Day 1 Sun, February 19, 2023最新文献

{"title":"Implementing a Novel Organic Acid Matrix Stimulation to Successfully Remove Formation Damage: Case Studies, Iraq and Ecuador Oilfields","authors":"J. Alvarez, X. Alarcon, Jonnathan Tellez","doi":"10.2118/213428-ms","DOIUrl":"https://doi.org/10.2118/213428-ms","url":null,"abstract":"\u0000 This paper discusses the efficiency of design, application, and pumping schedule of organic acid treatments used for mature fields in Iraq. Due to challenging completion schematics, an enhanced fluid placement method consisting of coiled tubing (CT), nitrogen, and a fluidic oscillator tool (or combination) is presented.\u0000 By the time a well completion is achieved, oil production for most wells begins to decrease because of formation damage caused by fines migration, clay swelling, scale deposition, emulsions, organic deposits, or previous unsuccessful hydrochloric acid (HCl) or HCl/hydrofluoric acid (HF) stimulation treatments. A matrix stimulation/acidization using a tool that enables pumping the treatment, either as near as possible to or reciprocating across the perforations, is necessary to help remove formation damage, enhance recovery, and increase oil production (producer wells) or water injection (injector wells).\u0000 Matrix stimulation treatments were performed for both producer and injector wells for an Iraq field, demonstrating enhanced conductivity results and increasing oil production up to 2000 BOPD over the last production rate or improving the water injectivity rate by 10000 BWPD. In addition, for those wells in which an electrical submersible pump (ESP) was installed, it was necessary that the selected stimulation fluids did not adversely affect the internal components of the ESP. To reach this goal, analysis of the following parameters was performed: mineralogy, regain permeability test, temperature, fluids properties, rock properties, and formation damage. Based on the analysis, customized designs assisted by software simulations were developed to determine the most effective treatment selection.\u0000 Novel/Additive Information (25-75 words suggested)\u0000 This paper describes how well information and correct analysis, and design can help to develop a customized optimal intervention strategy, identify the best solution to remove the formation damage, and deliver value added to the operators.","PeriodicalId":396949,"journal":{"name":"Day 1 Sun, February 19, 2023","volume":"2 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121450444","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Successful Managed Pressure Drilling Application in a Challenging Well With Crossflow in Unconventional Field","authors":"Hua Zhang, J. Muhammad, Naif Mutlaq Alhajri","doi":"10.2118/213441-ms","DOIUrl":"https://doi.org/10.2118/213441-ms","url":null,"abstract":"\u0000 Unconventional tight gas well encountered unexpected losses at target depth and simultaneously well control took place from water source in upper zone. Bleed off tests concluded it was kick rather than ballooning. Combining upper flow and lower loss zones resulted in downhole crossflow and near zero mud window providing high operational risks to drill next 5-7/8 inch horizontal section. Managed Pressure Drilling (MPD) was utilized to drill horizontal section, mitigate well control risk and reach reservoir target.\u0000 Prior to MPD selection, several attempts could not heal losses. The contigent 7 inch drilling liner was installed however it could not isolate the flow zone. MPD maintains constant bottom-hole pressure and enables full circulation. Under near zero mud weight (MW) window condition using same method of maintaining flow out equal to flow in would create high risk of well control as there is high possibility of influx moving up and diluting drilling fluid. It was necessary to maintain constant bottom-hole pressure during drilling and tripping by forcing influx to move down to lower fracture zone with acceptable rate of losses.\u0000 During well construction with a fully automated MPD system, as a starting point MPD static pore pressure test (PPT) precisely detected pore pressure of water flow zone, establishing the low limit of the drilling window. During successful drilling of 3,027 feet in horizontal section, the influx was forced to move down to the lower loss zone with 5 to 20 barrels per hour dynamic losses. Real-time instantaneous annular pressure adjustment with MPD system minimized losses and managed well without interrupting drilling process even under condition of losses change to gain varying by only 25 psi surface back pressure (SBP). Benefits of multi stage displacement, detection and mitigation the swab and surge by stripping in and out also proved that MPD system made the process safer. Furthermore, in such well having no mud window, early detection of gain or losses tendency was imperative, so that the remedy actions could be applied immediately before things worsened with time. MPD system had the capability to detect gain/loss relatively early than the rig pit-volume system. Moreover, the target bottomhole pressure was adjusted almost instantly by adjusting the SBP by MPD system. The well would be considered un-drillable without MPD.\u0000 MPD added safety factor during releasing stuck pipe operations where the low weight spotting fluids utilized. A fully automated MPD system provided a solution for specific risk condition such as near zero MW window and crossflow while drilling unconventional tight gas horizontal well. The precise and instant control of bottom hole pressure was the key factor of overall success.\u0000 This paper summarizes the implementation of the fully automated MPD system as a sophisticated tool to precisely control such situations instantly, saving time, associated mud costs and hence optimize the overall drilling ","PeriodicalId":396949,"journal":{"name":"Day 1 Sun, February 19, 2023","volume":"86 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116239205","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Enhanced Fluid Characterization for Improved Saturation & Connectivity","authors":"T. Mattar, Abdulelah Bingaith, S. Ghadiry, R. Ahmed","doi":"10.2118/213294-ms","DOIUrl":"https://doi.org/10.2118/213294-ms","url":null,"abstract":"\u0000 New methods used to accurately determine water and hydrocarbon saturation profile, hydrocarbon typing & reservoir extent (connectivity) in real time by using acquired insitu water salinity measurement downhole and measured hydrocarbon optical density from formation testers.\u0000 The uncertainties present from water salinity (Rw) values from nearby wells (due to vertical & aerial variations) may compute inaccurate hydrocarbon saturations when input in Archie's based fluid saturation model, which affects the hydrocarbon in place calculations. Also, relying only on pressure measurement for connectivity assessment & reservoir extent using Vertical Interference Testing (VIT) may sometimes be misleading & inconclusive due to supercharging in low permeability & low pressure contrast in high permeability which affects the field development plans. Therefore, the new methodology is introduced to overcome these challenges.\u0000 Firstly, the downhole water salinity is measured in a water zone at the bottom of the reservoir while pumping out using formation tester after achieving clean-out (negligible contamination). The values were input into the initial petrophysical model to recompute the new fluid saturation which was confirmed by pump-out fluid fractions from other zones.\u0000 Secondly, the optical density measurement from the spectroscopy was used to confirm the vertical connectivity though Reservoir Fluid Geodynamics & indicating a compositional gradient in real time in an oil column. This was done by constructing Flory-Huggins-Zuo (FHZ) Equation of State model and identifying asphaltene molecular size from optical density gradient.\u0000 These two methods will bring accurate & reliable results compared to conventional methods which has some uncertainties impacting evaluation & reservoir understanding. Secondly, will help in optimizing sampling & downhole fluid analysis programs which eventually saves cost & time & CO2 emissions. Thirdly, Optical Density gradient analysis can be also used for flow assurance prediction.","PeriodicalId":396949,"journal":{"name":"Day 1 Sun, February 19, 2023","volume":"27 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115393414","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Managing Adequate Gas EOR for Unstable Asphaltene Stability Field?Asphaltene Flow Assurance Pre-Risk Assessment Case Study for CO2, Enriched Gas, and Lean Gas Options","authors":"M. Tange, T. Hiraiwa, Khuloud Tareq Khlaifi, R. Sakurai, S. Bahri, A. Abed, H. Uematsu, K. Makishima, Y. Inokuma, M. Sawata, S. H. Alkaabi, H. Yonebayashi","doi":"10.2118/213443-ms","DOIUrl":"https://doi.org/10.2118/213443-ms","url":null,"abstract":"\u0000 To enhance oil production (EOR) in tight carbonate oil reservoirs, gas EOR can be a promising option from injectivity viewpoints compared with water-basis chemical EOR. CO2 is the most attractive injectant with higher recovery factor expectation while responding to the recent decarbonization demands; however, CO2 is also known to accelerate asphaltene flow assurance risks. In actual fact, the previous work revealed a high asphaltene flow assurance potential risk for CO2 injection. Therefore, a further pre-risk evaluation case study was conducted to extract adequate type of potential injection gas among CO2, enriched gas, and lean gas.\u0000 This study focused on subsurface gas-induced asphaltene risks in an offshore heterogeneous oil field showing unstable asphaltene colloidal instability index (CII=2.2), where a crestal lean gas injection has been applied without any asphaltene issues. A single phase bottomhole sample was taken from appropriate candidate well keeping representative reservoir fluid in a clear asphaltene-gradient field: i.e., lesser asphaltenes in shallow depth but more in deeper section.\u0000 As a result of this study, no asphaltene onset was detected from original reservoir fluid while asphaltene onset pressures (AOPs) were detected from mixture of reservoir fluid and CO2 or enriched gas or lean gas at two temperatures representing reservoir and wellhead conditions. Experimental gas mixing ratios were carefully designed to distribute the AOPs broadly in operating pressure range: from in-situ reservoir and near wellbore to bottomhole, for securing higher numerical model accuracy by avoiding data extrapolation. A numerical model, calibrated with experimental outputs, predicted risk magnitude by reservoir depth. A comparative analysis revealed higher asphaltene precipitation risks in CO2 injectant than enriched gas and lean gas. Finally, asphaltene particle/aggregate size were discussed for formation damage risks. The visually measured asphaltene solid particle size varied from 1-10 μm for CO2 injection and 1-4 μm for enriched gas injection while no visible for lean gas. From the past injection water quality analysis, the reservoir has threshold particle size between 0.5-1.0 μm to cause plugging. Therefore, it was concluded that risk of asphaltene-induced formation damage is lower in enriched gas injection compared with CO2 injection. In general, higher oil recovery is expected by order of CO2, enriched, and lean gases.\u0000 In conclusion, even CO2 EOR is being attractive rapidly from decarbonization viewpoints, the study highlights an importance of balancing business case opportunity and risk from the aspect of injection gas-induced asphaltene flow assurance potential risks.","PeriodicalId":396949,"journal":{"name":"Day 1 Sun, February 19, 2023","volume":"85 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123545340","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Toward Combining Multi Seismic Attributes, A Novel Machine Learning Approach","authors":"Mustafa Alshuala","doi":"10.2118/213320-ms","DOIUrl":"https://doi.org/10.2118/213320-ms","url":null,"abstract":"\u0000 The objective of this study is to develop and examine a machine learning model that combines multiple seismic attributes in a way that preserves all the features of the combined attributes with, hopefully, better resolution and efficiency than the conventional seismic attributes integration method. We used the Auto- Encoder algorithm, which is a neural network method. It consists of two identical networks known as encoder and decoder. Auto-Encoder was initially developed to compress data in the encoder part, and then the same structure is used to decompress data in the decoder part. Our interest is in the output of the encoder which is the reduced version of the input.\u0000 For fault and fracture detection, we examined and compared the results of Octree as a conventional multi- seismic quantization method and Auto-Encoder as a new machine learning technique. The study used five 3D volumes, one for each of the five attributes Raw Data, Skeleton, Detect, Negative Curvature 1 and Negative Curvature 3. Each 3D volume is divided into 100 slices. One slice per attribute (i.e. a set of five slices) comprise an input dataset to the encoder. The process is iterated 100 times to obtain 100 slices of encoded attributes.\u0000 The result of the Auto-Encoder solution is compared with that of Octree. The Auto-Encoder accurately preserved the three faults from the input attribute images whereas Octree preserved only one fault. Additionally, the details of the fractures in the Curvature attributes are also preserved with more clarity in the Auto-Encoder solution than Octree. The machine learning technique (Auto-Encoder) preserves all the features (i.e. faults and fractures) from the combined attributes and shows better resolution than Octree. It can also combine unlimited number of attributes whereas Octree is limited to eight attributes only.","PeriodicalId":396949,"journal":{"name":"Day 1 Sun, February 19, 2023","volume":"6 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123963087","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Data-Driven Well Candidate Recognition Solution. Case Study in a Digital Oil Field in Abu Dhabi","authors":"Erismar Rubio, N. Reddicharla, Mayada Ali Sultan Ali, Mohamed Ali Attar","doi":"10.2118/213329-ms","DOIUrl":"https://doi.org/10.2118/213329-ms","url":null,"abstract":"\u0000 Well Candidate Recognition (WCR) data analytics solution was developed to expedite the process of identifying unhealthy wells that may require rig/rigless interventions based on data integration, automation, and advanced data-driven models. The solution expedites well performance review process to pinpoint candidates for stimulation, N2 lift, Gas lift conversion, Water/Gas shutoff, etc. It provides a flexible visualization platform to highlight hidden well performance insight, prioritizing well intervention activities.\u0000 Before the solution was in place, a time-consuming well performance review's process was performed well by well bases. All petroleum engineers were involved in the process that takes months to compile a solid list of opportunities for production enhancement. In addition, each engineer utilized their own process to assess well performance using partially company best recommended practices. It was notice that most expensive field activities were the ones with lowest success performance indicators, pushing the asset to review, standardize and automate the process of well intervention candidate's selection. The solution enforced best reservoir management practices for reservoir/well surveillance and optimization, identifying opportunities to align reservoir management goals with short term production optimization and sustainable reservoir development, adopting new data driven technologies for improving reservoir recovery/management for cost rationalization.\u0000 The implementation of this solution permitted to identify 20 hidden opportunities for production improvement to support production target achievement with an actual gain of 20MBOPD. On the other hand, all well interventions were successful executed with and avg. success factor of 103%, exceeding in most cases the expected gain, compared with previous years avg. success factor of 32%. The substantial increment in the success factor of the most expensive field activities had a favorable impact over asset UTC.\u0000 WCR's Dashboards leveraged legacy data, models and smart field capabilities, using advance visualization feature to identifying unhealthy wells, that may require rig/rigless intervention based on best reservoir management practices, providing an efficient/automated well performance review saving 70% of the petroleum engineer's time. Opportunities are assessed and ranked based on expected gain via intelligent action tracking system to ensure action completion and production contribution, perusing higher recovery while delivering consistent results. It also offers: GIS Map capability to identify localized poor properties or issues; pressure data and automated well model update to identify high drawdown (Skin), reservoir pressure decline and actual well capacity with automated peer comparison to support production optimization workflow; ability for quick Identification of erroneous data loaded in official data sources; well intervention dashboard to assess success of actual/pre","PeriodicalId":396949,"journal":{"name":"Day 1 Sun, February 19, 2023","volume":"28 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114682772","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Well Design Re-Engineering: First Level of Emission Footprint Optimization","authors":"Aleksandr Nifantov, A. Ruzhnikov","doi":"10.2118/213365-ms","DOIUrl":"https://doi.org/10.2118/213365-ms","url":null,"abstract":"\u0000 Well construction is one of the greenhouse gas (GHG) emissions contributors in the oil and gas industry. Today, the main attention is paid to technology solutions, minimizing drilling time and rig upgrading with low-energy equipment. However, what about optimum well design itself, which may lead to acceptable operational risks, reasonable budget, lower power demand and consequently lower emissions to deliver it? The work presented in this paper is about the planning process to reach not just a technical and financial balance in the construction of a well, but also incorporate sustainability elements into the design process itself.\u0000 The conventional engineering approach to designing a well, namely being able to meet its technical targets within reasonable budget, was upgraded with an additional workflow to consider the GHG emission footprint of well construction process. Specifically, it was incorporated in a digital solution which enables a comparison between different well program scenarios, from which an optimal design can be chosen. The process includes the following step: 1) creation of a well design meeting its technical targets; 2) estimation of the well budget; 3) modeling the well construction GHG emissions for the different designs. Some iterations of this process are needed to reach sustainable well design (relatively optimal case).\u0000 The real extended reach drilling (ERD) well proposal was used as the example for this study. The 3D geomechanical model was created prior to start the well engineering. It simulated distribution of stresses which enabled calculation of the safe pressure window while drilling, tripping, running casing and cementing. Considering this model, the originally proposed casing design was upscaled to achieve the ECD (Equivalent Circulating Density) in the required range without collapsing and breaking down the wellbore wall. Additionally, the trajectory was optimized to improve hole cleaning and facilitate the running of casing in highly deviated sections of the well. All these measures theoretically minimized the risk of not hitting the planned targets. Then, the well profile was tuned to improve the financial impact and operational emission footprint without compromising technical solution. As a result, it had led to potential lowering of the well construction budget by ~2 % and reduction of the emission by 6.3 % (for the sum of Scope 1 and 3 emissions).\u0000 The main idea of this approach is to achieve a low-energy, cost-effective and technically feasible well design as a baseline. Within the constraints of this design, it will then leverage specific technology solutions to further minimize energy consumption and GHG emissions.\u0000 This manuscript presents a new methodology for the engineering design process for oil and gas wells, which quantitively incorporates sustainability. The ideas, which are expressed in the manuscript, can be implemented in any drilling project worldwide.","PeriodicalId":396949,"journal":{"name":"Day 1 Sun, February 19, 2023","volume":"35 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127935288","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Application of Image Processing Techniques in Deep-Learning Workflow to Predict CO2 Storage in Highly Heterogeneous Naturally Fractured Reservoirs: A Discrete Fracture Network Approach","authors":"Zeeshan Tariq, B. Yan, Shuyu Sun","doi":"10.2118/213359-ms","DOIUrl":"https://doi.org/10.2118/213359-ms","url":null,"abstract":"\u0000 Naturally fractured reservoirs (NFRs), such as fractured carbonate reservoirs, are commonly located worldwide and have the potential to be good sources of long-term storage of carbon dioxide (CO2). The numerical reservoir simulation models are an excellent source for evaluating the likelihood and comprehending the physics underlying behind the interaction of CO2 and brine in subsurface formations. For various reasons, including the rock's highly fractured and heterogeneous nature, the rapid spread of the CO2 plume in the fractured network, and the high capillary contrast between matrix and fractures, simulating fluid flow behavior in NFR reservoirs during CO2 injection is computationally expensive and cumbersome. This paper presents a deep-learning approach to capture the spatial and temporal dynamics of CO2 saturation plumes during the injection and monitoring periods of Geological Carbon Sequestration (GCS) sequestration in NFRs. To achieve our purpose, we have first built a base case physics-based numerical simulation model to simulate the process of CO2 injection in naturally fractured deep saline aquifers. A standalone package was coded to couple the discrete fracture network in a fully compositional numerical simulation model. Then the base case reservoir model was sampled using the Latin-Hypercube approach to account for a wide range of petrophysical, geological, reservoir, and decision parameters. These samples generated a massive physics-informed database of around 900 cases that provides a sufficient training dataset for the DL model. The performance of the DL model was improved by applying multiple filters, including the Median, Sato, Hessian, Sobel, and Meijering filters. The average absolute percentage error (AAPE), root mean square error (RMSE), Structural similarity index metric (SSIM), peak signal-to-noise ratio (PSNR), and coefficient of determination (R2) were used as error metrics to examine the performance of the surrogate DL models. The developed workflow showed superior performance by giving AAPE less than 5% and R2 more than 0.94 between ground truth and predicted values. The proposed DL-based surrogate model can be used as a quick assessment tool to evaluate the long-term feasibility of CO2 movement in a fracture carbonate medium.","PeriodicalId":396949,"journal":{"name":"Day 1 Sun, February 19, 2023","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127976641","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Comprehensive Study on Ultra-Heavy Oil Deposition in North Kuwait and Successful Fluid Sampling for Field Development Studies: Case Study","authors":"Baroon Bodoor, David Nelson Jesudian, B. Al-Otaibi, H. Ibrahim, C. Chao, Viet Le, Ahmed Ghruda, _. Sofiance","doi":"10.2118/213242-ms","DOIUrl":"https://doi.org/10.2118/213242-ms","url":null,"abstract":"\u0000 The Burgan reservoir is located in North Kuwait was discovered in 1957. First commercial oil production from this multistack sandstone reservoir started back in 1964. Operating under active bottom water drive as well as edge water drive. The primary reservoir in the field is Burgan of Lower Cretaceous age, which contributes the major oil production of the fields.\u0000 Burgan reservoir is the second largest reservoir in terms of STOOIP and reserves, producing 30% of daily oil production. Significant amount of historical production came from the lower part of the reservoir where the pattern of water influx is well understood. Most of the historical production and the majority of remaining reserves are in the upper part of the reservoir where the pressure support and water influx are relatively well understood.\u0000 Presence of tar was initially detected from cores and produced oil in some of the wells and visual inspection of core material. Tar zone in the Burgan was considered to be structurally controlled and occurred in specific depth window around oil-water contact. Heavy oil has been discovered in basal parts of Burgan sandstone in some of the zones within North Kuwait. Development of Burgan in north Kuwait began in the 1950s with oil recovery since then from Burgan channel sands with few exceptions in the North Kuwait as samples confirmed ultra-heavy oil.","PeriodicalId":396949,"journal":{"name":"Day 1 Sun, February 19, 2023","volume":"40 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130781291","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A Two-Phase Transfer Function for Simulation of Fractured Ultratight Gas-Condensate Reservoirs","authors":"M. Raslan, Anuj Gupta, H. Ates, K. Jessen","doi":"10.2118/213205-ms","DOIUrl":"https://doi.org/10.2118/213205-ms","url":null,"abstract":"\u0000 In modeling of fractured ultratight gas-condensate reservoirs it is particularly important to represent liquid dropout, and its impact on fluid flow behavior, accurately. This, in turn, allows for design and optimization of reservoir production strategies, to mitigate potential production loss below the dewpoint pressure. Unfortunately, the traditional transfer functions used to describe the mass transfer between matrix/fracture segments in dual-porosity models (DPM’s) do not explicitly represent the complex physics of the inherent multiphase problem, which may complicate the application of existing simulators. Therefore, the objective of this work is to develop a two-phase transfer function that improves the modeling of gas-condensate systems via a DP representation.\u0000 Commercial simulators typically offer a simple matrix/fracture mass transfer model to perform calculations in DP systems: The default shape factors are based on a pseudo-steady state (PSS) approximation, and for multiphase problems, the transfer function of Kazemi et al. (1976) is commonly used. Without sub-gridding, the traditional transfer functions cannot represent the extended transient behavior observed in ultratight fractured reservoirs. Furthermore, in compositional modeling of gas-condensate reservoirs, the averaging of matrix block properties masks the compositional changes near the matrix/fracture interface, that is critical to prediction of production behavior below the dewpoint.\u0000 To overcome the limitations of the current models, we introduce a new transfer function that includes 1) a time-dependent shape factor and 2) a modified representation of the two-phase flow. We utilize the correction factor introduced by Zhang et al. (2022) allowing the shape factors to vary with time. For two-phase problems, instead of evaluating the mass transfer at an average pressure and composition, we propose a novel approach that evaluates the transfer function at conditions that reflect/approximate the pressure and composition/saturation gradients within the matrix block. By approximating the fluid state near the matrix/fracture interface, we represent the liquid buildup that dictates the fluid mobility more accurately.\u0000 The open-source MATLAB Reservoir Simulation Toolbox (MRST) was used as a platform for the work presented in this paper: The existing single-porosity (SP) compositional model of MRST was first extended and validated (with the analytical solution for the single-phase pressure diffusion equation) to allow for DP modeling and simulation of condensate systems.\u0000 We present calculation results for a single-block DPM, representative of a fractured ultratight gas-condensate reservoir, to demonstrate the limitations of the traditional mass transfer modeling approach. We then introduce the new transfer function and compare all calculation results with fine-grid SP reference models. In this work, we consider two condensate fluid descriptions: 1) a 4-component analog rich gas, and","PeriodicalId":396949,"journal":{"name":"Day 1 Sun, February 19, 2023","volume":"7 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129651124","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}