive reservoir characterization and fluid typing of this Tight Jurassic Carbonate (Marrat formation). The Sidewall Magnetic resonance (SMR) tool multi wait time enabled T2 polarization to differentiate between moveable water and hydrocarbons. After acquisition, the standard deliverables were porosity, the effective porosity ratio, and the permeability index to evaluate the rock qualities. Porosity was divided into clay-bound water (CBW), bulk-volume irreducible (BVI) and bulk-volume moveable (BVM). Rock quality was interpreted and classified based on effective porosity and permeability index ratios. The ratio where a steeper gradient was interpreted as high flow zones, a gentle gradient as low flow zones, and a flat gradient was considered as tight baffle zones. SMR logging proved to be essential for the proper reservoir characterization and to support critical decisions on well completion design. Fundamental rock quality and permeability profile were supplied by SMR. Oil saturation was identified by applying 2D-NMR methods, T1/T2 vs. T2 and Diffusion vs. T2 maps in a challenging oil-based mud environment. The Electrical Borehole imaging (EBI) was used to identify fracture types and establish fracture density. Additionally, the impact of fractures to enhance porosity and permeability was possible. The Geochemical Spectroscopy Tool (GST) for the precise determination of formation chemistry, mineralogy, and lithology, as well as the identification of total organic carbon (TOC). The integration of the EBI, GST and SMR datasets provided sweet spots identification and perforation interval selection candidates, which the producer used to bring wells onto production.
- North America > United States > Texas > Starr County (0.41)
- North America > United States > North Dakota > Mountrail County (0.41)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth (0.41)
- (3 more...)
- Geology > Sedimentary Geology (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.96)
- Geology > Mineral > Silicate > Phyllosilicate (0.77)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.56)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.94)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.94)
Abstract Monitoring of CO2 plume migration in a depleted carbonate reservoir is challenging and demand comprehensive and trailblazing monitoring technologies. 4D time-lapse seismic exhibits the migration of CO2 plume within geological storage but in the area affected by gas chimney due to poor signal-to-noise ratio (SNR), uncertainty in identifying and interpretation of CO2 plume gets exaggerated. High resolution 3D vertical seismic profile (VSP) survey using distributed acoustic sensor (DAS) technology fulfil the objective of obtaining the detailed subsurface image which include CO2 plume migration, reservoir architecture, sub-seismic faults and fracture networks as well as the caprock. Integration of quantitative geophysics and dynamic simulation with illumination modelling dignify the capabilities of 3D DAS-VSP for CO2 plume migration monitoring. The storage site has been studied in detailed and an integrated coupled dynamic simulation were performed and results were integrated with seismic forward modeling to demonstrate the CO2 plume migration with in reservoir and its impact on seismic amplitude. 3D VSP illumination modelling was carried out by integrating reservoir and overburden interpretations, acoustic logs and seismic velocity to illustrate the subsurface coverage area at top of reservoir. Several acquisition survey geometries were simulated based on different source carpet size for effective surface source contribution for subsurface illumination and results were analyzed to design the 3D VSP survey for early CO2 plume migration monitoring. The illumination simulation was integrated with dynamic simulation for fullfield CO2 plume migration monitoring with 3D DAS-VSP by incorporating Pseudo wells illumination analysis. Results of integrated coupled dynamic simulation and 4D seismic feasibility were analyzed for selection of best well location to deploy the multi fiber optic sensor system (M-FOSS) technology. Amplitude response of synthetic AVO (amplitude vs offsets) gathers at the top of carbonate reservoir were analyzed for near, mid and far angle stacks with respect to pre-production as well as pre-injection reservoir conditions. Observed promising results of distinguishable 25-30% of CO2 saturation in depleted reservoir from 4D time-lapse seismic envisage the application of 3D DAS-VSP acquisition. The source patch analysis of 3D VSP illumination modelling results indicate that a source carpet of 6km×6km would be cos-effectively sufficient to produce a maximum of approximately 2km in diameter subsurface illumination at the top of the reservoir. The Pseudo wells illumination analysis results show that current planned injection wells would probably able to monitor early CO2 injection but for the fullfield monitoring additional monitoring wells or a hybrid survey of VSP and surface seismic would be required. The integrated modeling approach ensures that 4D Seismic in subsurface CO2 plume monitoring is robust. Monitoring pressure build-ups from 3D DAS-VSP will reduce the associated risks.
- North America > United States (0.94)
- Asia > Malaysia (0.64)
- Research Report > New Finding (0.50)
- Research Report > Experimental Study (0.35)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Louisiana > Delhi Field (0.99)
Improving Long-Term Hydraulic Fracture Conductivity in Carbonate Formations by Substitution of Harder Minerals
Samarkin, Yevgeniy (King Fahd University of Petroleum & Minerals) | Aljawad, Murtada Saleh (King Fahd University of Petroleum & Minerals) | Amao, Abduljamiu Olalekan (King Fahd University of Petroleum & Minerals) | Sølling, Theis Ivan (King Fahd University of Petroleum & Minerals) | Al-Ramadan, Khalid (King Fahd University of Petroleum & Minerals) | AlTammar, Murtadha J. (Saudi Aramco) | Alruwaili, Khalid M. (Saudi Aramco)
Abstract Hydraulic fracturing is applied in tight formations to create conductive paths within the reservoir. However, the conductivity of the created fractures declines with time due to the closure stresses. The decline is sharp in soft formations because of proppant embedment and fracture surface asperities failure. The improvement in fracture surface hardness can mitigate the abovementioned challenges and sustain the fracture conductivity. This research targeted enhancing carbonate rock's hardness by forming minerals harder than calcite. Carbonate rocks, namely dolomite, limestone, and chalk, were treated at ambient temperature conditions by immersion into the aqueous solutions of NaF and ZnSO4 with a concentration of 0.1M. During treatment, the solution was sampled to monitor the changes in ion concentration and estimate the reaction kinetics by ICP - OES and IC devices. The hardness of rock samples was measured by impulse hammering technique before and after the treatment. The changes in rock's mineralogy and elemental content were studied by XRD and SEM imaging. The permeability of rocks was estimated by the steady-state gas injection method. The formation of smithsonite (ZnCO3, Mohs scale hardness - 4.5) and fluorite (CaF2, Mohs scale hardness - 4) was achieved in the reaction of calcite (CaCO3, Mohs scale hardness – 3) with ZnSO4 and NaF, respectively. Chalk and limestone reacted efficiently with both solutions; however, the dolomite reaction with solutions was feeble. XRD detected the newly formed smithsonite minerals, and it was observed in SEM images that minerals formed an interconnected net in chalk and limestone specimens. In dolomite samples, the minerals formed isolated gatherings that were sparsely located on the grains. The treatments caused the improvement of the rock specimen's hardness. 0.1M solution of NaF was not effective in strengthening the rock samples (only chalk sample experienced 6.7% improvement in hardness) because of low concentration of the solutions used; however, treatment resulted in negligible changes in permeability of the samples. In contrast, Young's modulus of limestone and chalk treated by ZnSO4 increased by 17% and 21%. Permeability of rocks treated by ZnSO4 reduced drastically, most likely due to the formation of gypsum as a byproduct of the reaction. This research presents a method for carbonate rock hardening via the transformation of parent calcite into harder minerals. It explains its possible application in the petroleum industry to sustain the conductivity of propped/acid fractures. The proposed technique will help to mitigate fracture conductivity decline due to proppant embedment and asperities failure issues that are especially severe in soft formations.
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.90)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (0.71)
Laboratory and Field Evaluation of Aqueous Retarded Acid System for Carbonate Gas Field, Offshore Borneo Island
Ravichandran, Tenamutha (PETRONAS Carigali Sdn. Bhd.) | Sidek, Sulaiman (PETRONAS Carigali Sdn. Bhd.) | Zakaria, Ahmed Nabil (PETRONAS Carigali Sdn. Bhd.) | Ahmed Shata, Karim (PETRONAS Carigali Sdn. Bhd.) | Sapiee, Zool Nasri (PETRONAS Carigali Sdn. Bhd.) | Abdul Rahman, Hazrina (PETRONAS Carigali Sdn. Bhd.) | Foo Kwang Hui, Nicholas (PETRONAS Carigali Sdn. Bhd.) | Wan Mohamad, Wan Amni (PETRONAS Carigali Sdn. Bhd.) | Yahaya, Fadzil (PETRONAS Carigali Sdn. Bhd.) | Abdul Razak, Affandi (Uzma Group Sdn. Bhd.) | Maharon, Diana (Uzma Group Sdn. Bhd.) | Jadid, Maharon (Uzma Group Sdn. Bhd.)
Abstract Objectives, Scope This paper provides valuable insights on aqueous retarded acid system evaluation based on laboratory testing, literature review and engineering analysis prior to the field application for a candidate well in a gas field, offshore East Malaysia (Figure 1). The field is a reefal carbonates build-up overlayed by a thick shale sequence and is one of the deepest fields in Sarawak Asset, in which the produced fluid contains up to 3,500ppm H2S, 20% CO2 and bottomhole temperature up to 288°F. Production enhancement for this carbonate reservoir requires application of a more effective approach to address challenges associated with acid placement and reservoir contact in long pay zones of complex diagenetic facies high temperature carbonate reservoirs, thereby improving return on investment. Figure 1: Structural map of Central Luconia carbonate platform offshore Sarawak, Malaysia (Janjuhah et al. 2016) Methods, Procedures, Process The workflow adopted for the stimulation job involves thorough historical production data analysis, detail petrophysical review to evaluate reservoir properties, in-depth production performance analysis (i.e. nodal and network modeling), completion review to ascertain damage mechanism and economic evaluation that include decision risk analysis to evaluate all range of probabilistic outcome. Initial selection of stimulation fluids was based on the mineralogical composition of the main producing formation. A detailed study of reservoir rock and its reaction to various acid systems has been based upon software modeling where sensitivity analyses involving multiple treatment schedule scenarios incorporating various acid and diverter fluid systems are considered. Coreflood experiment was then performed to determine the Pore Volume to Breakthrough (PVBT) comparing emulsified acid with aqueous retarded acid at temperature of 250°F, injection rate of 3ml/min and at confining pressure of 1,500psi. The low PVBT values (i.e. 1.125 and 0.521) and unique breakthrough features obtained from the coreflood confirmed that aqueous retarded acid is effective to stimulate the carbonate reservoir. Compatibility testing was also conducted to assess the stability of the retarded acid recipes and potential reaction with reservoir fluids (i.e. water and condensate), downhole completion and surface equipment. Results, Observation, Conclusion An established stimulation software was used to refine the acid volume calculation and placement analysis. Field trial was made using combined application of the aqueous retarded acid and viscoelastic diverting acid. Considering several case scenarios, the remedial treatment was performed via bullheading to achieve optimum injection rate within 5bpm to 7bpm. Total of 197bbls acid and 197bbls diverter was be pumped during the treatment that will be split in several stages to achieve average invasion profile of 2.8ft and -1.3 skin value. This paper presents aqueous retarded acid system as alternative to widely used emulsified acid systems. Field application of the approach supports the theoretical findings based on substantial improvement in well production, pressure matching of the remedial treatment and calibrated nodal analysis assessment. This demonstrates the value of holistic approach of laboratory testing, comprehensive software modeling and application of enhanced stimulation fluids to overcome complex technical challenges Novel, Additive Information The field production was previously constrained by its high CO2 levels and the supply gas ratio agreement. The information and lessons learnt from this paper will be applicable as evident of practical improvements to achieve sustainable production from the field since it has a strategic importance as production, processing and export hub to other four gas fields. Recent CO2 blending project has allow a better distribution of gas across the network and therefore demand higher production from the field, thus further unlock it potential to achieve economic optimization.
- Geology > Sedimentary Geology (0.54)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.34)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.34)
Analogue outcrops can be used to prepare geoscientists with realistic expectations and responses for Geosteering ultra-long horizontal wells (ERD) in thin reservoirs with different scales of faults, and uncertainty in fault zone parameters and characteristics. Geosteering ultra-long horizontal wells in specific, thin, meter-thick target zones within reservoirs is challenged when sub-seismic faults are present or where seismic scale fault throw and fault location is ill-defined or imprecisely known. This paper defines the challenge of how analogue outcrops can be used to prepare geoscientists with realistic expectations and responses to such operational difficulties in faulted carbonates, irrespective of the tools employed to characterize encountered faults. Geosteering wells in reservoirs with different scales of faults and uncertainty in fault zone character and detection limits can lead to: (i) extensive ‘out of zone’ intervals and (ii) undulating wellbores (when attempting to retrieve target layer positioning), whereby well productivity and accessibility are compromised. Using faulted carbonate field analogues can direct the operation geologist's geosteering response to such faulted scenarios. Descriptions from outcrops are used to address subsurface scenarios of marker horizon(s) and their lateral/spatial variability; diagenesis related to faults at outcrop and expected variations along wellbore laterals in the oilfield. Additionally, offsets/throws, damage zone geometries for thin-bed reservoir understanding of fault zone effects in low-offset structures. Appreciation of faults in outcrops allows an understanding of expectations whilst drilling according to the following: (1) Scales of features from seismic to sub-seismic damage zones: what to expect when geosteering within / out of zone, across faults with indeterminate throws. (2) Understandings from 3D analogues/geometries applied predictively to field development, targeting specific thin reservoir zones / key marker beds. Several oil- well case-examples highlight the response in steering wellbores located within specific thin target zones whereby faults were expected, but where fault throw differed significantly to what was anticipated from initial seismic interpretation. Examples elucidating the application include a meter-thick dolomite zone within a very thick limestone reservoir where injector and producer wells are completed, where the wellbore remains within reservoir but out of specific target zone (how to marry smooth wellbore with layer conformance). Furthermore, for very thin reservoirs primarily located within non-reservoir carbonates, minor faults would misdirect wellbore into argillaceous limestone above or below the reservoirs. Faulted zones with water influx mapped from LWD where modelled property responses can be better characterized by low-offset faults with compartmentalizing effects for completion strategies. Even with an extensive suite of logs to characterize fault zones, the objective of Geosteering a well continuously within zone becomes difficult. Selected key tools are required for success. Directly using Early Cretaceous reservoir analogues, with specific fault types and displacements, critically aid geosteering practices for QA, prediction and learnings.
- Europe (0.67)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.17)
- Geology > Structural Geology > Fault (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.45)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.34)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (0.34)
Abstract Simulation Engineers and Geomodelers rely on reservoir rock geological descriptions to help identify baffles, barriers and pathways to fluid flow critical to accurate reservoir performance predictions. Part of the reservoir modelling process involves Petrographers laboriously describing rock thin sections to interpret the depositional environment and diagenetic processes controlling rock quality, which along with pressure differences, controls fluid movement and influences ultimate oil recovery. Supervised Machine Learning and a rock fabric labelled data set was used to train a neural net to recognize Modified Durham classification reservoir rock thin section images and their individual components (fossils and pore types) plus predict rock quality. The image recognition program's accuracy was tested on an unseen thin section image database.
- Europe (1.00)
- Asia > Middle East > UAE (0.50)
- North America > United States (0.46)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Sedimentary Geology > Depositional Environment (0.89)
- Information Technology > Sensing and Signal Processing > Image Processing (1.00)
- Information Technology > Artificial Intelligence > Machine Learning > Statistical Learning (1.00)
- Information Technology > Artificial Intelligence > Machine Learning > Pattern Recognition > Image Matching (0.61)
- Information Technology > Artificial Intelligence > Machine Learning > Neural Networks > Deep Learning (0.47)
Polymer Injection to Unlock Bypassed Oil in a Giant Carbonate Reservoir: Bridging the Gap Between Laboratory and Large Scale Polymer Project
Fabbri, Clement (ADNOC Onshore) | Al Saadi, Haitham Ali (ADNOC Onshore) | Wang, Ke (ADNOC Onshore) | Maire, Flavien (ADNOC Onshore) | Romero, Carolina (ADNOC Onshore) | Cordelier, Philippe (TotalEnergies) | Prinet, Catherine (TotalEnergies) | Jouenne, Stephane (TotalEnergies) | Garnier, Olivier (TotalEnergies) | Xu, Siqing (ADNOC) | Leon, Juan Manuel (ADNOC) | Baslaib, Mohammed (ADNOC) | Masalmeh, Shehadeh (ADNOC)
Abstract Polymer flooding has long been proposed to improve sweep efficiency in heterogeneous reservoirs where polymer enhances cross flow between layers and forces water into the low permeability layers, leading to more homogeneous saturation profile. Although this approach could unlock large volumes of by-passed oil in layered carbonate reservoirs, compatibility of polymer solutions with high salinity - high temperature carbonate reservoirs has been hindering polymer injection projects in such harsh conditions. The aim of this paper is to present the laboratory work, polymer injection field test results and pilot design aimed to unlock target tertiary oil recovery in a highly heterogeneous mixed to oil-wet giant carbonate reservoir. This paper focuses on a highly layered limestone reservoir with various levels of cyclicity in properties. This reservoir may be divided in two main bodies, i.e., an Upper zone and a Lower zone with permeability contrast of up to two orders of magnitude. The main part of the reservoir is currently under peripheral and mid-flank water injection. Field observations show that injected water tends to channel quickly through the Upper zone along the high permeability layers and bypass the oil in the Lower zone. Past studies have indicated that this water override phenomenon is caused by a combination of high permeability contrast and capillary forces which counteract gravity forces. In this setting, adequate polymer injection strategy to enhance cross-flow between these zones is investigated, building on laboratory and polymer injection test field results. A key prerequisite for defining such EOR development scenario is to have representative static and dynamic models that captures the geological heterogeneity of this kind of reservoirs. This is achieved by an improved and integrated reservoir characterization, modelling and water injection history matching procedure. The history matched model was used to investigate different polymer injection schemes and resulted in an optimum pilot design. The injection scheme is defined based on dynamic simulations to maximize value, building on results from single-well polymer injection test, laboratory work and on previous published work, which have demonstrated the potential of polymer flooding for this reservoir. Our study evidences the positive impact of polymer propagation at field scale, improving the water-front stability, which is a function of pressure gradient near producer wells. Sensitivities to the position and number of polymer injectors have been performed to identify the best injection configuration, depending on the existing water injection scheme and the operating constraints. The pilot design proposed builds on laboratory work and field monitoring data gathered during single-well polymer injection field test. Together, these elements represent building blocks to enable tertiary polymer recovery in giant heterogeneous carbonate reservoirs with high temperature - high salinity conditions.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.76)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Directional Radial Drilling Increases Reservoir Coverage with Precise Wellbore Placement Resulting in a Significant Production Increase from a Thin Reservoir
Bashirov, Ayrat (LLC Perfobore) | Galas, Ilya (LLC Perfobore) | Nazyrov, Marat (LLC Perfobore) | Kuznetsov, Dmitry (LLC LUKOIL-Komi) | Akkuzhin, Azamat (LLC LUKOIL-Komi)
Abstract In many oil and gas provinces not only in Russia, but throughout the world, carbonate strata make up a significant portion of the sedimentary cover, and large accumulations of hydrocarbons are associated with them. However, the purposeful study of them as reservoirs for hydrocarbons in our country practically began only in the post-war years. In the special petrography laboratory carbonate rocks composing various stratigraphic complexes of almost all oil and gas provinces of the Soviet Union were studied, and in particular, Paleozoic carbonate strata of the Timan-Pechora province, Ural-Volga region, Belarus, Kazakhstan, ancient Riphean-Cambrian formations of Yakutia and relatively young strata of the Late Cretaceous of the northeastern Ciscaucasia. Carbonates are widespread sedimentary rocks. A very significant part of them was formed in the conditions of vast shallow-water marine epicontinental basins. A large number of works are devoted to the study of such deposits. However, issues related to the conditions of formation of carbonate sediments and their postsedimentary changes cannot be considered resolved, as well as the classification of the rocks themselves. The analyzed field is the Osvanyurskoye one. It was discovered in 2007. The field is located in the north-east of the European part of the Russian Federation, 2 km from Usinsk in the Komi Republic. The field is a part of the Timano-Pechora oil and gas province and it is a mature field (fig. 1). The objective was a 2.5m thick layer of the Serpukhov horizon.
- Europe > Russia > Northwestern Federal District > Nenets Autonomous Okrug (0.34)
- Europe > Russia > Northwestern Federal District > Komi Republic (0.34)
- Europe > Russia > Central Federal District > Komi Republic (0.25)
- Asia > Russia > Far Eastern Federal District > Sakha Republic (0.25)
- Phanerozoic > Paleozoic (0.69)
- Phanerozoic > Mesozoic > Cretaceous > Upper Cretaceous (0.45)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.90)