B. Kayode, O. Meza, Nerio Quintero, Shaikha J Aldossary
Geo-modelling is usually done to honor static data such as core, well logs and seismic acoustic impedance (AI) map where available. Once the static geo-model is complete, history matching is carried out by tuning the static model properties until the model reproduces observed dynamic behavior. The objective of this paper is to showcase how a systematic a priori integration of dynamic elements into geo-modelling eliminated the need for history matching. These dynamic elements are; connected reservoir regions CRR (Kayode et.al 2018) and permeability-thickness (kh) interpretation from Pressure Transient Analysis PTA. This paper also introduces the concept of CRR based permeability modeling. CRRs were defined based on time-lapse shut-in pressure trend groups. Core and log data were grouped on the basis of the identified CRR and used to build CRR-based Neural Network models for predicting permeability logs of non-cored wells within each CRR. The geo-modeler then created two geo-realizations by using the permeability logs within each CRR to distribute permeability within the CRR using two assumptions of variogram lengths (i) variogram range obtained from analysis of limited core data, (ii) variogram range required to ensure intra-CRR connectivity. Pressure transient was simulated for wells with observed PTA data using the two realizations, and a comparison of the log-log plots of simulated pressure transient derivative and observed pressure transient derivative were used to determine the quality of each realization for each well. The realization that provided the least squares of error across all the wells was selected as base-case geo-model. Permeability correction coefficients were applied on the base-case geo-model until PTA kh were acceptably matched. The resulting permeability log at the PTA well is referred to as PTA-corrected permeability log. Some cored wells were originally exempted from the neural-network permeability modelling because they didn't have logs (sonic, density and neutron logs). Hybrid permeability logs were derived from a combination of the predicted permeability logs and core permeability at these well locations. All permeability correction logs (i) PTA-corrected permeability logs and (ii) Hybrid permeability logs were then fed back into the geo-modeling workflow to generate an improved permeability distribution which respects core data, PTA kh, and CRRs. The do-nothing simulation run has more than 80% of wells’ pressure data acceptably history matched. This application demonstrates that a priori integration of dynamic elements like CRR, PTA kh, and the use of CCR-based permeability modeling results in a better characterized geo-model with potential for eliminating the need for history matching.
{"title":"Forward Integration of Dynamic Data into 3-D Static Modeling Significantly Improves Reservoir Characterization","authors":"B. Kayode, O. Meza, Nerio Quintero, Shaikha J Aldossary","doi":"10.2523/IPTC-19183-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19183-MS","url":null,"abstract":"\u0000 Geo-modelling is usually done to honor static data such as core, well logs and seismic acoustic impedance (AI) map where available. Once the static geo-model is complete, history matching is carried out by tuning the static model properties until the model reproduces observed dynamic behavior. The objective of this paper is to showcase how a systematic a priori integration of dynamic elements into geo-modelling eliminated the need for history matching. These dynamic elements are; connected reservoir regions CRR (Kayode et.al 2018) and permeability-thickness (kh) interpretation from Pressure Transient Analysis PTA. This paper also introduces the concept of CRR based permeability modeling.\u0000 CRRs were defined based on time-lapse shut-in pressure trend groups. Core and log data were grouped on the basis of the identified CRR and used to build CRR-based Neural Network models for predicting permeability logs of non-cored wells within each CRR. The geo-modeler then created two geo-realizations by using the permeability logs within each CRR to distribute permeability within the CRR using two assumptions of variogram lengths (i) variogram range obtained from analysis of limited core data, (ii) variogram range required to ensure intra-CRR connectivity. Pressure transient was simulated for wells with observed PTA data using the two realizations, and a comparison of the log-log plots of simulated pressure transient derivative and observed pressure transient derivative were used to determine the quality of each realization for each well. The realization that provided the least squares of error across all the wells was selected as base-case geo-model. Permeability correction coefficients were applied on the base-case geo-model until PTA kh were acceptably matched. The resulting permeability log at the PTA well is referred to as PTA-corrected permeability log. Some cored wells were originally exempted from the neural-network permeability modelling because they didn't have logs (sonic, density and neutron logs). Hybrid permeability logs were derived from a combination of the predicted permeability logs and core permeability at these well locations.\u0000 All permeability correction logs (i) PTA-corrected permeability logs and (ii) Hybrid permeability logs were then fed back into the geo-modeling workflow to generate an improved permeability distribution which respects core data, PTA kh, and CRRs.\u0000 The do-nothing simulation run has more than 80% of wells’ pressure data acceptably history matched. This application demonstrates that a priori integration of dynamic elements like CRR, PTA kh, and the use of CCR-based permeability modeling results in a better characterized geo-model with potential for eliminating the need for history matching.","PeriodicalId":11267,"journal":{"name":"Day 3 Thu, March 28, 2019","volume":"5 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88878468","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}
Characterization, testing and evaluation of LCM products are very important for successful treatment of loss circulation problems. However, due to the lack of suitable API and any other industry methods and test apparatus that are applicable for characterization, testing and evaluation of various LCM products, the industry are facing difficulties in comprehensive characterization, testing and evaluation of LCM products. Hence, the industry needs fit-for-purpose methods and devices to fill up the industry gaps and overcome the technical limitations of current measurement systems. This paper describes several new methods and test devices for comprehensive characterization and evaluation of the stiffness characteristics of gel-based LCMs, attrition resistance of particulate LCM products, physical simulation and evaluation of sealing and blocking efficiency in fractured, super-K and vugular loss zones containing converging, diverging and parallel front fracture profiles. Experimental results provided by the characterization tools and various loss zone simulating test set up indicate the suitability of these tools and the apparatus in predicting the LCM Characteristics along with the sealing and plugging efficiency. Due to better simulation of various loss zone characteristic features, the newly developed test apparatus and the methods provide reliable technical guidelines to improve the probability and likelihood of success a LCM treatment job. The simple, easy to operate, reliable tools and methods described in this paper will help in overcoming the difficulties and limitations of testing and evaluation of LCM products to select the superior and reject the inferior.
{"title":"Novel Methods and Test Fixtures for Comprehensive Evaluation and Characterization of LCM Products","authors":"Amanullah, R. Alouhali, Mohammed K. Arfaj","doi":"10.2523/IPTC-19428-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19428-MS","url":null,"abstract":"Characterization, testing and evaluation of LCM products are very important for successful treatment of loss circulation problems. However, due to the lack of suitable API and any other industry methods and test apparatus that are applicable for characterization, testing and evaluation of various LCM products, the industry are facing difficulties in comprehensive characterization, testing and evaluation of LCM products. Hence, the industry needs fit-for-purpose methods and devices to fill up the industry gaps and overcome the technical limitations of current measurement systems. This paper describes several new methods and test devices for comprehensive characterization and evaluation of the stiffness characteristics of gel-based LCMs, attrition resistance of particulate LCM products, physical simulation and evaluation of sealing and blocking efficiency in fractured, super-K and vugular loss zones containing converging, diverging and parallel front fracture profiles. Experimental results provided by the characterization tools and various loss zone simulating test set up indicate the suitability of these tools and the apparatus in predicting the LCM Characteristics along with the sealing and plugging efficiency. Due to better simulation of various loss zone characteristic features, the newly developed test apparatus and the methods provide reliable technical guidelines to improve the probability and likelihood of success a LCM treatment job. The simple, easy to operate, reliable tools and methods described in this paper will help in overcoming the difficulties and limitations of testing and evaluation of LCM products to select the superior and reject the inferior.","PeriodicalId":11267,"journal":{"name":"Day 3 Thu, March 28, 2019","volume":"2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77985082","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}
Lunar field is a marginal gas field located in the Gulf of Thailand. A significant portion of reservoir sands is currently categorized as Additional Zones of Interest (AZI) which is not accounted in reserves. As for this kind of sand, the conventional petrophysical evaluation alone cannot certainly distinguish between hydrocarbon and water in the porous medium. The alternative method (dT LogR) for formation re-evaluation is therefore considered in attempt to reduce uncertainty in fluid classification and reveal hidden hydrocarbon potential from these AZIs. There are 2 phases in verifying the validity of dT LogR method. Phase I: dT logR method (Ref. Q.R. Passey et al., AAPG 1990) was tested against the unperforated AZI sands of 10 selected platforms in order to fine-tune scaling parameters in dT logR. The total of 12 gas-potential AZI candidates were selected for perforation test. Data acquisition was also planned to obtain the reservoir deliverability information in order to further calibrate the interpretation model. The production test results of these sands showed that the accuracy of the interpretation was 41% (5 sands of 12 candidates produced gas) but 33% (4 sands of 12 candidates) showed water flow. Phase II: The production test data from perforated AZIs in phase I and the well correlation were then incorporated in dT LogR assisted log reinterpretation. Additional 13 gas-potential AZI candidates were identified for 2nd perforation test to prove the correctness of the recalibrated petrophysical model. The results showed success in model improvement of which its accuracy increased to 61% and no high water production was observed in any of them. After using dT LogR method to assist petrophysical evaluation, a total of 469 metres of unperforated AZIs were reconsidered to be productive gas bearing formation. In other words, 22 BCF of gas reserves and 873 MSTB of condensate reserves from these upgraded AZIs were added. In addition, it is foreseen that the remaining AZIs of other platforms are to be further reevaluated and therefore improves the confidence in reserves booking and field development planning of Lunar Field. In conclusion, the dT LogR method is a very useful tool for Lunar Field to significantly reduce uncertainty of fluid classification which in turn provides lots of benefits in gas field management adding immeasurable value to Lunar Field.
{"title":"Disclose Hidden Hydrocarbon HC Reserves from Additional Zone of Interest AZIs Using dT LogR Method in Lunar Field, Gulf of Thailand","authors":"Paphitchaya Kamkong, Thamaporn Karnjanamuntana, Weera Prungkwanmuang, Jakkrich Yingyuen, Dejasarn Oatwaree, Nichakorn Amornpiyapong, Patcharin Khositchaisri, V. Tivayanonda, Dutkamon Wongsuvapich, Soraya Tongsuk","doi":"10.2523/IPTC-19129-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19129-MS","url":null,"abstract":"\u0000 Lunar field is a marginal gas field located in the Gulf of Thailand. A significant portion of reservoir sands is currently categorized as Additional Zones of Interest (AZI) which is not accounted in reserves. As for this kind of sand, the conventional petrophysical evaluation alone cannot certainly distinguish between hydrocarbon and water in the porous medium. The alternative method (dT LogR) for formation re-evaluation is therefore considered in attempt to reduce uncertainty in fluid classification and reveal hidden hydrocarbon potential from these AZIs.\u0000 There are 2 phases in verifying the validity of dT LogR method. Phase I: dT logR method (Ref. Q.R. Passey et al., AAPG 1990) was tested against the unperforated AZI sands of 10 selected platforms in order to fine-tune scaling parameters in dT logR. The total of 12 gas-potential AZI candidates were selected for perforation test. Data acquisition was also planned to obtain the reservoir deliverability information in order to further calibrate the interpretation model. The production test results of these sands showed that the accuracy of the interpretation was 41% (5 sands of 12 candidates produced gas) but 33% (4 sands of 12 candidates) showed water flow.\u0000 Phase II: The production test data from perforated AZIs in phase I and the well correlation were then incorporated in dT LogR assisted log reinterpretation. Additional 13 gas-potential AZI candidates were identified for 2nd perforation test to prove the correctness of the recalibrated petrophysical model. The results showed success in model improvement of which its accuracy increased to 61% and no high water production was observed in any of them.\u0000 After using dT LogR method to assist petrophysical evaluation, a total of 469 metres of unperforated AZIs were reconsidered to be productive gas bearing formation. In other words, 22 BCF of gas reserves and 873 MSTB of condensate reserves from these upgraded AZIs were added. In addition, it is foreseen that the remaining AZIs of other platforms are to be further reevaluated and therefore improves the confidence in reserves booking and field development planning of Lunar Field.\u0000 In conclusion, the dT LogR method is a very useful tool for Lunar Field to significantly reduce uncertainty of fluid classification which in turn provides lots of benefits in gas field management adding immeasurable value to Lunar Field.","PeriodicalId":11267,"journal":{"name":"Day 3 Thu, March 28, 2019","volume":"45 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74394233","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 permeability along a fracture is not constant, but varies with geometrical complexities such as pre-existing cracks. The spatial permeability changes affecting fluid pressure distributions can generate a sophisticated source mechanism potential to interpret measured seismicity complexity in the field. In this study, the relation between injection-induced seismicity and changes in fracture permeability during hydraulic fracturing stimulation of naturally fractured reservoirs is investigated numerically. In the model, the infinite homogeneous rock is assumed to be impermeable and elastic and a plane-strain fracture is embedded in it with distributed cracks. The fluid flow in the fracture is realized through over pressure generated by constant-rate injection. When the over-pressurized fluid enters these cracks, the pressure varying trend is changed and the injection pressure tends to increase, rather than decrease monotonically. Also, the slipping is temporarily stopped along the whole fracture. When the barrier to fluid flow is overcome, a most prominent pulse-type slip at a limited slip speed occurs along the pressurized region. The slip pulse can induce an injection pressure drop reflecting the decrease of the stress level near the rupture tip. In the meantime, the slip pulse acts as the source mechanisms for these microseismic events during the fracturing stimulation operations. It is found that the stress drop and slip rate decrease with rupture growth. In addition, the stopping phase and the accelerating duration of the slip patterns are two interesting features to estimate the source sizes of the rupture complexities generated by the forced fluid flow along a fracture.
{"title":"Linking Injection-Induced Seismicity to Permeability Changes","authors":"Xi Zhang, Fengshou Zhang, Shize Wang","doi":"10.2523/IPTC-19338-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19338-MS","url":null,"abstract":"\u0000 The permeability along a fracture is not constant, but varies with geometrical complexities such as pre-existing cracks. The spatial permeability changes affecting fluid pressure distributions can generate a sophisticated source mechanism potential to interpret measured seismicity complexity in the field. In this study, the relation between injection-induced seismicity and changes in fracture permeability during hydraulic fracturing stimulation of naturally fractured reservoirs is investigated numerically. In the model, the infinite homogeneous rock is assumed to be impermeable and elastic and a plane-strain fracture is embedded in it with distributed cracks. The fluid flow in the fracture is realized through over pressure generated by constant-rate injection. When the over-pressurized fluid enters these cracks, the pressure varying trend is changed and the injection pressure tends to increase, rather than decrease monotonically. Also, the slipping is temporarily stopped along the whole fracture. When the barrier to fluid flow is overcome, a most prominent pulse-type slip at a limited slip speed occurs along the pressurized region. The slip pulse can induce an injection pressure drop reflecting the decrease of the stress level near the rupture tip. In the meantime, the slip pulse acts as the source mechanisms for these microseismic events during the fracturing stimulation operations. It is found that the stress drop and slip rate decrease with rupture growth. In addition, the stopping phase and the accelerating duration of the slip patterns are two interesting features to estimate the source sizes of the rupture complexities generated by the forced fluid flow along a fracture.","PeriodicalId":11267,"journal":{"name":"Day 3 Thu, March 28, 2019","volume":"31 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83151074","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. Baumann, D. Damm, J. Escudero, M. Smart, Xiang Tong Yang, Jun Yan Liu, Zhang Wei
Many high-pressure/high-temperature (HP/HT) gas fields are developed in Northeast China with wells that have pressures reaching 20,000 psi and temperatures up to 180°C. The main difficulty in perforating these wells is the high wellbore pressure, which leads to large gunshock loads when the guns fire. Field operators experienced substantial losses when perforating these HP wells with standard guns; therefore, they needed to minimize the risk of equipment damage due to gunshock and reduce the amount of perforating debris left in the well. To reduce gunshock loads and perforating debris problems, a new low perforating shock and debris (LPSD) gun system was developed specifically for HP/HT wells. Compared with standard guns, LPSD guns produce much less gunshock and negligible amounts of debris; thus, by using LPSD guns operators can minimize gunshock risk and save on cleanup runs. LPSD guns leave almost no debris in the well because LPSD guns retain all the metallic components inside the gun carriers, including the shaped charge cases, which remain virtually intact inside the guns. Complementing the new LPSD gun technology, we use gunshock simulation for shock load reduction and optimization. These are key elements of the perforating job design, and they are critical to prevent equipment damage in HP wells. We show several examples of tool damage resulting from gunshock loads when third-party guns were used. These gunshock problems represented costly losses from equipment damage and nonproductive time. Using gunshock simulation, we show the origin of shock loads and the magnitude of the loads acting on the equipment, resulting in collapsed casing, corkscrewed tubing, and damage to packer mandrels and seals. We compared the performance of LPSD with standard guns under the same perforating conditions, demonstrating that LPSD guns can reduce shock loads significantly, making LPSD guns better suited for all HP wells, including those in Northeast China. The LPSD gun system developed for HP wells significantly reduces the amplitude of the transient pressure waves and associated gunshock loads, and totally reduces the amount of debris. The reduction of gunshock enables perforating wells that otherwise cannot be safely and reliably perforated with standard equipment.
{"title":"New Low-Shock Low-Debris Gun Technology with Reliable Gunshock Simulation and Optimization","authors":"C. Baumann, D. Damm, J. Escudero, M. Smart, Xiang Tong Yang, Jun Yan Liu, Zhang Wei","doi":"10.2523/IPTC-19376-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19376-MS","url":null,"abstract":"\u0000 Many high-pressure/high-temperature (HP/HT) gas fields are developed in Northeast China with wells that have pressures reaching 20,000 psi and temperatures up to 180°C. The main difficulty in perforating these wells is the high wellbore pressure, which leads to large gunshock loads when the guns fire. Field operators experienced substantial losses when perforating these HP wells with standard guns; therefore, they needed to minimize the risk of equipment damage due to gunshock and reduce the amount of perforating debris left in the well.\u0000 To reduce gunshock loads and perforating debris problems, a new low perforating shock and debris (LPSD) gun system was developed specifically for HP/HT wells. Compared with standard guns, LPSD guns produce much less gunshock and negligible amounts of debris; thus, by using LPSD guns operators can minimize gunshock risk and save on cleanup runs. LPSD guns leave almost no debris in the well because LPSD guns retain all the metallic components inside the gun carriers, including the shaped charge cases, which remain virtually intact inside the guns. Complementing the new LPSD gun technology, we use gunshock simulation for shock load reduction and optimization. These are key elements of the perforating job design, and they are critical to prevent equipment damage in HP wells.\u0000 We show several examples of tool damage resulting from gunshock loads when third-party guns were used. These gunshock problems represented costly losses from equipment damage and nonproductive time. Using gunshock simulation, we show the origin of shock loads and the magnitude of the loads acting on the equipment, resulting in collapsed casing, corkscrewed tubing, and damage to packer mandrels and seals. We compared the performance of LPSD with standard guns under the same perforating conditions, demonstrating that LPSD guns can reduce shock loads significantly, making LPSD guns better suited for all HP wells, including those in Northeast China.\u0000 The LPSD gun system developed for HP wells significantly reduces the amplitude of the transient pressure waves and associated gunshock loads, and totally reduces the amount of debris. The reduction of gunshock enables perforating wells that otherwise cannot be safely and reliably perforated with standard equipment.","PeriodicalId":11267,"journal":{"name":"Day 3 Thu, March 28, 2019","volume":"68 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84062683","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}
China has abundant low-rank coalbed methane resources. The research object is the low rank lignite seams in Jiergalangtu Sag in Erlian Basin. The reservoir has low porosity and low permeability, and it has no natural productivity. The coal seams have a burial depth of 200-600 meters, thickness of 40-60 meters, and Ro of 0.32% to 0.47%. Borrowing the idea of well completion experience for the conventional low rank coal seams in the region, open hole cavity completion techniques were adopted in two wells, obtaining an output of only about 150 m3/d. The conventional active water fracturing was also tested in another well, and the output after fracturing was 200-300 m3/d. The effect of stimulation was very poor, which limited commercial exploitation activities in the region. This paper introduces two techniques to improve the effect of stimulation by improving induced fracture extension and supporting capacity in the coal seams, including the hydraulic blasting & grouting caving fracturing technique and the reverse compound fracturing technique, which were applied in two wells. A constant rate of production after fracturing reached 1,500-2,000m3/d, which was well above the lower limit output of economic exploitation in the region of 600m3/d. Exciting results were obtained. The exploration of these techniques is of great significance for low rank coalbed methane stimulation, which can help us to implement effective fracturing stimulation operation in low rank coal seams to obtain the best production effect.
{"title":"Improving the Effective Supporting and Fracturing Technology is the Key to the Successful Stimulation of Low-Permeability and Low-Rank Coalbed Methane Reservoirs","authors":"Xin Wang, Qingzhong Zhu, Wei Zheng, H. Lu","doi":"10.2523/IPTC-19203-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19203-MS","url":null,"abstract":"\u0000 China has abundant low-rank coalbed methane resources. The research object is the low rank lignite seams in Jiergalangtu Sag in Erlian Basin. The reservoir has low porosity and low permeability, and it has no natural productivity. The coal seams have a burial depth of 200-600 meters, thickness of 40-60 meters, and Ro of 0.32% to 0.47%. Borrowing the idea of well completion experience for the conventional low rank coal seams in the region, open hole cavity completion techniques were adopted in two wells, obtaining an output of only about 150 m3/d. The conventional active water fracturing was also tested in another well, and the output after fracturing was 200-300 m3/d. The effect of stimulation was very poor, which limited commercial exploitation activities in the region. This paper introduces two techniques to improve the effect of stimulation by improving induced fracture extension and supporting capacity in the coal seams, including the hydraulic blasting & grouting caving fracturing technique and the reverse compound fracturing technique, which were applied in two wells. A constant rate of production after fracturing reached 1,500-2,000m3/d, which was well above the lower limit output of economic exploitation in the region of 600m3/d. Exciting results were obtained. The exploration of these techniques is of great significance for low rank coalbed methane stimulation, which can help us to implement effective fracturing stimulation operation in low rank coal seams to obtain the best production effect.","PeriodicalId":11267,"journal":{"name":"Day 3 Thu, March 28, 2019","volume":"44 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82683267","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}
Scott Paul, Aldrick Garcia Mayans, N. Patel, M. Blyth, A. Rodrigues
The basic objective of real-time pore pressure (RTPP) services is to maintain the equivalent static density (ESD) and equivalent circulating density (ECD) within a desired mud weight (MW) window. This paper will present a new workflow to differentiate between supercharging in low-permeability, limited lateral extent sands, and genuine elevated pore pressure; ultimately preventing unwarranted MW increases that might either result in premature termination of the section or induce losses. In a typical workflow, log-derived models are used to compute the pore pressure (PP) in shales. These models are calibrated with drilling events and prompt formation pressure-while-drilling (FPWD) pretests in sands. However, in the Gulf of Mexico (GoM), sub seismic sand lenses are susceptible to supercharging; sometimes manifesting as an event gas peak. Moreover, using these gas events to determine supercharging have proven unreliable as they do not systematically occur. A novel workflow using time-lapse FPWD measurements, incorporating the acquisition environment, and the ability to circulate drilling mud at different flowrates to iteratively demonstrate the presence of supercharging has been developed. A common scenario is presented from a deep water well in the GoM in which both RTPP and FPWD services were run. As drilling progressed, the shale PP computed from the sonic logging-while-drilling tool was repeatedly validated with FPWD measurements. However, then a pretest conducted across an underlying sand showed PP value slightly higher than the computed shale PP. Based on conventional methodology, this condition would trigger a MW increase. Following regulatory requirements, ESD should be in a specified range above the confirmed PP. If the MW was increased further, the resulting ECD would be near the last casing shoe leak off test value, compromising wellbore integrity. If the flow rate was reduced to control the ECD, then wellbore cleaning would be compromised. A departure from the previously observed sand-shale PP equilibrium was unexpected and supercharging was suspected in this underlying sand. Clear evidence of supercharging was demonstrated by employing an iterative sequence of four repeated pretests with parameter adjustments. Experimental data were obtained and showed that no MW increase was required. Based on these results, the RTPP model was adjusted accordingly, and drilling continued without any problems to the planned section total depth. The presence of potentially supercharged sub seismic sand lenses complicates PP calibration. This new workflow is proposed to identify supercharging in these sands; thus, minimizing unwarranted MW increases, which could either result in premature termination of the section or induce losses. Either of these results could lead to operation cost overruns and extra casing and liner runs. The efficiency of the new workflow is demonstrated by the safe and successful drilling of a Deepwater prospect.
{"title":"Real-Time Interpretation of Supercharged Formations during Pore Pressure Monitoring","authors":"Scott Paul, Aldrick Garcia Mayans, N. Patel, M. Blyth, A. Rodrigues","doi":"10.2523/IPTC-19124-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19124-MS","url":null,"abstract":"\u0000 The basic objective of real-time pore pressure (RTPP) services is to maintain the equivalent static density (ESD) and equivalent circulating density (ECD) within a desired mud weight (MW) window. This paper will present a new workflow to differentiate between supercharging in low-permeability, limited lateral extent sands, and genuine elevated pore pressure; ultimately preventing unwarranted MW increases that might either result in premature termination of the section or induce losses.\u0000 In a typical workflow, log-derived models are used to compute the pore pressure (PP) in shales. These models are calibrated with drilling events and prompt formation pressure-while-drilling (FPWD) pretests in sands. However, in the Gulf of Mexico (GoM), sub seismic sand lenses are susceptible to supercharging; sometimes manifesting as an event gas peak. Moreover, using these gas events to determine supercharging have proven unreliable as they do not systematically occur. A novel workflow using time-lapse FPWD measurements, incorporating the acquisition environment, and the ability to circulate drilling mud at different flowrates to iteratively demonstrate the presence of supercharging has been developed.\u0000 A common scenario is presented from a deep water well in the GoM in which both RTPP and FPWD services were run. As drilling progressed, the shale PP computed from the sonic logging-while-drilling tool was repeatedly validated with FPWD measurements. However, then a pretest conducted across an underlying sand showed PP value slightly higher than the computed shale PP. Based on conventional methodology, this condition would trigger a MW increase. Following regulatory requirements, ESD should be in a specified range above the confirmed PP. If the MW was increased further, the resulting ECD would be near the last casing shoe leak off test value, compromising wellbore integrity. If the flow rate was reduced to control the ECD, then wellbore cleaning would be compromised. A departure from the previously observed sand-shale PP equilibrium was unexpected and supercharging was suspected in this underlying sand. Clear evidence of supercharging was demonstrated by employing an iterative sequence of four repeated pretests with parameter adjustments. Experimental data were obtained and showed that no MW increase was required. Based on these results, the RTPP model was adjusted accordingly, and drilling continued without any problems to the planned section total depth.\u0000 The presence of potentially supercharged sub seismic sand lenses complicates PP calibration. This new workflow is proposed to identify supercharging in these sands; thus, minimizing unwarranted MW increases, which could either result in premature termination of the section or induce losses. Either of these results could lead to operation cost overruns and extra casing and liner runs. The efficiency of the new workflow is demonstrated by the safe and successful drilling of a Deepwater prospect.","PeriodicalId":11267,"journal":{"name":"Day 3 Thu, March 28, 2019","volume":"71 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76770479","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}
Muhammad Abdulhadi, Pei Tze Kueh, Shahrizal Abdul Aziz, Najmi Mansor, T. Tran, H. Chin, S. Jacobs, I. M. Fadhil, Alister Albert Suggust, M. Z. Usop, B. Ralphie, Khairul Arifin Dolah, K. Abdussalam, Hasim Munandai, Zainuddin Yusop
It is a common practice to run a contact-saturation log to confirm the oil column prior to oil gain activities such as adding perforations or infill drilling. From 2012 to 2017, a total of eight logging jobs were executed in Field B which were subsequently followed by oil gain activities. The eight contact-saturation logging jobs were comprised of pulse-neutron logs in both carbon-oxygen (C/O) and sigma mode. The logs were run in varied well completions targeting thirteen different zones. Four logs were run in single tubing strings while the remaining four were in dual string completions. Certain target zones were already perforated while others had completion accessories such as a blast joint or integrated tubing-conveyed perforating (iTCP) guns across them. Eight of the target zones were later add-perforated while two were used to mature infill well targets. Four of the seven add-perforations results were consistent with the logging results. One of the successful logs clearly indicated that the oil column had migrated into the original gas cap. Of the two infill wells drilled, only one was successful. These case studies in Field B indicate that in conditions of open perforations, trapped fluid across the annulus, and in low resistivity sand, distinguishing between original and residual saturation is difficult with pulse-neutron log. The log measurement was significantly affected. The most obvious lesson learned was that perforating and producing the reservoir would be the best method to confirm the potential oil gain. From a value point of view, it would have been more economical to perforate the zone straightaway if the oil gain activity had similar cost to the logging activity. The lessons learned also helped to establish clear guidelines in Field B on utilizing contact-saturation logs in the future. The paper seeks to present the logging results, subsequent oil gain activities, and lessons learned from the contact-saturation logging in Field B. These lessons learned will be applicable in other oilfields with similar conditions to improve decision making in the industry.
{"title":"Additional-Perforations and Infill Wells Based on Multiple Contacts & Saturation Logging Results: A Case Study","authors":"Muhammad Abdulhadi, Pei Tze Kueh, Shahrizal Abdul Aziz, Najmi Mansor, T. Tran, H. Chin, S. Jacobs, I. M. Fadhil, Alister Albert Suggust, M. Z. Usop, B. Ralphie, Khairul Arifin Dolah, K. Abdussalam, Hasim Munandai, Zainuddin Yusop","doi":"10.2523/IPTC-19520-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19520-MS","url":null,"abstract":"\u0000 It is a common practice to run a contact-saturation log to confirm the oil column prior to oil gain activities such as adding perforations or infill drilling. From 2012 to 2017, a total of eight logging jobs were executed in Field B which were subsequently followed by oil gain activities.\u0000 The eight contact-saturation logging jobs were comprised of pulse-neutron logs in both carbon-oxygen (C/O) and sigma mode. The logs were run in varied well completions targeting thirteen different zones. Four logs were run in single tubing strings while the remaining four were in dual string completions. Certain target zones were already perforated while others had completion accessories such as a blast joint or integrated tubing-conveyed perforating (iTCP) guns across them. Eight of the target zones were later add-perforated while two were used to mature infill well targets.\u0000 Four of the seven add-perforations results were consistent with the logging results. One of the successful logs clearly indicated that the oil column had migrated into the original gas cap. Of the two infill wells drilled, only one was successful. These case studies in Field B indicate that in conditions of open perforations, trapped fluid across the annulus, and in low resistivity sand, distinguishing between original and residual saturation is difficult with pulse-neutron log. The log measurement was significantly affected. The most obvious lesson learned was that perforating and producing the reservoir would be the best method to confirm the potential oil gain. From a value point of view, it would have been more economical to perforate the zone straightaway if the oil gain activity had similar cost to the logging activity. The lessons learned also helped to establish clear guidelines in Field B on utilizing contact-saturation logs in the future.\u0000 The paper seeks to present the logging results, subsequent oil gain activities, and lessons learned from the contact-saturation logging in Field B. These lessons learned will be applicable in other oilfields with similar conditions to improve decision making in the industry.","PeriodicalId":11267,"journal":{"name":"Day 3 Thu, March 28, 2019","volume":"14 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84641591","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}
Building realistic and reliable subsurface models requires detailed knowledge of both the rock and fluids involved. While the hydrocarbon volume estimation has a profound impact on the viability of a development, next to the saturation height models and free fluid levels the hydraulic communication and permeability have a significant role as well. Compartmentalization could change the field development plan: e.g. increase the well count, necessitate significant change to the well profiles (e.g. extended range drilling), require complex and expensive completion strategy. When in different parts of the same field different free fluid levels are identified, leading to different fluid contacts for the same rock quality, the lateral hydraulic communication at the field level can be challenged. This aspect is of importance since the hydrocarbon volume distribution has drastic impact on total hydrocarbon recovery. At the same time building and initializing a model based on different free water level positions across the field, zero capillary pressure, is challenging. Perched water contacts are the result of water entrapment during the hydrocarbon migration that could lead to variability in free fluid levels across a field. The fundamental controls that lead to the perched contacts formation are studied and shown to be the rock quality and relative permeability. Counter-intuitively, the perching effect is not going to feature in poor quality rocks with sub-milli Darcy permeability – the effects would be visible only for a considerable barrier height, with Free Water Level to barrier height of tensto hundred meters. In addition, realistic heterogeneous models are studied to investigate the heterogeneity effect on perching and on formation pressures. Whilst low permeability is correlated to a wide range of depths where two phases are mobile, the perching controls in high permeability contrast formations are studied. Using a dynamic modelling route, potential water entrapment occurrence as a result of high permeability contrast is shown, without structural control, i.e. an underlying impermeably zone defining a trap. The main control in such a case is water permeability just as in structurally controlled perching. This work challenges the industry view that model initialization should be performed with buoyancy as an equilibrium driving mechanism. Such a saturation modelling route would lead to discrepancies when compared to using the capillary pressure as a direct input instead of buoyancy.
{"title":"Heterogeneity and Relative Permeability Role in Primary Drainage: from Lateral to Vertical Perching","authors":"I. Hulea, Igor Kim","doi":"10.2523/IPTC-19507-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19507-MS","url":null,"abstract":"\u0000 Building realistic and reliable subsurface models requires detailed knowledge of both the rock and fluids involved. While the hydrocarbon volume estimation has a profound impact on the viability of a development, next to the saturation height models and free fluid levels the hydraulic communication and permeability have a significant role as well. Compartmentalization could change the field development plan: e.g. increase the well count, necessitate significant change to the well profiles (e.g. extended range drilling), require complex and expensive completion strategy.\u0000 When in different parts of the same field different free fluid levels are identified, leading to different fluid contacts for the same rock quality, the lateral hydraulic communication at the field level can be challenged. This aspect is of importance since the hydrocarbon volume distribution has drastic impact on total hydrocarbon recovery. At the same time building and initializing a model based on different free water level positions across the field, zero capillary pressure, is challenging.\u0000 Perched water contacts are the result of water entrapment during the hydrocarbon migration that could lead to variability in free fluid levels across a field. The fundamental controls that lead to the perched contacts formation are studied and shown to be the rock quality and relative permeability. Counter-intuitively, the perching effect is not going to feature in poor quality rocks with sub-milli Darcy permeability – the effects would be visible only for a considerable barrier height, with Free Water Level to barrier height of tensto hundred meters.\u0000 In addition, realistic heterogeneous models are studied to investigate the heterogeneity effect on perching and on formation pressures. Whilst low permeability is correlated to a wide range of depths where two phases are mobile, the perching controls in high permeability contrast formations are studied.\u0000 Using a dynamic modelling route, potential water entrapment occurrence as a result of high permeability contrast is shown, without structural control, i.e. an underlying impermeably zone defining a trap. The main control in such a case is water permeability just as in structurally controlled perching. This work challenges the industry view that model initialization should be performed with buoyancy as an equilibrium driving mechanism. Such a saturation modelling route would lead to discrepancies when compared to using the capillary pressure as a direct input instead of buoyancy.","PeriodicalId":11267,"journal":{"name":"Day 3 Thu, March 28, 2019","volume":"38 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89474925","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}
Gaocheng Wang, Chunduan Zhao, Xing Liang, Yuanwei Pan, Li Lin, Lizhi Wang, Yun Rui, Qingshan Li
Huangjinba shale gas field is located at the south edge of the Sichuan Basin. It has very complex structures, in situ stresses and natural fracture corridors in comparison to adjacent areas in the Sichuan Basin. In recent drilling campaigns, drilling risks have caused some wells to fail in reaching their planned total depth, eventually failing to deliver cost-effective gas production. In order to mitigate drilling risks, e.g. mud loss, collapse, stuck, hang up, gas kick, effective drilling risk prediction is an urgent challenge to address. Integrating quantitative drilling risk prediction methods with qualitative methods could increase the prediction accuracy and avoid or mitigate the drilling risk during the well deployment stage. In this project, multiple seismic attributes were used to predict natural fracture distributions which qualitatively indicated the locations where drilling risks were likely occur. Comprehensive geophysical characterization was performed to identify natural fracture zones and patterns, and their mechanisms were validated by analyzing regional geological and tectonic evolution. Image log data was then integrated into the natural fracture distribution prediction from seismic to build a DFN (Discrete Fracture Network). This combination of the DFN predicted from seismic data plus quantitative image log information allowed improved accuracy in the prediction of drilling risks. Following this, natural fracture stability was analyzed by building a 3D geomechanics model in order to predict drilling complex qualitatively. A full field 3D geomechanics model was built through integrating seismic, geological structure, log and core data. The 3D geomechanical model includes 3D anisotropic mechanical properties, 3D pore pressure, and the 3D in-situ stress field. Through leveraging measurements from an advanced sonic tool and core data, the anisotropy of the formation was captured at wellbores and propagated to 3D space guided by prestack seismic inversion data. 3D pore pressure prediction was conducted using seismic data and calibrated against pressure measurements, mud logging data, and flowback data. The discrete fracture network model, which represented multi-scale natural fracture systems, was integrated into the 3D geomechanical model during stress modeling to reflect the disturbance on the in-situ stress field by the presence of the natural fracture systems. From these models, a drilling map which quantitatively indicated the depth where drilling risk such as mud loss, gas kick, etc. occurred was created along the well trajectory. This paper presents the highlights and innovations in seismic multi-attributes analysis and full-field geomechanics modeling which integrate qualitative and quantitative methods for drilling risk prediction.
{"title":"Integrating Qualitative and Quantitative Drilling Risk Prediction Methods for Shale Gas Field in Sichuan Basin","authors":"Gaocheng Wang, Chunduan Zhao, Xing Liang, Yuanwei Pan, Li Lin, Lizhi Wang, Yun Rui, Qingshan Li","doi":"10.2523/IPTC-19487-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19487-MS","url":null,"abstract":"\u0000 Huangjinba shale gas field is located at the south edge of the Sichuan Basin. It has very complex structures, in situ stresses and natural fracture corridors in comparison to adjacent areas in the Sichuan Basin. In recent drilling campaigns, drilling risks have caused some wells to fail in reaching their planned total depth, eventually failing to deliver cost-effective gas production. In order to mitigate drilling risks, e.g. mud loss, collapse, stuck, hang up, gas kick, effective drilling risk prediction is an urgent challenge to address. Integrating quantitative drilling risk prediction methods with qualitative methods could increase the prediction accuracy and avoid or mitigate the drilling risk during the well deployment stage.\u0000 In this project, multiple seismic attributes were used to predict natural fracture distributions which qualitatively indicated the locations where drilling risks were likely occur. Comprehensive geophysical characterization was performed to identify natural fracture zones and patterns, and their mechanisms were validated by analyzing regional geological and tectonic evolution.\u0000 Image log data was then integrated into the natural fracture distribution prediction from seismic to build a DFN (Discrete Fracture Network). This combination of the DFN predicted from seismic data plus quantitative image log information allowed improved accuracy in the prediction of drilling risks.\u0000 Following this, natural fracture stability was analyzed by building a 3D geomechanics model in order to predict drilling complex qualitatively. A full field 3D geomechanics model was built through integrating seismic, geological structure, log and core data. The 3D geomechanical model includes 3D anisotropic mechanical properties, 3D pore pressure, and the 3D in-situ stress field. Through leveraging measurements from an advanced sonic tool and core data, the anisotropy of the formation was captured at wellbores and propagated to 3D space guided by prestack seismic inversion data. 3D pore pressure prediction was conducted using seismic data and calibrated against pressure measurements, mud logging data, and flowback data. The discrete fracture network model, which represented multi-scale natural fracture systems, was integrated into the 3D geomechanical model during stress modeling to reflect the disturbance on the in-situ stress field by the presence of the natural fracture systems.\u0000 From these models, a drilling map which quantitatively indicated the depth where drilling risk such as mud loss, gas kick, etc. occurred was created along the well trajectory.\u0000 This paper presents the highlights and innovations in seismic multi-attributes analysis and full-field geomechanics modeling which integrate qualitative and quantitative methods for drilling risk prediction.","PeriodicalId":11267,"journal":{"name":"Day 3 Thu, March 28, 2019","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89525419","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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