Joel Dowlath, K. Onyeagoro, Elizabeth Sookal, Kevan Quammie, Ashwin Srinivasan
The Enterprise gas field is a discovery in Shell's operated acreage in the Columbus Basin off the east coast of Trinidad. It is comprised of two major fault blocks, with an exploration well in the smaller one and an appraisal well in the larger one. The larger fault block is further broken up by minor faults. The potential compartmentalization of this fault block is the major uncertainty in the development of the Enterprise field. The development plan called for one or two wells to be drilled in the Enterprise field. Detailed mapping of each of the minor faults and analysis of log and pressure data from the wells was used to determine how well connected the various segments are. Using relationships derived from a global database and Vshale logs from offset wells, a range of fault transmissibility multipliers was derived for each fault based on calculated shale gouge ratios and mapped fault throws. Results of the dynamic fault seal analysis were integrated with dynamic simulation and showed that using base case fault transmissibility multipliers, for all segments where there is reservoir-reservoir juxtaposition across the minor faults, there will be connectivity and the larger fault block can be drained by a single development well. Various combinations of well placements were tested against low, base and high case geological realizations and these were used to determine the optimal development scenario for the field.
{"title":"The Faults in our Fields – Well Count and Placement in a Columbus Basin Gas Field","authors":"Joel Dowlath, K. Onyeagoro, Elizabeth Sookal, Kevan Quammie, Ashwin Srinivasan","doi":"10.2118/191226-MS","DOIUrl":"https://doi.org/10.2118/191226-MS","url":null,"abstract":"\u0000 The Enterprise gas field is a discovery in Shell's operated acreage in the Columbus Basin off the east coast of Trinidad. It is comprised of two major fault blocks, with an exploration well in the smaller one and an appraisal well in the larger one. The larger fault block is further broken up by minor faults. The potential compartmentalization of this fault block is the major uncertainty in the development of the Enterprise field.\u0000 The development plan called for one or two wells to be drilled in the Enterprise field. Detailed mapping of each of the minor faults and analysis of log and pressure data from the wells was used to determine how well connected the various segments are. Using relationships derived from a global database and Vshale logs from offset wells, a range of fault transmissibility multipliers was derived for each fault based on calculated shale gouge ratios and mapped fault throws.\u0000 Results of the dynamic fault seal analysis were integrated with dynamic simulation and showed that using base case fault transmissibility multipliers, for all segments where there is reservoir-reservoir juxtaposition across the minor faults, there will be connectivity and the larger fault block can be drained by a single development well. Various combinations of well placements were tested against low, base and high case geological realizations and these were used to determine the optimal development scenario for the field.","PeriodicalId":11006,"journal":{"name":"Day 3 Wed, June 27, 2018","volume":"98 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77030874","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 objective of this study was to systematically and quantitatively quantify where production from Thin – Bedded Pay may be more challenging using conventional methods of completion. This study will focus on different areas within the deltaic environment in which Thin – Bedded Pay are prominent. A 3D structural model was built and populated with properties to represent four (4) different main classes of geological environments with a deltaic system. It explored the effect of completing across the conventional sands only vs completing both the conventional and secondary units. The main finding in this thesis is that completing the thin-bedded pay increased the overall rate of the production on average of about 10% in different environments. In addition, in complicated reservoir architecture environments such as the upper slope and distal delta slope environments, there are significant (14% and 10%) incremental increases in the recovery factors by completing across these thinly bedded zones. Thus, it is recommended that these environments be further explored in how best to develop the thin-bedded resource in these environments since, in a time when the finite resources of oil and gas are becoming scarce, it is important to understand what reserves we may have that are not currently being tapped into.
{"title":"A Study in Quantifying Thin-Bedded Pay Contribution Within a Deltaic System in the Columbus Basin","authors":"J. Fortune, R. Jackman","doi":"10.2118/191231-MS","DOIUrl":"https://doi.org/10.2118/191231-MS","url":null,"abstract":"\u0000 The objective of this study was to systematically and quantitatively quantify where production from Thin – Bedded Pay may be more challenging using conventional methods of completion. This study will focus on different areas within the deltaic environment in which Thin – Bedded Pay are prominent. A 3D structural model was built and populated with properties to represent four (4) different main classes of geological environments with a deltaic system. It explored the effect of completing across the conventional sands only vs completing both the conventional and secondary units. The main finding in this thesis is that completing the thin-bedded pay increased the overall rate of the production on average of about 10% in different environments. In addition, in complicated reservoir architecture environments such as the upper slope and distal delta slope environments, there are significant (14% and 10%) incremental increases in the recovery factors by completing across these thinly bedded zones. Thus, it is recommended that these environments be further explored in how best to develop the thin-bedded resource in these environments since, in a time when the finite resources of oil and gas are becoming scarce, it is important to understand what reserves we may have that are not currently being tapped into.","PeriodicalId":11006,"journal":{"name":"Day 3 Wed, June 27, 2018","volume":"57 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84063583","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}
O. Espinola, R. Mehranfar, J. Álvarez, J. Villanueva, L. Vazquez
Integrated asset modeling has been used for the last decade with a wide technical application covering different challenges from field development to production optimization. Besides supporting the FEEDS and FEL studies for different purposes. Moreover, the technology has evolved in terms of integration and dynamic or transient simulation has been added as an extra element expanding the possibility to cover different challenges and workflows. The objective of this paper is to show how this dynamic integration (Dynamic integrated asset modeling) was applied to a common problem of several reservoirs that produce water and gas under different dynamic mechanisms (injection, aquifer and gas cap) to understand, from the reservoir perspective, the effects of gas and water conning over the entire production system. The methodology applied was using a refined sector model solved with numerical simulation and coupled with a transient multiphase flow simulator to see how pressure drop affect the contacts level and shape based on the petrophysical properties and under different production scenarios and generate different graphics to see how this phenomenon behaves. Besides a comparison with all the most analytical correlations used in the literature to identify gas and water conning was performed to see the differences among them and with this dynamic integrated approach. On the other hand, for the production side this coupled model was applied to an offshore facility to see these reservoir effects in the transport system and how they impact in the pipeline and riser due to this abrupt entrance of gas and water changing the flow conditions, flow patterns, pressure drop and creating some instabilities in the separators caused by severe slugging. The results of this analysis were very useful to understand the total production systems (reservoir-surface) behavior, predict the gas and water breakthrough, establish the critical rates to avoid these problems and see how the results differ in some cases with the common analytical correlations. Specific conditions in the pipeline and riser were established to quantify the slugging problems and evaluate different alternatives to eliminate the instabilities through proposing different scenarios such as gas injection in the riser, top side choking, etc. Application of this integrated approach has been very beneficial in recognizing the source of the problem, offer proper and feasible solutions in development and operational phases. In addition, validating and reducing uncertainty of related literature correlations and give to the production and reservoir engineers a quick and reliable way to know the critical rates that can support the decision-making process.
{"title":"Application of Integrated Dynamic Asset Modeling to Predict and Resolve Production Instabilities in an Offshore Facility, A Case Study, Mexico","authors":"O. Espinola, R. Mehranfar, J. Álvarez, J. Villanueva, L. Vazquez","doi":"10.2118/191270-MS","DOIUrl":"https://doi.org/10.2118/191270-MS","url":null,"abstract":"\u0000 Integrated asset modeling has been used for the last decade with a wide technical application covering different challenges from field development to production optimization. Besides supporting the FEEDS and FEL studies for different purposes. Moreover, the technology has evolved in terms of integration and dynamic or transient simulation has been added as an extra element expanding the possibility to cover different challenges and workflows. The objective of this paper is to show how this dynamic integration (Dynamic integrated asset modeling) was applied to a common problem of several reservoirs that produce water and gas under different dynamic mechanisms (injection, aquifer and gas cap) to understand, from the reservoir perspective, the effects of gas and water conning over the entire production system.\u0000 The methodology applied was using a refined sector model solved with numerical simulation and coupled with a transient multiphase flow simulator to see how pressure drop affect the contacts level and shape based on the petrophysical properties and under different production scenarios and generate different graphics to see how this phenomenon behaves. Besides a comparison with all the most analytical correlations used in the literature to identify gas and water conning was performed to see the differences among them and with this dynamic integrated approach. On the other hand, for the production side this coupled model was applied to an offshore facility to see these reservoir effects in the transport system and how they impact in the pipeline and riser due to this abrupt entrance of gas and water changing the flow conditions, flow patterns, pressure drop and creating some instabilities in the separators caused by severe slugging.\u0000 The results of this analysis were very useful to understand the total production systems (reservoir-surface) behavior, predict the gas and water breakthrough, establish the critical rates to avoid these problems and see how the results differ in some cases with the common analytical correlations. Specific conditions in the pipeline and riser were established to quantify the slugging problems and evaluate different alternatives to eliminate the instabilities through proposing different scenarios such as gas injection in the riser, top side choking, etc. Application of this integrated approach has been very beneficial in recognizing the source of the problem, offer proper and feasible solutions in development and operational phases. In addition, validating and reducing uncertainty of related literature correlations and give to the production and reservoir engineers a quick and reliable way to know the critical rates that can support the decision-making process.","PeriodicalId":11006,"journal":{"name":"Day 3 Wed, June 27, 2018","volume":"30 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73763748","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}
This paper analyses the results of the combined Cement Bond Log/ Variable Density Log /Radial Bond Log (CBL/VDL/RBL) tool run on 10 consecutively drilled offshore development wells by an operator during the 2015/2016 period in Trinidad and Tobago. The Bond Index (BI) is used as a quantitative criterion for measuring cement to casing bond and the VDL/RBL as a qualitative criterion for cement to formation bond. The performance of the wells after perforation is examined with the aim of highlighting the importance of a good cement job for successful production. Cement pump pressure/pump rate/cement density charts are also examined to explain cement job outcomes.
{"title":"Bond Log Analysis Offshore Trinidad","authors":"C. Welsh","doi":"10.2118/191207-MS","DOIUrl":"https://doi.org/10.2118/191207-MS","url":null,"abstract":"\u0000 This paper analyses the results of the combined Cement Bond Log/ Variable Density Log /Radial Bond Log (CBL/VDL/RBL) tool run on 10 consecutively drilled offshore development wells by an operator during the 2015/2016 period in Trinidad and Tobago. The Bond Index (BI) is used as a quantitative criterion for measuring cement to casing bond and the VDL/RBL as a qualitative criterion for cement to formation bond. The performance of the wells after perforation is examined with the aim of highlighting the importance of a good cement job for successful production. Cement pump pressure/pump rate/cement density charts are also examined to explain cement job outcomes.","PeriodicalId":11006,"journal":{"name":"Day 3 Wed, June 27, 2018","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82075031","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}
Fengrui Sun, Yuedong Yao, Guozhen Li, L. Zhao, Hao Liu, Xiangfang Li
Most of the previous works were focused on the saturated/superheated steam flow in wellbores coupled with conventional single-tubing injection method. With the rapid development of technology. Supercritical water coupled with toe-point injection technique is proposed. Compared with conventional method, supercritical water could heat the reservoir to a higher temperature, obtain a larger heated radius, and obtain a higher thermal cracking efficiency etc. Besides, toe-point alternating heel-point injection could release the phenomenon of unequal absorption of steam when the horizontal wellbore is extremely long or the reservoir is of serious heterogeneity. This paper presents a model for estimating thermal properties of supercritical water along the inner tubing (IT) and annuli in the horizontal section of the wellbores with toe-point injection technique. Firstly, a flow model in wellbores is proposed based on the mass, energy and momentum conservation equations. Secondly, coupled with flow model in reservoir, a comprehensive mathematical model is proposed. Thirdly, type curves of supercritical water flow in horizontal wellbores with toe-point injection technique is obtained by finite difference method on space and iteration technique. Finally, sensitivity analysis is conducted. Results show that: (a) supercritical water temperature decreases rapidly from heel-point to toe-point in IT. The temperature decrease rate near toe-point of wellbores becomes smaller. (b) The larger the pressure difference, the larger the mass injection rate from annuli to oil layer. (c) When the mass injection rate is small, heat loss from fluid to reservoir plays an important role on temperature drop. (d) When the injection rate is high enough, the effect of heat loss on temperature drop becomes weak. (e) The pressure of supercritical water at a certain place in IT or annuli decreases with injection rate.
{"title":"Water Performance in Toe-Point Injection Wellbores at Supercritical State","authors":"Fengrui Sun, Yuedong Yao, Guozhen Li, L. Zhao, Hao Liu, Xiangfang Li","doi":"10.2118/191151-MS","DOIUrl":"https://doi.org/10.2118/191151-MS","url":null,"abstract":"\u0000 Most of the previous works were focused on the saturated/superheated steam flow in wellbores coupled with conventional single-tubing injection method. With the rapid development of technology. Supercritical water coupled with toe-point injection technique is proposed.\u0000 Compared with conventional method, supercritical water could heat the reservoir to a higher temperature, obtain a larger heated radius, and obtain a higher thermal cracking efficiency etc. Besides, toe-point alternating heel-point injection could release the phenomenon of unequal absorption of steam when the horizontal wellbore is extremely long or the reservoir is of serious heterogeneity.\u0000 This paper presents a model for estimating thermal properties of supercritical water along the inner tubing (IT) and annuli in the horizontal section of the wellbores with toe-point injection technique. Firstly, a flow model in wellbores is proposed based on the mass, energy and momentum conservation equations. Secondly, coupled with flow model in reservoir, a comprehensive mathematical model is proposed. Thirdly, type curves of supercritical water flow in horizontal wellbores with toe-point injection technique is obtained by finite difference method on space and iteration technique. Finally, sensitivity analysis is conducted.\u0000 Results show that: (a) supercritical water temperature decreases rapidly from heel-point to toe-point in IT. The temperature decrease rate near toe-point of wellbores becomes smaller. (b) The larger the pressure difference, the larger the mass injection rate from annuli to oil layer. (c) When the mass injection rate is small, heat loss from fluid to reservoir plays an important role on temperature drop. (d) When the injection rate is high enough, the effect of heat loss on temperature drop becomes weak. (e) The pressure of supercritical water at a certain place in IT or annuli decreases with injection rate.","PeriodicalId":11006,"journal":{"name":"Day 3 Wed, June 27, 2018","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85354669","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 sustained casing pressure (SCP) in shale gas wells caused by cement sheath failure can have serious impacts on safe and efficient gas production. Although horizontal wells are widely used for production from Shales, the cementing quality and casing centericity is barely ensured. Among other indications, the casing off-center is iedtified very often in the wells with SCP problem in Sichuan field. Hence, the objective of this study is to analyze the effect of the casing off-center on the integrity of the cement sheath. To better understand stress distribution in eccentric cement sheaths, an analytical model is proposed in this paper. By comparing the results of this model with the centeric casing, the impacts of casing off-center on integrity of the cement sheath is analyzed. During the fracturing treatment, the casing off-center has little effect on stress in the cement sheath if the well is well cemented and bonded to the formation rock. But on the contrary, the casing off-center has serious effects on stress distribution if the cementing is done poorly. The debonding of casing-cement-formation interfaces can significantly increase the circumferential stress at the cement sheath. At the narrow side of the cement sheath, the circumferential stress could be 2.5 times higher than the thick side. The offset magnitude of the casing eccentricity has little effect on the radial stress in the cement sheath but it can significantly increase the shear stress. We found that the risk of cement failure may reduce by making casing string more centralized, increasing the thickness of casing. The results provide insights for design practices led to better integrity in shale gas wells.
{"title":"Integrity Failure of Cement Sheath Owing to Hydraulic Fracturing and Casing Off-Center in Horizontal Shale Gas Wells","authors":"Kui Liu, D. Gao, A. D. Taleghani","doi":"10.2118/191196-MS","DOIUrl":"https://doi.org/10.2118/191196-MS","url":null,"abstract":"\u0000 The sustained casing pressure (SCP) in shale gas wells caused by cement sheath failure can have serious impacts on safe and efficient gas production. Although horizontal wells are widely used for production from Shales, the cementing quality and casing centericity is barely ensured. Among other indications, the casing off-center is iedtified very often in the wells with SCP problem in Sichuan field. Hence, the objective of this study is to analyze the effect of the casing off-center on the integrity of the cement sheath. To better understand stress distribution in eccentric cement sheaths, an analytical model is proposed in this paper. By comparing the results of this model with the centeric casing, the impacts of casing off-center on integrity of the cement sheath is analyzed. During the fracturing treatment, the casing off-center has little effect on stress in the cement sheath if the well is well cemented and bonded to the formation rock. But on the contrary, the casing off-center has serious effects on stress distribution if the cementing is done poorly. The debonding of casing-cement-formation interfaces can significantly increase the circumferential stress at the cement sheath. At the narrow side of the cement sheath, the circumferential stress could be 2.5 times higher than the thick side. The offset magnitude of the casing eccentricity has little effect on the radial stress in the cement sheath but it can significantly increase the shear stress. We found that the risk of cement failure may reduce by making casing string more centralized, increasing the thickness of casing. The results provide insights for design practices led to better integrity in shale gas wells.","PeriodicalId":11006,"journal":{"name":"Day 3 Wed, June 27, 2018","volume":"74 11 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91029506","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}
Four wells were successfully drilled and completed, but high drilling fluid densities (1.95 to 1.98 SG) were necessary to maintain wellbore stability in the overburden section immediately above the depleted reservoir. The estimated hydrostatic overbalance from the drilling fluid was approximately 800 bar (11,603 psi) higher than reservoir pressure. A wellbore strengthening technique was selected to seal the calculated 1500 μm fractures induced by these high pressures. This paper highlights the engineering, logistical, and operational challenges encountered while successfully drilling and completing such wells. Geomechanical data was initially acquired, including Young's modulus, Poisson's ratio, and minimum in-situ horizontal stress; and, together with the operational parameters [hole diameter and equivalent circulating density (ECD)], these data were used to estimate fracture width (1500 μm). Subsequently, a drilling fluid system was engineered and customized to seal such fractures, thereby strengthening the wellbore to help minimize losses in the reservoir. The solution was validated at two separate laboratories. Large particulate materials with a D50 of 600 to 2300 μm were used. Improvement opportunities during execution were captured for the next cycle. A total drilling fluid loss of 512 m3 during a 16-hour period was experienced in one well after a drilling liner packoff occurred, and fractures greater than 1500 μm were initiated; however, the liner was successfully cemented in place. The coarse particulate materials (600 to 2300 μm) were mobilized in 500 and 1000 kg bags to minimize deck space requirements on the rig and help facilitate ease of mixing. Rig mixing and pit agitation capacity were important for effective mixing of the fluid system. The application also provided the opportunity to align testing procedures and equipment between the field and laboratory. With increasing reservoir depletion, the potential exists for fracture width increases that can impact the particle size of materials necessary to effectively design a solution. Engineered particulate solutions provided a pathway for sourcing and procuring the necessary wellbore strengthening materials.
{"title":"Engineered Wellbore Strengthening Application Enables Successful Drilling of Challenging Wells","authors":"Godwin Chimara, A. Calder, W. Amer, Philip Leslie","doi":"10.2118/191219-MS","DOIUrl":"https://doi.org/10.2118/191219-MS","url":null,"abstract":"\u0000 Four wells were successfully drilled and completed, but high drilling fluid densities (1.95 to 1.98 SG) were necessary to maintain wellbore stability in the overburden section immediately above the depleted reservoir. The estimated hydrostatic overbalance from the drilling fluid was approximately 800 bar (11,603 psi) higher than reservoir pressure. A wellbore strengthening technique was selected to seal the calculated 1500 μm fractures induced by these high pressures. This paper highlights the engineering, logistical, and operational challenges encountered while successfully drilling and completing such wells.\u0000 Geomechanical data was initially acquired, including Young's modulus, Poisson's ratio, and minimum in-situ horizontal stress; and, together with the operational parameters [hole diameter and equivalent circulating density (ECD)], these data were used to estimate fracture width (1500 μm). Subsequently, a drilling fluid system was engineered and customized to seal such fractures, thereby strengthening the wellbore to help minimize losses in the reservoir. The solution was validated at two separate laboratories. Large particulate materials with a D50 of 600 to 2300 μm were used. Improvement opportunities during execution were captured for the next cycle.\u0000 A total drilling fluid loss of 512 m3 during a 16-hour period was experienced in one well after a drilling liner packoff occurred, and fractures greater than 1500 μm were initiated; however, the liner was successfully cemented in place. The coarse particulate materials (600 to 2300 μm) were mobilized in 500 and 1000 kg bags to minimize deck space requirements on the rig and help facilitate ease of mixing. Rig mixing and pit agitation capacity were important for effective mixing of the fluid system. The application also provided the opportunity to align testing procedures and equipment between the field and laboratory. With increasing reservoir depletion, the potential exists for fracture width increases that can impact the particle size of materials necessary to effectively design a solution. Engineered particulate solutions provided a pathway for sourcing and procuring the necessary wellbore strengthening materials.","PeriodicalId":11006,"journal":{"name":"Day 3 Wed, June 27, 2018","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81574188","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}
D. Ryan, Nwenna Crooks-Smith, P. Nurafza, Candice Ogiste, S. Calvert
The Dolphin Field has been producing gas since 1996, however predicting in place volumes, reserves and forecasting production has been a challenge since field inception. The fact that in place estimates have increased significantly since development sanction highlights that a range of geophysical, geological and petrophysical uncertainties are associated with the field. Historically, static volumes have been smaller than dynamic volumes estimated from material balance. The explanation of this difference traditionally related to uncertainty in contact depth (given the minimal data on contacts), that adversely caused poor predictions of water production in the historical models. Many of the reservoir units within the Greater Dolphin Area (GDA) are characterised by a heterolithic deltaic succession of centimeter scale very-fine sandstone, siltstone and mudstone. Given the thin-bedded nature of the reservoir, conventional wireline-logging tools lack the resolution to accurately resolve many of the static parameters including water saturation. However, based on the available PLT data, it is believed that these thin-bedded intervals generally contribute to the production from the wells and hence to the fluid flow in the reservoir. A new static and dynamic reservoir model of the GDA has been built that integrates and incorporates new seismic interpretation, petrophysical recharacterization, revised geological and reservoir engineering concepts, and eventually history matching to production data. A key component of this new model build has been integrated modelling iterations amongst different disciplines from new petrophysical interpretations through to dynamic simulation. Initial iterations used a conventional formation evaluation method and resulted in simulations that showed accelerated pressure drops (compared to production data) as a result of failure to capture flow from thin-beded intervals. An alternative petrophysical methodology that aims to better estimate water saturation within thin bedded intervals has been incorporated into a new workflow to account for the thin bed volumes. The new thin bed simulation model results in greater gas contributions from the thin-bedded intervals and helps overcome the historical shortage of static volumes required to achieve a pressure match.
{"title":"Re-Evaluating Contributions from Thin Bedded Reservoirs: Integrated Reservoir Modelling of the Greater Dolphin Area","authors":"D. Ryan, Nwenna Crooks-Smith, P. Nurafza, Candice Ogiste, S. Calvert","doi":"10.2118/191166-MS","DOIUrl":"https://doi.org/10.2118/191166-MS","url":null,"abstract":"\u0000 The Dolphin Field has been producing gas since 1996, however predicting in place volumes, reserves and forecasting production has been a challenge since field inception. The fact that in place estimates have increased significantly since development sanction highlights that a range of geophysical, geological and petrophysical uncertainties are associated with the field. Historically, static volumes have been smaller than dynamic volumes estimated from material balance. The explanation of this difference traditionally related to uncertainty in contact depth (given the minimal data on contacts), that adversely caused poor predictions of water production in the historical models.\u0000 Many of the reservoir units within the Greater Dolphin Area (GDA) are characterised by a heterolithic deltaic succession of centimeter scale very-fine sandstone, siltstone and mudstone. Given the thin-bedded nature of the reservoir, conventional wireline-logging tools lack the resolution to accurately resolve many of the static parameters including water saturation. However, based on the available PLT data, it is believed that these thin-bedded intervals generally contribute to the production from the wells and hence to the fluid flow in the reservoir.\u0000 A new static and dynamic reservoir model of the GDA has been built that integrates and incorporates new seismic interpretation, petrophysical recharacterization, revised geological and reservoir engineering concepts, and eventually history matching to production data. A key component of this new model build has been integrated modelling iterations amongst different disciplines from new petrophysical interpretations through to dynamic simulation. Initial iterations used a conventional formation evaluation method and resulted in simulations that showed accelerated pressure drops (compared to production data) as a result of failure to capture flow from thin-beded intervals. An alternative petrophysical methodology that aims to better estimate water saturation within thin bedded intervals has been incorporated into a new workflow to account for the thin bed volumes. The new thin bed simulation model results in greater gas contributions from the thin-bedded intervals and helps overcome the historical shortage of static volumes required to achieve a pressure match.","PeriodicalId":11006,"journal":{"name":"Day 3 Wed, June 27, 2018","volume":"61 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75292335","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}
Nowadays advanced decline curve analysis techniques are widely accepted for estimating Hydrocarbon Initially in place (HCIIP), reservoir parameters and production forecasting. These analytical techniques were developed assuming different reservoir models and wellbore geometries. Most of them considered an ideal single well reservoir system, which is not a common scenario of production. In light of that, some authors have proposed theoretical solutions for the analysis of production data of multi-well reservoir. Gas and oil reservoirs has been studied and validated with reservoir simulation models; however the application to real field case was not addresses in detail. There is an example for gas-condensate reservoir with the multi-well approach and the other for an oil field by applying a single well methodology. This paper presents a field case study application of Blasingame type curve method to a multi-well gas-condensate reservoir. Total material balance pseudo-time was calculated using the two-phase compressibility factor. Bottomhole flowing pressures were calculated with vertical flow correlations and adjusted with dynamic gradients. A single well production data was analyzed to estimate the total Original Gas In-Place of a gas-condensate reservoir as well as reservoir parameters. The results of the multi-well method were comparable with volumetric and conventional material balance estimations, as well as well testing interpretation results. Therefore the reliability of the multi-well type curve approach to gas-condensate reservoirs was confirmed.
{"title":"Application of Blasingame Type Curves to a Multi-Well Gas-Condensate Reservoir: Field Case Study","authors":"P. M. Adrian, M. Cabrera","doi":"10.2118/191214-MS","DOIUrl":"https://doi.org/10.2118/191214-MS","url":null,"abstract":"\u0000 Nowadays advanced decline curve analysis techniques are widely accepted for estimating Hydrocarbon Initially in place (HCIIP), reservoir parameters and production forecasting. These analytical techniques were developed assuming different reservoir models and wellbore geometries. Most of them considered an ideal single well reservoir system, which is not a common scenario of production.\u0000 In light of that, some authors have proposed theoretical solutions for the analysis of production data of multi-well reservoir. Gas and oil reservoirs has been studied and validated with reservoir simulation models; however the application to real field case was not addresses in detail. There is an example for gas-condensate reservoir with the multi-well approach and the other for an oil field by applying a single well methodology.\u0000 This paper presents a field case study application of Blasingame type curve method to a multi-well gas-condensate reservoir. Total material balance pseudo-time was calculated using the two-phase compressibility factor. Bottomhole flowing pressures were calculated with vertical flow correlations and adjusted with dynamic gradients. A single well production data was analyzed to estimate the total Original Gas In-Place of a gas-condensate reservoir as well as reservoir parameters.\u0000 The results of the multi-well method were comparable with volumetric and conventional material balance estimations, as well as well testing interpretation results. Therefore the reliability of the multi-well type curve approach to gas-condensate reservoirs was confirmed.","PeriodicalId":11006,"journal":{"name":"Day 3 Wed, June 27, 2018","volume":"7 3","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91508436","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}
Sand-slug fracturing has been the main fracturing pumping mode due to the tightness of shale. This mode makes it easier to inject proppants. However, it may cause poor connectivity in the middle brittle formation due to the discontinuous propping. This paper describes an attempt to fracture the unconventional shales with conventional sand-ramp fracturing pumping mode. The results show that good effect is achieved compared with the sand-slug fracturing mode used in the adjacent wells. Shale reservoir reconstruction has large construction displacement and high pressure, and it adopts fracturing technology of slickwater and linear glue1. In other blocks, Sand-slug mode causes large amounts of slickwater injecting into the formation. The role of water, in addition to carrying sand and making seams, will also cause "water lock" in the micro-fissure, reducing the gas permeability. Therefore, the large amount of liquid is not good to the reservoir. The Sand-ramp modes using less fluid and higher sand content2-3, resulting in a greater height and length of the fractures. By using a small amount of proppant, Sand-ramp mode can also achieve high conductivity4, communicating the natural cracks5-7 at the same time. Two wells were designed for Sand-ramp mode in the test area. Based on the understandings on geological characteristics and formation property, the sand-ramp fracturing pumping mode was designed. Two of six wells in the pad were selected to apply this mode. To maximize the stimulated reservoir volume, slickwater accounted for 40% to 60% of the total injected fluids. 100-mesh quartz sands were pumped in priority to improve the complexity of fracture. Then, the 40-70 mesh ceramsites was pumped with crosslinked gel to support the primary, secondary and natural fractures. The pumping rate is 12-13 cubic meters per minute and no acid is used throughout the whole pumping process. The maximum proppant concentration of sand-ramp reached to 480 kilogram per cubic meters, which was much higher than that of sand-slugs. As a result, good propped fractures were obtained. Since no fluid sweep was used after the sand-slug, the average fluid injection per stage is declined by 27%, but the average sand injection volume was increased by 17%, which significantly reduced the cost and the possible influence to environment. With the sand-ramp mode, the highest test production of the block was up to 278500 cubic meters per day. This well produced 35 million cubic meters of shale gas in 270 days. The practicability of the sand-ramp pumping mode used in unconventional shales is proven to be positive, especially in the formation with high horizontal stress difference. However, the development result needs to be continuously studied.
由于页岩的致密性，砂段塞压裂一直是主要的压裂泵送方式。这种模式使得注入支撑剂更加容易。然而，由于支撑的不连续，可能会导致中间脆性地层连通性差。本文介绍了采用常规砂坡道压裂泵送方式对非常规页岩进行压裂的尝试。结果表明，与邻井采用的砂段塞压裂方式相比，该压裂方式取得了良好的效果。页岩储层改造施工排量大、施工压力高，采用滑溜水-线性胶合压裂技术。在其他区块，砂段塞模式会导致大量滑溜水注入地层。水的作用，除了携砂造缝外，还会在微裂隙中造成“锁水”，降低透气性。因此，大量的液体对储层是不利的。砂坡道模式使用更少的流体和更高的含砂量，导致裂缝的高度和长度更大。通过使用少量支撑剂，砂坡道模式也可以获得高导电性，同时连通天然裂缝。在试验区设计了两口井采用砂坡道模式。基于对地质特征和地层性质的认识，设计了砂坡道压裂泵送模式。该区块的6口井中有2口被选中应用该模式。为了最大限度地提高增产油藏的体积，滑溜水占注入流体总量的40%至60%。优先泵送100目石英砂，以提高裂缝的复杂性。然后，用交联凝胶泵送40-70目陶粒，以支撑初级、次级和天然裂缝。泵送速率为每分钟12-13立方米，在整个泵送过程中不使用酸。砂坡道的最大支撑剂浓度可达480 kg / m3，远高于砂段塞。结果，获得了良好的支撑裂缝。由于在砂段塞之后没有进行扫井作业，每级平均注液量下降了27%，但平均注砂量增加了17%，显著降低了成本和对环境的影响。在砂坡道模式下，该区块的最高测试产量可达278500立方米/天。这口井在270天内生产了3500万立方米的页岩气。在非常规页岩中，特别是在水平应力差较大的地层中，证明了坡道抽砂模式的实用性。但是，开发效果还需要不断的研究。
{"title":"Application of Sand-Ramp Fracturing Pumping Mode in Unconventional Shales Stimulation","authors":"Guangzhi Yang, Shicheng Zhang, Ming Liu","doi":"10.2118/191154-MS","DOIUrl":"https://doi.org/10.2118/191154-MS","url":null,"abstract":"\u0000 Sand-slug fracturing has been the main fracturing pumping mode due to the tightness of shale. This mode makes it easier to inject proppants. However, it may cause poor connectivity in the middle brittle formation due to the discontinuous propping. This paper describes an attempt to fracture the unconventional shales with conventional sand-ramp fracturing pumping mode. The results show that good effect is achieved compared with the sand-slug fracturing mode used in the adjacent wells.\u0000 Shale reservoir reconstruction has large construction displacement and high pressure, and it adopts fracturing technology of slickwater and linear glue1. In other blocks, Sand-slug mode causes large amounts of slickwater injecting into the formation. The role of water, in addition to carrying sand and making seams, will also cause \"water lock\" in the micro-fissure, reducing the gas permeability. Therefore, the large amount of liquid is not good to the reservoir.\u0000 The Sand-ramp modes using less fluid and higher sand content2-3, resulting in a greater height and length of the fractures. By using a small amount of proppant, Sand-ramp mode can also achieve high conductivity4, communicating the natural cracks5-7 at the same time. Two wells were designed for Sand-ramp mode in the test area.\u0000 Based on the understandings on geological characteristics and formation property, the sand-ramp fracturing pumping mode was designed. Two of six wells in the pad were selected to apply this mode. To maximize the stimulated reservoir volume, slickwater accounted for 40% to 60% of the total injected fluids. 100-mesh quartz sands were pumped in priority to improve the complexity of fracture. Then, the 40-70 mesh ceramsites was pumped with crosslinked gel to support the primary, secondary and natural fractures. The pumping rate is 12-13 cubic meters per minute and no acid is used throughout the whole pumping process.\u0000 The maximum proppant concentration of sand-ramp reached to 480 kilogram per cubic meters, which was much higher than that of sand-slugs. As a result, good propped fractures were obtained. Since no fluid sweep was used after the sand-slug, the average fluid injection per stage is declined by 27%, but the average sand injection volume was increased by 17%, which significantly reduced the cost and the possible influence to environment. With the sand-ramp mode, the highest test production of the block was up to 278500 cubic meters per day. This well produced 35 million cubic meters of shale gas in 270 days.\u0000 The practicability of the sand-ramp pumping mode used in unconventional shales is proven to be positive, especially in the formation with high horizontal stress difference. However, the development result needs to be continuously studied.","PeriodicalId":11006,"journal":{"name":"Day 3 Wed, June 27, 2018","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88909910","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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