Jing Wang, Tuozheng Zhang, Huiqing Liu, Xiaohu Dong, Xiaobo Li, Yang Min, Hongguang Liu, Gaixing Hu, K. Sepehrnoori
Fractured-vuggy reservoir is significantly different from porous reservoirs. Ordovician reservoir in T Oilfield in China is the largest FVCR around the world. Water flooding has been applied as a prospective method in more than 140 units, but water channeling is especially serious and the recovery is only about 15%. In such reservoir, cavities and fractures are the main storage spaces and flow channels, respectively. Because the fractures and cavities are spatially non-stratified and discretized, the waterflood pattern differs significantly from that in sandstone or porous carbonate reservoirs. It is very essential to construct a spatial well pattern to match the distribution and connectivity of fractures and cavities, which is a very popular topic in recent years. In this work, we presented a multistage construction method of spatial well pattern combining reservoir engineering with numerical simulation methods. Firstly, the economic concepts of Lorenz curve and Gini coefficient were introduced to choose the injector from all wells to achieve equilibrium displacement of injected water in the plane. Secondly, displacement and drainage equilibrium index (DDEI) was presented to determine the vertical location of the injector to achieve equilibrium displacement and drainage in vertical direction. Thirdly, the vertical locations of the producers were determined based on the distribution of reserves in vertical direction. Fourthly, the local producers were further optimized based on the cavities along the wellbore by numerical simulation. Finally, this method was successfully used to construct the spatial well patterns of fractured-vuggy units with different karst features in A unit of T Oilfield. The results show that the oil recovery factor is inversely proportional to the Gini coefficient calculated with the combined variable of flow resistance and crude reserve rather than that calculated with flow resistance in pore reservoirs. The ratio of the reserve to formation factor, V/(kh), can be used to determine the vertical location of the injector. And the optimal DDEI which is the ratio of V/(kh) in upper reservoir of the wellbore to that in lower reservoir of the wellbore is equal to 1. The vertical locations of producers are related to the vertical distributions of reserve and cavities in different karst units. At last, the principles of constructing spatial well pattern in fractured-vuggy carbonate reservoirs were proposed. This work provides an innovative and effective method to establish a spatial well pattern for FVCRs, which will break new ground for efficient development of FVCRs by water flooding.
{"title":"A Novel Method of Constructing Spatial Well Pattern for Water Flooding in Fractured-Vuggy Carbonate Reservoirs FVCRs","authors":"Jing Wang, Tuozheng Zhang, Huiqing Liu, Xiaohu Dong, Xiaobo Li, Yang Min, Hongguang Liu, Gaixing Hu, K. Sepehrnoori","doi":"10.2118/206017-ms","DOIUrl":"https://doi.org/10.2118/206017-ms","url":null,"abstract":"\u0000 Fractured-vuggy reservoir is significantly different from porous reservoirs. Ordovician reservoir in T Oilfield in China is the largest FVCR around the world. Water flooding has been applied as a prospective method in more than 140 units, but water channeling is especially serious and the recovery is only about 15%. In such reservoir, cavities and fractures are the main storage spaces and flow channels, respectively. Because the fractures and cavities are spatially non-stratified and discretized, the waterflood pattern differs significantly from that in sandstone or porous carbonate reservoirs. It is very essential to construct a spatial well pattern to match the distribution and connectivity of fractures and cavities, which is a very popular topic in recent years.\u0000 In this work, we presented a multistage construction method of spatial well pattern combining reservoir engineering with numerical simulation methods. Firstly, the economic concepts of Lorenz curve and Gini coefficient were introduced to choose the injector from all wells to achieve equilibrium displacement of injected water in the plane. Secondly, displacement and drainage equilibrium index (DDEI) was presented to determine the vertical location of the injector to achieve equilibrium displacement and drainage in vertical direction. Thirdly, the vertical locations of the producers were determined based on the distribution of reserves in vertical direction. Fourthly, the local producers were further optimized based on the cavities along the wellbore by numerical simulation. Finally, this method was successfully used to construct the spatial well patterns of fractured-vuggy units with different karst features in A unit of T Oilfield.\u0000 The results show that the oil recovery factor is inversely proportional to the Gini coefficient calculated with the combined variable of flow resistance and crude reserve rather than that calculated with flow resistance in pore reservoirs. The ratio of the reserve to formation factor, V/(kh), can be used to determine the vertical location of the injector. And the optimal DDEI which is the ratio of V/(kh) in upper reservoir of the wellbore to that in lower reservoir of the wellbore is equal to 1. The vertical locations of producers are related to the vertical distributions of reserve and cavities in different karst units. At last, the principles of constructing spatial well pattern in fractured-vuggy carbonate reservoirs were proposed.\u0000 This work provides an innovative and effective method to establish a spatial well pattern for FVCRs, which will break new ground for efficient development of FVCRs by water flooding.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"19 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77173576","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}
The complexity, high cost, and potential environmental concerns of chemical enhanced oil recovery (EOR) methods have diminished their field applications considerably. However, considering the significant incremental oil recoveries that can be obtained from these methods encourage researchers to explore ways to reduce both complexity, cost, and environmental concerns of such systems. This is especially important in carbonate formations, where after waterflooding, much of the oil remains trapped in complex reservoir pores—especially if the reservoir contains an interconnected fracture network of flow channels within the bulk rock matrix. In this paper, we present an experimental assessment of several simple chemical EOR waterflooding systems comprising of small concentrations of a low cost, low molecular weight ketone and a non-ionic surfactant in association with low-salinity brine. The experiments were conducted in carbonate cores from a Permian Basin San Andres Formation. Four different oil displacement scenarios were investigated using San Andres carbonate cores from the Central Vacuum Field in New Mexico. This included 1) low-salinity brine, 2) low-salinity brine with a surfactant, 3) low-salinity brine with a ketone, and 4) low-salinity brine with a combined ketone-surfactant system. Static imbibition experiments were conducted using a spontaneous imbibition apparatus in addition to the use of a high-speed centrifuge to saturate the cores to irreducible brine saturation. Adding a 1% concentration of 3-pentanone and a 1% non-ionic surfactant to a low-salinity brine yielded oil recoveries of 44% from the 3-pentanone system, compared to 11.4% from low-salinity brine only. The oil recovery is enhanced by a single mechanism or synergy of several mechanisms that includes interfacial tension (IFT) reduction by surfactant, capillary imbibition, favorable wettability alteration by ketone, and osmotic low-salinity brine imbibition. The IFT decreased to 1.79 mN/m upon addition of non-ionic surfactant to low-salinity brine, and it reduced to 2.96 mN/m in a mixture of 3-pentanone and non-ionic surfactant in low-salinity brine. Furthermore, ketone improved the core wettability by reducing the contact angle to 43.9° from 50.7° in the low-salinity brine experiment. In addition, the low-salinity brine systems caused mineral dissolution, which created an alkali environment confirmed by an increase in the brine pH. We believe the increase in pH increased the hydrophilic character of the pores; thus, increasing oil recovery.
{"title":"Cost-Effective Chemical EOR for Heterogenous Carbonate Reservoirs Using a Ketone-Surfactant System","authors":"Etaf Alghunaim, O. Uzun, H. Kazemi, J. Sarg","doi":"10.2118/205910-ms","DOIUrl":"https://doi.org/10.2118/205910-ms","url":null,"abstract":"\u0000 The complexity, high cost, and potential environmental concerns of chemical enhanced oil recovery (EOR) methods have diminished their field applications considerably. However, considering the significant incremental oil recoveries that can be obtained from these methods encourage researchers to explore ways to reduce both complexity, cost, and environmental concerns of such systems. This is especially important in carbonate formations, where after waterflooding, much of the oil remains trapped in complex reservoir pores—especially if the reservoir contains an interconnected fracture network of flow channels within the bulk rock matrix.\u0000 In this paper, we present an experimental assessment of several simple chemical EOR waterflooding systems comprising of small concentrations of a low cost, low molecular weight ketone and a non-ionic surfactant in association with low-salinity brine. The experiments were conducted in carbonate cores from a Permian Basin San Andres Formation. Four different oil displacement scenarios were investigated using San Andres carbonate cores from the Central Vacuum Field in New Mexico. This included 1) low-salinity brine, 2) low-salinity brine with a surfactant, 3) low-salinity brine with a ketone, and 4) low-salinity brine with a combined ketone-surfactant system. Static imbibition experiments were conducted using a spontaneous imbibition apparatus in addition to the use of a high-speed centrifuge to saturate the cores to irreducible brine saturation.\u0000 Adding a 1% concentration of 3-pentanone and a 1% non-ionic surfactant to a low-salinity brine yielded oil recoveries of 44% from the 3-pentanone system, compared to 11.4% from low-salinity brine only. The oil recovery is enhanced by a single mechanism or synergy of several mechanisms that includes interfacial tension (IFT) reduction by surfactant, capillary imbibition, favorable wettability alteration by ketone, and osmotic low-salinity brine imbibition. The IFT decreased to 1.79 mN/m upon addition of non-ionic surfactant to low-salinity brine, and it reduced to 2.96 mN/m in a mixture of 3-pentanone and non-ionic surfactant in low-salinity brine. Furthermore, ketone improved the core wettability by reducing the contact angle to 43.9° from 50.7° in the low-salinity brine experiment. In addition, the low-salinity brine systems caused mineral dissolution, which created an alkali environment confirmed by an increase in the brine pH. We believe the increase in pH increased the hydrophilic character of the pores; thus, increasing oil recovery.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"402 1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77475754","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}
M. Y. Alklih, N. M. Aljneibi, K. Khan, Melike Dilsiz
Miscible HC-WAG injection is a globally implemented EOR method and seems robust in so many cases. Some of the largest HC-WAG projects are found in major carbonate oil reservoirs in the Middle-East, with miscibility being the first measure to expect the success of a HC-WAG injection. Yet, several miscible injection projects reported disappointing outcomes and challenging implementation that reduces the economic attractiveness of the miscible processes. To date, there are still some arguments on the interpretation of laboratory and field data and predictive modeling. For a miscible flood, to be an efficient process for a given reservoir, several conditions must be satisfied; given that the incremental oil recovery is largely dependent on reservoir properties and fluid characteristic. Experiences gained from a miscible rich HC-WAG project in Abu Dhabi, implemented since 2006, indicate that an incremental recovery of 10% of the original oil in place can be achieved, compared to water flooding. However, experiences also show that several complexities are being faced, including but not limited to, issues of water injectivity in the mixed wettability nature of the reservoir, achieving miscibility conditions full field, maintaining VRR and corresponding flow behavior, suitability of monitoring strategy, UTC optimization efforts by gas curtailment and most importantly challenges of modeling the miscibility behavior across the reservoir. A number of mitigation plans and actions are put in place to chase the positive impacts of enhanced oil recovery by HC-WAG injection. If gas injection is controlled for gravity and dissolution along with proper understanding on the limitations of WAG, then miscible flood will lead to excellent results in the field. The low frequency of certain reservoir monitoring activities, hence less available data for assessment and modeling, can severely bound the benefits of HC-WAG and make it more difficult to justify the injection of gas, particularly in those days when domestic gas market arises. This work aims to discuss the lessons learned from the ongoing development of HC-WAG and attempts to comprehend miscible flood assessment methods.
{"title":"Does Miscibility Alone Predict the Success of WAG Projects? Key Issues in Miscible HC-WAG Injection","authors":"M. Y. Alklih, N. M. Aljneibi, K. Khan, Melike Dilsiz","doi":"10.2118/206116-ms","DOIUrl":"https://doi.org/10.2118/206116-ms","url":null,"abstract":"\u0000 Miscible HC-WAG injection is a globally implemented EOR method and seems robust in so many cases. Some of the largest HC-WAG projects are found in major carbonate oil reservoirs in the Middle-East, with miscibility being the first measure to expect the success of a HC-WAG injection. Yet, several miscible injection projects reported disappointing outcomes and challenging implementation that reduces the economic attractiveness of the miscible processes. To date, there are still some arguments on the interpretation of laboratory and field data and predictive modeling.\u0000 For a miscible flood, to be an efficient process for a given reservoir, several conditions must be satisfied; given that the incremental oil recovery is largely dependent on reservoir properties and fluid characteristic. Experiences gained from a miscible rich HC-WAG project in Abu Dhabi, implemented since 2006, indicate that an incremental recovery of 10% of the original oil in place can be achieved, compared to water flooding. However, experiences also show that several complexities are being faced, including but not limited to, issues of water injectivity in the mixed wettability nature of the reservoir, achieving miscibility conditions full field, maintaining VRR and corresponding flow behavior, suitability of monitoring strategy, UTC optimization efforts by gas curtailment and most importantly challenges of modeling the miscibility behavior across the reservoir.\u0000 A number of mitigation plans and actions are put in place to chase the positive impacts of enhanced oil recovery by HC-WAG injection. If gas injection is controlled for gravity and dissolution along with proper understanding on the limitations of WAG, then miscible flood will lead to excellent results in the field. The low frequency of certain reservoir monitoring activities, hence less available data for assessment and modeling, can severely bound the benefits of HC-WAG and make it more difficult to justify the injection of gas, particularly in those days when domestic gas market arises.\u0000 This work aims to discuss the lessons learned from the ongoing development of HC-WAG and attempts to comprehend miscible flood assessment methods.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"34 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80969831","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}
Florian Aichinger, L. Brillaud, B. Nobbs, Florent Couliou, J. Oyovwevotu, Graeme Mathieson, David Vavasseur, Jamie Hardie
This paper will present predicted vs. measured wear for six wells that were analysed in the Culzean field, which is a high-pressure, high-temperature (HPHT) gas condensate field located in the central North Sea. The focus rests on the casing wear prediction, monitoring and analysing process and within that, especially on how to make use of offset well data to improve the accuracy of casing wear predictions. The three major inputs to successfully predict casing wear are: Trajectory & tortuosity, wear factor and required rotating operations. All those were calibrated based on field measurements (High-resolution gyro, MFCL (Multi-Finger-Caliper-Log) and automatically recorded rig mechanics data), to improve the prediction quality for the next section and/or well. The simulations were done using an advanced stiff-string model featuring a 3D mesh that distinguishes the influence of different contact type and geometry on the wear groove shape. The "single MFCL interpretation method", in which the wear is measured against the most probable elliptical casing shape and herby allowing wear interpretation with only one MFCL log and avoiding bias error, was applied. (Aichinger, 2016) For the six wells that were analysed the prediction of the largest wear peak per well section was compared to the measurement. In the planning phase (before any survey data was available) the mean absolute error on the wear groove depth was +/- 0.018 [in] (+/- 0.46 [mm]), the maximum error was + 0.045 [in] (+ 1.1 [mm]). The error of the results is summarized in Figure 10 and laid out in detail in Figure 9. Generally, the predictions are accurate enough to be able to manage casing wear effectively. In this case, the maximum allowable wear on the intermediate casing was extremely limited to ensure proper well integrity in case of a well full of gas event while drilling an HTHP reservoir. This paper should provide help to engineers who seek to improve the accuracy of casing wear prediction and hence improve casing wear management. It presents a new way of anticipating tortuosity based on offset well data and it offers a suggestion on how to deal with MFCL measurement error during wear factor calibration and wear prediction.
{"title":"Casing Wear: Prediction, Monitoring, Analysis and Management in the Culzean Field","authors":"Florian Aichinger, L. Brillaud, B. Nobbs, Florent Couliou, J. Oyovwevotu, Graeme Mathieson, David Vavasseur, Jamie Hardie","doi":"10.2118/206221-ms","DOIUrl":"https://doi.org/10.2118/206221-ms","url":null,"abstract":"\u0000 \u0000 \u0000 This paper will present predicted vs. measured wear for six wells that were analysed in the Culzean field, which is a high-pressure, high-temperature (HPHT) gas condensate field located in the central North Sea.\u0000 The focus rests on the casing wear prediction, monitoring and analysing process and within that, especially on how to make use of offset well data to improve the accuracy of casing wear predictions.\u0000 \u0000 \u0000 \u0000 The three major inputs to successfully predict casing wear are: Trajectory & tortuosity, wear factor and required rotating operations. All those were calibrated based on field measurements (High-resolution gyro, MFCL (Multi-Finger-Caliper-Log) and automatically recorded rig mechanics data), to improve the prediction quality for the next section and/or well.\u0000 The simulations were done using an advanced stiff-string model featuring a 3D mesh that distinguishes the influence of different contact type and geometry on the wear groove shape.\u0000 The \"single MFCL interpretation method\", in which the wear is measured against the most probable elliptical casing shape and herby allowing wear interpretation with only one MFCL log and avoiding bias error, was applied. (Aichinger, 2016)\u0000 \u0000 \u0000 \u0000 For the six wells that were analysed the prediction of the largest wear peak per well section was compared to the measurement. In the planning phase (before any survey data was available) the mean absolute error on the wear groove depth was +/- 0.018 [in] (+/- 0.46 [mm]), the maximum error was + 0.045 [in] (+ 1.1 [mm]). The error of the results is summarized in Figure 10 and laid out in detail in Figure 9. Generally, the predictions are accurate enough to be able to manage casing wear effectively.\u0000 In this case, the maximum allowable wear on the intermediate casing was extremely limited to ensure proper well integrity in case of a well full of gas event while drilling an HTHP reservoir.\u0000 \u0000 \u0000 \u0000 This paper should provide help to engineers who seek to improve the accuracy of casing wear prediction and hence improve casing wear management. It presents a new way of anticipating tortuosity based on offset well data and it offers a suggestion on how to deal with MFCL measurement error during wear factor calibration and wear prediction.\u0000","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"33 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81606981","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}
Improved Oil Recovery, IOR, in shales is a topic of growing interest due to the low oil recovery observed in shales. Evaluating different IOR chemicals at the lab scale has proved difficult and time consuming due to their ultra-low permeability and low porosity. Conventional core procedures (such as core floods) are often not practical to use with such samples since they take too long. In this study, we introduce a new laboratory method for measuring the oil recovery in a huff-and-puff IOR process in shales. In huff-and-puff IOR, a treatment additive and a gas are typically injected in combination into the reservoir. Oil production is initiated after a shut-in period. Our experimental protocol starts by saturating preserved shales with oil by exposing them to the reservoir oil under pressure for an extended time. To speed up this process the preserved shale sample is crushed and sieved to 5-10 mesh. The pressure vessels are then loaded with these oil-saturated 5-10 mesh shale particles and the desired IOR fluid is injected into the pressure vessel. The vessel is rotated to ensure full contact with the shale. The samples are heated to ensure that the fluid is at reservoir pressure and temperature. Several tests were done to ensure that the fluid temperature and pressure inside the vessels were at the desired conditions throughout the 72-hour test period. T2 NMR scans were carried out before and after treatment to determine the amount of incremental oil recovery from the treatment. In tests where the two fluid phases were indistinguishable, deuterium was used in the treatment fluid in lieu of water. Excellent reproducible results were obtained with this method. This new method has been used to test a number of different treatment fluids, gases and solvents under a variety of conditions. The test can be completed in a matter of a few days as compared to several weeks that would be required for a core flood. Several tests can be run simultaneously, further speeding up the process. The results of the laboratory tests can be scaled to the field by using suitable surface-to-volume ratios in the lab and comparing them to the field. With this new method we have a fast and robust method for conducting these huff-and-puff experiments in a repeatable, and precise manner. This allows us to quickly evaluate different IOR fluids for a particular shale-fluid system at reservoir conditions.
{"title":"A New Experimental Method for Measuring Improved Oil Recovery in Shales","authors":"Zach Quintanilla, R. Russell, M. Sharma","doi":"10.2118/206016-ms","DOIUrl":"https://doi.org/10.2118/206016-ms","url":null,"abstract":"\u0000 Improved Oil Recovery, IOR, in shales is a topic of growing interest due to the low oil recovery observed in shales. Evaluating different IOR chemicals at the lab scale has proved difficult and time consuming due to their ultra-low permeability and low porosity. Conventional core procedures (such as core floods) are often not practical to use with such samples since they take too long.\u0000 In this study, we introduce a new laboratory method for measuring the oil recovery in a huff-and-puff IOR process in shales. In huff-and-puff IOR, a treatment additive and a gas are typically injected in combination into the reservoir. Oil production is initiated after a shut-in period. Our experimental protocol starts by saturating preserved shales with oil by exposing them to the reservoir oil under pressure for an extended time. To speed up this process the preserved shale sample is crushed and sieved to 5-10 mesh. The pressure vessels are then loaded with these oil-saturated 5-10 mesh shale particles and the desired IOR fluid is injected into the pressure vessel. The vessel is rotated to ensure full contact with the shale. The samples are heated to ensure that the fluid is at reservoir pressure and temperature. Several tests were done to ensure that the fluid temperature and pressure inside the vessels were at the desired conditions throughout the 72-hour test period. T2 NMR scans were carried out before and after treatment to determine the amount of incremental oil recovery from the treatment. In tests where the two fluid phases were indistinguishable, deuterium was used in the treatment fluid in lieu of water. Excellent reproducible results were obtained with this method. This new method has been used to test a number of different treatment fluids, gases and solvents under a variety of conditions. The test can be completed in a matter of a few days as compared to several weeks that would be required for a core flood. Several tests can be run simultaneously, further speeding up the process. The results of the laboratory tests can be scaled to the field by using suitable surface-to-volume ratios in the lab and comparing them to the field.\u0000 With this new method we have a fast and robust method for conducting these huff-and-puff experiments in a repeatable, and precise manner. This allows us to quickly evaluate different IOR fluids for a particular shale-fluid system at reservoir conditions.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"14 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82736477","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}
A. Khitrenko, S. Fedotkin, Ayk Nazaryan, S. Zhigulskiy, P. Emelyanov
Seismic data is a main source of information for lateral forecast of lithofacies. No one can deny that seismic data is a useful method to determinate structure of prospects. However, we have to accept to urgent need to implement steps that will make possible to predict distribution of lithofacies. In exploration, the prediction of lithology and fluid properties is a main goal. Popularity and comparative simplicity of inversion, made seismic inversion popular for reservoir characterization. Despite the benefits of method, inability to estimate uncertainty of models, stochastic seismic inversion was inveted. A stochastic seismic inversion combine relationship with varying lithofacies parameters and elastic properties using uncertainty of each data. Additional modification of stochastic seismic inversion is geological constraints allows to exclude not appropriate realization and obtain correct probability model of lithofacies. Comparison of approaches and results on a real set provided from the Tyumen formation in Western Siberia allows to estimate advantages and disadvantages of modification stochastic Seismic inversion.
{"title":"Risk Reduction on the Western Siberia Prospect Using Stochastic Seismic Inversion and Geological Constraints","authors":"A. Khitrenko, S. Fedotkin, Ayk Nazaryan, S. Zhigulskiy, P. Emelyanov","doi":"10.2118/205954-ms","DOIUrl":"https://doi.org/10.2118/205954-ms","url":null,"abstract":"\u0000 Seismic data is a main source of information for lateral forecast of lithofacies. No one can deny that seismic data is a useful method to determinate structure of prospects. However, we have to accept to urgent need to implement steps that will make possible to predict distribution of lithofacies. In exploration, the prediction of lithology and fluid properties is a main goal. Popularity and comparative simplicity of inversion, made seismic inversion popular for reservoir characterization. Despite the benefits of method, inability to estimate uncertainty of models, stochastic seismic inversion was inveted. A stochastic seismic inversion combine relationship with varying lithofacies parameters and elastic properties using uncertainty of each data. Additional modification of stochastic seismic inversion is geological constraints allows to exclude not appropriate realization and obtain correct probability model of lithofacies.\u0000 Comparison of approaches and results on a real set provided from the Tyumen formation in Western Siberia allows to estimate advantages and disadvantages of modification stochastic Seismic inversion.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89016548","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}
C. Pedroso, Kesavan Govinathan, I. Mickelburgh, Philip Wassouf, C. Latini
In recent years, it has become common practice for operating companies to make a significant effort in the planning of gravel pack installations, especially in their most important wells. Typically, the placement of the gravel pack is accurately modelled, and multiple contingencies developed for potential alternative scenarios to reduce the overall risk of execution. After the pack has been placed, the use of down-hole gauge data enables the gravel pack to be fully evaluated in order to confirm success and investigate any issues or failures. This understanding feeds into improved designs and ever higher success rates for future completions. The most challenging gravel packs Operators are installing today are those placed in long horizontal open holes, around screens fitted with Inflow Control Devices (ICDs) or Autonomous Inflow Control Devices (AICDs). Simulating gravel pack placement in wells such as these requires the effective modelling of unusually dynamic and complex flow paths. Until recently, no simulator could adequately model these treatments. Most jobs have also been done without the downhole gauges necessary for a complete job evaluation, which has resulted in a lack of data for job evaluation and understanding. Consequently, completions requiring the pack to be placed around ICD/AICD screen assemblies have, until recently, been done without the assurance of pre-job gravel pack placement modelling. The lack of an adequate simulator has also meant that, even on these complex and valuable wells, Operators have been restricted to simple volumetric evaluation of their success. With no way to understand actual packing mechanisms or investigate root causes of failures, the assumptions made on how packing occurs in these complex wells have remained unconfirmed. Recent evolution of gravel pack simulators has made the effective pre-job simulation, and post-job evaluation, of gravel packs placed around ICD/AICDs a reality. This paper presents the results of the first evaluation of a multi-proppant deep water horizontal alpha beta gravel pack around AICD screens. It facilitates the understanding of how such gravel packs are placed, validates the packing efficiencies, and illustrates the benefits of using multiple gravels for packing.
{"title":"Understanding AICD Gravel Packing","authors":"C. Pedroso, Kesavan Govinathan, I. Mickelburgh, Philip Wassouf, C. Latini","doi":"10.2118/206153-ms","DOIUrl":"https://doi.org/10.2118/206153-ms","url":null,"abstract":"\u0000 In recent years, it has become common practice for operating companies to make a significant effort in the planning of gravel pack installations, especially in their most important wells. Typically, the placement of the gravel pack is accurately modelled, and multiple contingencies developed for potential alternative scenarios to reduce the overall risk of execution. After the pack has been placed, the use of down-hole gauge data enables the gravel pack to be fully evaluated in order to confirm success and investigate any issues or failures. This understanding feeds into improved designs and ever higher success rates for future completions.\u0000 The most challenging gravel packs Operators are installing today are those placed in long horizontal open holes, around screens fitted with Inflow Control Devices (ICDs) or Autonomous Inflow Control Devices (AICDs). Simulating gravel pack placement in wells such as these requires the effective modelling of unusually dynamic and complex flow paths. Until recently, no simulator could adequately model these treatments. Most jobs have also been done without the downhole gauges necessary for a complete job evaluation, which has resulted in a lack of data for job evaluation and understanding.\u0000 Consequently, completions requiring the pack to be placed around ICD/AICD screen assemblies have, until recently, been done without the assurance of pre-job gravel pack placement modelling. The lack of an adequate simulator has also meant that, even on these complex and valuable wells, Operators have been restricted to simple volumetric evaluation of their success. With no way to understand actual packing mechanisms or investigate root causes of failures, the assumptions made on how packing occurs in these complex wells have remained unconfirmed.\u0000 Recent evolution of gravel pack simulators has made the effective pre-job simulation, and post-job evaluation, of gravel packs placed around ICD/AICDs a reality. This paper presents the results of the first evaluation of a multi-proppant deep water horizontal alpha beta gravel pack around AICD screens. It facilitates the understanding of how such gravel packs are placed, validates the packing efficiencies, and illustrates the benefits of using multiple gravels for packing.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"32 6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90593132","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}
There are advantages to using high performance lightweight cement when encountering low bottomhole pressures. The most notable are maintaining wellbore stability during cement placement and the isolation of potential flow zones to achieve the wellbore construction objectives. Several complex wells sought these advantages for similar situations. A review of the deployment process for using high performance lightweight cement conventionally, including the quality assurance measures, initially deemed it as not a viable option. As the complex wells needed a technical solution, an unconventional deployment method for high performance lightweight cement enabled its use while simplifying and improving quality assurance; allowing achievement of the isolation requirements.
{"title":"Stranger Things 2: Unconventional Deployment Method of High Performance Lightweight Cement Enables Success in Complex Wells","authors":"J. Shine, Urooj Qasmi, I. Gbemiga","doi":"10.2118/206191-ms","DOIUrl":"https://doi.org/10.2118/206191-ms","url":null,"abstract":"\u0000 There are advantages to using high performance lightweight cement when encountering low bottomhole pressures. The most notable are maintaining wellbore stability during cement placement and the isolation of potential flow zones to achieve the wellbore construction objectives. Several complex wells sought these advantages for similar situations. A review of the deployment process for using high performance lightweight cement conventionally, including the quality assurance measures, initially deemed it as not a viable option. As the complex wells needed a technical solution, an unconventional deployment method for high performance lightweight cement enabled its use while simplifying and improving quality assurance; allowing achievement of the isolation requirements.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"22 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88725600","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}
Mohamed Alhammadi, S. Masalmeh, B. Al-Shehhi, M. Sohrabi, A. Farzaneh
This study aims to compare the roles of rock and crude oil in improving recovery by low salinity water injection (LSWI) and, particularly, to explore the significance of micro-dispersion formation in LSWI performance. Core samples and crude oil were taken from two carbonate reservoirs (A and B) in Abu Dhabi. The oil samples were selected such that one of them would form micro-dispersion when in contact with low salinity brine while the other would not. A series of coreflood experiments was performed in secondary and tertiary modes under reservoir conditions. First, a core sample from reservoir A was initialized and aged with crude oil from reservoir A and a core sample from reservoir B was initialized and aged with crude oil from reservoir B. The cores were then swapped, and the performance of low salinity injection was tested using rock from reservoir A and crude from reservoir B, and vice versa. For the first set of experiments, we found that the crude oil sample capable of forming micro-dispersion (we call this oil "positive", from reservoir A) resulted in extra oil recovery in both secondary and tertiary LSWI modes, compared to high salinity flooding. Moreover, in the secondary LSWI mode we observed significant acceleration of oil production, with higher ultimate oil recovery (12.5%) compared to tertiary mode (6.5%). To ensure repeatability, the tertiary experiment was repeated, and the results were reproduced. The core flood test performed using "negative" crude oil that did not form micro-dispersion (from reservoir B) showed no improvement in oil recovery compared to high salinity waterflooding. In the "cross-over" experiments (when cores were swapped), the positive crude oil showed a similar improvement in oil recovery and the negative crude oil showed no improvement in oil recovery even though each of them was used with a core sample from the other reservoir. These results suggest that it is the properties of crude oil rather than the rock that play the greater role in oil recovery. These results suggest that the ability of crude oil to form micro-dispersion when contacted with low salinity water is an important factor in determining whether low salinity injection will lead to extra oil recovery during both secondary and tertiary LSWI. The pH and ionic composition of the core effluent were measured for all experiments and were unaffected by the combination of core and oil used in each experiment. This work provides new experimental evidence regarding real reservoir rock and oil under reservoir conditions. The novel crossover approach in which crude oil from one reservoir was tested in another reservoir rock was helpful for understanding the relative roles of crude oil and rock in the low salinity water mechanism. Our approach suggests a simple, rapid and low-cost methodology for screening target reservoirs for LSWI.
{"title":"Experimental Investigation of the Impact of Crude Oil and Rock on Improved Recovery by Low Salinity Water Injection","authors":"Mohamed Alhammadi, S. Masalmeh, B. Al-Shehhi, M. Sohrabi, A. Farzaneh","doi":"10.2118/206118-ms","DOIUrl":"https://doi.org/10.2118/206118-ms","url":null,"abstract":"\u0000 This study aims to compare the roles of rock and crude oil in improving recovery by low salinity water injection (LSWI) and, particularly, to explore the significance of micro-dispersion formation in LSWI performance. Core samples and crude oil were taken from two carbonate reservoirs (A and B) in Abu Dhabi. The oil samples were selected such that one of them would form micro-dispersion when in contact with low salinity brine while the other would not.\u0000 A series of coreflood experiments was performed in secondary and tertiary modes under reservoir conditions. First, a core sample from reservoir A was initialized and aged with crude oil from reservoir A and a core sample from reservoir B was initialized and aged with crude oil from reservoir B. The cores were then swapped, and the performance of low salinity injection was tested using rock from reservoir A and crude from reservoir B, and vice versa.\u0000 For the first set of experiments, we found that the crude oil sample capable of forming micro-dispersion (we call this oil \"positive\", from reservoir A) resulted in extra oil recovery in both secondary and tertiary LSWI modes, compared to high salinity flooding. Moreover, in the secondary LSWI mode we observed significant acceleration of oil production, with higher ultimate oil recovery (12.5%) compared to tertiary mode (6.5%). To ensure repeatability, the tertiary experiment was repeated, and the results were reproduced. The core flood test performed using \"negative\" crude oil that did not form micro-dispersion (from reservoir B) showed no improvement in oil recovery compared to high salinity waterflooding. In the \"cross-over\" experiments (when cores were swapped), the positive crude oil showed a similar improvement in oil recovery and the negative crude oil showed no improvement in oil recovery even though each of them was used with a core sample from the other reservoir. These results suggest that it is the properties of crude oil rather than the rock that play the greater role in oil recovery. These results suggest that the ability of crude oil to form micro-dispersion when contacted with low salinity water is an important factor in determining whether low salinity injection will lead to extra oil recovery during both secondary and tertiary LSWI. The pH and ionic composition of the core effluent were measured for all experiments and were unaffected by the combination of core and oil used in each experiment.\u0000 This work provides new experimental evidence regarding real reservoir rock and oil under reservoir conditions. The novel crossover approach in which crude oil from one reservoir was tested in another reservoir rock was helpful for understanding the relative roles of crude oil and rock in the low salinity water mechanism. Our approach suggests a simple, rapid and low-cost methodology for screening target reservoirs for LSWI.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"44 1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87829112","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}
The estimation of the drilling window limits ensures that lost circulation and wellbore instability events are minimized. These limits are conventionally defined during the pre-drilling phase based on offset wells data. As drilling commences, mud weights are selected to fit within these limits and they can be adjusted to react to different drilling scenarios as long as they don't violate the defined limits. This process fails to consider the effect of the initial mud weight and its subsequent adjustments on the strength of the wellbore. The concept of stress hysteresis dictates that when a body is subjected to a certain load, such as the one exerted by the hydrostatic pressure of the mud, its state will be altered in a manner that can shift its strength limits. This work presents a model that quantifies the changes in the drilling window due to variations in mud weight. The objective is to ensure that any subsequent mud weight changes will fall within the updated drilling window limits. The analysis is carried out using a novel process of a 3D poro-elasto-plastic finite element model (FEM) that is integrated with a machine learning (ML) algorithm. The integrated FEM-ML model uses offset wells data along with the best fitting failure criterion to estimate the initial limits of the drilling window. The offset wells data used consist of wireline logs, drilling reports, and mechanical testing lab results belonging to the formation of interest. The integrated model uses this data to estimate the stress distribution and learn the failure patterns. The model is then used to run different scenarios of mud weight variations while drilling a specific hole section to quantify their effect on the drilling window. The end result of each scenario is an update of the drilling window, which reflects the effect of stress hysteresis. When examining the initial estimations of the drilling window against those reflecting the stress path effect, a significant discrepancy in the window size is quantified. This examination is carried out for an offset well, which experienced multiple mud weight changes as a response to various drilling events. Subsequently, the changes in the drilling window and the actual mud weights used are analyzed in view of the drilling difficulties experienced in that specific offset well for the purpose of providing a form of validation. The model results show that the drilling window had shrunk significantly enough for the mud weight to violate the wellbore stability limit. Failure to consider the stress hysteresis effect in this well led major wellbore instability, tight hole, and overpull. The modelling effort presented in this work allows for a new aspect of dynamic responses to drilling events as they occur.
{"title":"Quantifying the Effect of Stress Hysteresis on the Drilling Window: How Mud Weight Variations Can Affect Wellbore Strength","authors":"H. Albahrani, Nobuo Morita, M. Alqam","doi":"10.2118/206199-ms","DOIUrl":"https://doi.org/10.2118/206199-ms","url":null,"abstract":"\u0000 The estimation of the drilling window limits ensures that lost circulation and wellbore instability events are minimized. These limits are conventionally defined during the pre-drilling phase based on offset wells data. As drilling commences, mud weights are selected to fit within these limits and they can be adjusted to react to different drilling scenarios as long as they don't violate the defined limits. This process fails to consider the effect of the initial mud weight and its subsequent adjustments on the strength of the wellbore. The concept of stress hysteresis dictates that when a body is subjected to a certain load, such as the one exerted by the hydrostatic pressure of the mud, its state will be altered in a manner that can shift its strength limits. This work presents a model that quantifies the changes in the drilling window due to variations in mud weight. The objective is to ensure that any subsequent mud weight changes will fall within the updated drilling window limits.\u0000 The analysis is carried out using a novel process of a 3D poro-elasto-plastic finite element model (FEM) that is integrated with a machine learning (ML) algorithm. The integrated FEM-ML model uses offset wells data along with the best fitting failure criterion to estimate the initial limits of the drilling window. The offset wells data used consist of wireline logs, drilling reports, and mechanical testing lab results belonging to the formation of interest. The integrated model uses this data to estimate the stress distribution and learn the failure patterns. The model is then used to run different scenarios of mud weight variations while drilling a specific hole section to quantify their effect on the drilling window. The end result of each scenario is an update of the drilling window, which reflects the effect of stress hysteresis.\u0000 When examining the initial estimations of the drilling window against those reflecting the stress path effect, a significant discrepancy in the window size is quantified. This examination is carried out for an offset well, which experienced multiple mud weight changes as a response to various drilling events. Subsequently, the changes in the drilling window and the actual mud weights used are analyzed in view of the drilling difficulties experienced in that specific offset well for the purpose of providing a form of validation. The model results show that the drilling window had shrunk significantly enough for the mud weight to violate the wellbore stability limit. Failure to consider the stress hysteresis effect in this well led major wellbore instability, tight hole, and overpull.\u0000 The modelling effort presented in this work allows for a new aspect of dynamic responses to drilling events as they occur.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"11 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87915193","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}
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