H. Salimi, Maryam Namdar Zanganeh, Sven McCarthy, Lucian Pirlea, Jurriaan Nortier, D. Frigo, Haitham Balushi, M. Lawati, M. Yarabi
Souring potentials of fields during planned-/ongoing-waterflood development need to be investigated to enable the selection of the injection-water source and facility-design options. This paper presents the application of a novel reservoir-souring approach to assess the souring potential of two Middle-East fields (S and T), to recommend ways to prevent and/or reduce H2S production, and to determine the optimum solution for injection water. The novel approach includes fluid sampling and analysis, a desktop study, a dynamic-reservoir simulation, and a surface-facility evaluation. In the desktop study, a qualitative assessment of souring associated with injection-water sources (produced water and/or aquifer water) and reservoir characteristics and mitigation strategies to limit future H2S concentrations were carried out. Subsequently, a compositional non-isothermal dynamic model that includes 3 phases, 18 components, and 18 reactions was developed to quantitatively predict the most-likely and the worst-case H2S levels over the fields’ life. Several sensitivity runs were performed to assess the impact of the key uncertain parameters on the H2S level. The desktop study concluded that the produced H2S from field S has a non-microbial external source, which is likely to be derived from thermal cracking of organosulfur compounds at depth and migrated into the reservoir from the Huqf source rocks. This thermally-generated H2S is presented with an initial background H2S level in the formation water in the simulations. The Base-Case-Scenario results reveal that in the S field with the background H2S level (350 ppmv), the level of H2S increases to 1000 ppmv after injection-water breakthrough because of the addition water-induced microbial souring. In the T field without background H2S levels, the level of microbial H2S reaches 195 ppmv in year 2044 at a water cut of 95%. The results of the Worst-Case Scenarios indicate that if the VFA content is significantly underestimated and the abstraction capacity is overestimated in the Base-Case Scenarios, the risk of microbial souring would be high in the S and T fields when injecting low-salinity Fars-aquifer water. In the Worst-Case Scenarios, the gas-phase H2S concentration attains max values of 3,400 and 1,200 ppmv, respectively, for the S and T fields. Analysis of the microbial-souring mitigation options suggest that injecting the high-salinity produced-water re-injection (PWRI) at the station—being the most robust microbial-souring-prevention method available—is the best mitigation option in the T and S fields and its effectivity and efficiency are far superior to nitrate injection. In the Worst-Case Scenario, PWRI effectively hampers the generation and production of microbial H2S and maintains the H2S concentration in the produced gas around the background H2S level. Although PWRI is not an option for the S and T fields and there is no infrastructure in place for transferring the station-PWRI to the S a
{"title":"A Quantitative and Predictive Reservoir-Souring Approach to Assess Reservoir-Souring Risk During Waterflood Development","authors":"H. Salimi, Maryam Namdar Zanganeh, Sven McCarthy, Lucian Pirlea, Jurriaan Nortier, D. Frigo, Haitham Balushi, M. Lawati, M. Yarabi","doi":"10.2118/200087-ms","DOIUrl":"https://doi.org/10.2118/200087-ms","url":null,"abstract":"\u0000 Souring potentials of fields during planned-/ongoing-waterflood development need to be investigated to enable the selection of the injection-water source and facility-design options. This paper presents the application of a novel reservoir-souring approach to assess the souring potential of two Middle-East fields (S and T), to recommend ways to prevent and/or reduce H2S production, and to determine the optimum solution for injection water.\u0000 The novel approach includes fluid sampling and analysis, a desktop study, a dynamic-reservoir simulation, and a surface-facility evaluation. In the desktop study, a qualitative assessment of souring associated with injection-water sources (produced water and/or aquifer water) and reservoir characteristics and mitigation strategies to limit future H2S concentrations were carried out. Subsequently, a compositional non-isothermal dynamic model that includes 3 phases, 18 components, and 18 reactions was developed to quantitatively predict the most-likely and the worst-case H2S levels over the fields’ life. Several sensitivity runs were performed to assess the impact of the key uncertain parameters on the H2S level.\u0000 The desktop study concluded that the produced H2S from field S has a non-microbial external source, which is likely to be derived from thermal cracking of organosulfur compounds at depth and migrated into the reservoir from the Huqf source rocks. This thermally-generated H2S is presented with an initial background H2S level in the formation water in the simulations.\u0000 The Base-Case-Scenario results reveal that in the S field with the background H2S level (350 ppmv), the level of H2S increases to 1000 ppmv after injection-water breakthrough because of the addition water-induced microbial souring. In the T field without background H2S levels, the level of microbial H2S reaches 195 ppmv in year 2044 at a water cut of 95%.\u0000 The results of the Worst-Case Scenarios indicate that if the VFA content is significantly underestimated and the abstraction capacity is overestimated in the Base-Case Scenarios, the risk of microbial souring would be high in the S and T fields when injecting low-salinity Fars-aquifer water. In the Worst-Case Scenarios, the gas-phase H2S concentration attains max values of 3,400 and 1,200 ppmv, respectively, for the S and T fields.\u0000 Analysis of the microbial-souring mitigation options suggest that injecting the high-salinity produced-water re-injection (PWRI) at the station—being the most robust microbial-souring-prevention method available—is the best mitigation option in the T and S fields and its effectivity and efficiency are far superior to nitrate injection. In the Worst-Case Scenario, PWRI effectively hampers the generation and production of microbial H2S and maintains the H2S concentration in the produced gas around the background H2S level. Although PWRI is not an option for the S and T fields and there is no infrastructure in place for transferring the station-PWRI to the S a","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 2022","volume":"164 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76111495","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}
Moataz O. Abu-Al-Saud, S. Ayirala, A. AlSofi, A. Yousef
Understanding the impact of water salinity and ionic compositions on rock-fluids interactions and subsequently wettability plays a major role to determine the performance of different recovery processes in carbonate formations. Various studies have shown that surface electric charge manipulation is the main driving mechanism behind wettability alteration observed in controlled ionic composition waterflooding (CICW) processes. Therefore, investigation of electrokinetic interactions at both brine/calcite and brine/crude-oil interfaces is important to optimize the injection water compositions used for chemical enhanced oil recovery (EOR) in carbonates. In this investigation, the electrokinetic interactions of different surfactants at calcite/brine/crude-oil interfaces are studied using Surface Complexation Modeling (SCM) approach. First, the three low salinity water recipes of NaCl brine, Na2SO4 brine, SmartWater, and a high salinity water (HSW) are analyzed as baseline for zeta-potential comparison. The salinities of low salinity water recipes are fixed at the same salinity as 10-times diluted high salinity water. Then, four different surfactants are added at 0.1 wt% concentration to the brine recipes, where the first two surfactants are anionic, the third one is amphoteric, and the fourth one is non-ionic surfactant. The SCM results are compared with experimental zeta potential measurements for calcite/brine and crude oil/brine suspensions in different aqueous solutions containing surfactants. The SCM results reasonably matched the experimental zeta potential data trends obtained with different surfactants at brine/calcite and crude-oil/brine interfaces. Both the anionic surfactants altered the zeta-potential values of brine/calcite and crude-oil/brine interfaces towards more negative in all brine recipes. This impact is found to be more pronounced for SmartWater and HSW. For amphoteric surfactant that includes both anionic and cationic charges, the opposite trend is observed. The zeta potentials became less negative at calcite/brine and oil/brine interfaces thereby making it unattractive for chemical EOR in carbonates. The negative surface charge of NaCl, and Na2SO4 brines decreased when non-ionic surfactant is added to the aqueous solution. However, much favorable effect is observed with HSW in conjunction with non-ionic surfactant, wherein the zeta-potential magnitudes became increasingly negative at the two interfaces. In SCM framework, the trend is accurately captured by reducing the surface equilibrium reaction constants for divalent cations (Ca+2, and Mg+2) to result in less adsorbed concentrations of divalent cations at the interfaces. This assumption can be rationalized by the optimal phase behavior of non-ionic surfactant observed in HSW to further explain such high effectiveness from electrokinetics perspective. The novelty of this work is that it captures the electrokinetic interactions of different surfactant chemicals at calcite
{"title":"A Surface Complexation Modeling SCM Based Electrokinetic Solution for Chemical EOR in Carbonates","authors":"Moataz O. Abu-Al-Saud, S. Ayirala, A. AlSofi, A. Yousef","doi":"10.2118/200027-ms","DOIUrl":"https://doi.org/10.2118/200027-ms","url":null,"abstract":"\u0000 Understanding the impact of water salinity and ionic compositions on rock-fluids interactions and subsequently wettability plays a major role to determine the performance of different recovery processes in carbonate formations. Various studies have shown that surface electric charge manipulation is the main driving mechanism behind wettability alteration observed in controlled ionic composition waterflooding (CICW) processes. Therefore, investigation of electrokinetic interactions at both brine/calcite and brine/crude-oil interfaces is important to optimize the injection water compositions used for chemical enhanced oil recovery (EOR) in carbonates.\u0000 In this investigation, the electrokinetic interactions of different surfactants at calcite/brine/crude-oil interfaces are studied using Surface Complexation Modeling (SCM) approach. First, the three low salinity water recipes of NaCl brine, Na2SO4 brine, SmartWater, and a high salinity water (HSW) are analyzed as baseline for zeta-potential comparison. The salinities of low salinity water recipes are fixed at the same salinity as 10-times diluted high salinity water. Then, four different surfactants are added at 0.1 wt% concentration to the brine recipes, where the first two surfactants are anionic, the third one is amphoteric, and the fourth one is non-ionic surfactant. The SCM results are compared with experimental zeta potential measurements for calcite/brine and crude oil/brine suspensions in different aqueous solutions containing surfactants.\u0000 The SCM results reasonably matched the experimental zeta potential data trends obtained with different surfactants at brine/calcite and crude-oil/brine interfaces. Both the anionic surfactants altered the zeta-potential values of brine/calcite and crude-oil/brine interfaces towards more negative in all brine recipes. This impact is found to be more pronounced for SmartWater and HSW. For amphoteric surfactant that includes both anionic and cationic charges, the opposite trend is observed. The zeta potentials became less negative at calcite/brine and oil/brine interfaces thereby making it unattractive for chemical EOR in carbonates. The negative surface charge of NaCl, and Na2SO4 brines decreased when non-ionic surfactant is added to the aqueous solution. However, much favorable effect is observed with HSW in conjunction with non-ionic surfactant, wherein the zeta-potential magnitudes became increasingly negative at the two interfaces. In SCM framework, the trend is accurately captured by reducing the surface equilibrium reaction constants for divalent cations (Ca+2, and Mg+2) to result in less adsorbed concentrations of divalent cations at the interfaces. This assumption can be rationalized by the optimal phase behavior of non-ionic surfactant observed in HSW to further explain such high effectiveness from electrokinetics perspective.\u0000 The novelty of this work is that it captures the electrokinetic interactions of different surfactant chemicals at calcite","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 2022","volume":"48 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85658870","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}
Chao Xu, Chunqiang Chen, Jixin Deng, Tao Yang, Hong Yang, Hua Bai
Understanding the interwell distribution of the reservoir porosity is of great importance for well deployment to improve EOR. Seismic inversion with seismic and logging data is an efficient method to obtain the reservoir porosity. This study aims to demonstrate the spatial distribution of the reservoir porosity in an important formation in Central Iraq. 3D seismic attributes and logging data were combined to invert the reservoir porosity through neural network technology. The migrated 3D seismic volume, inverted P-wave impedance volume, seismic attributes and the logging data of 10 wells, were employed for training neural networks. Based on the training network, we generated the 3D porosity volume. To verify the accuracy of the inverted result, the inverted porosity were compared with those from the logging data of other 5 wells. Data slices were extracted with seismic horizons to show the lateral distribution of the reservoir porosity. The validation error shows the best multi-attribute pair is the pair of square root of P-wave impedance, quadrature trace, and instantaneous frequency. Neural network was trained with the three attribute pair. Analysis of the correlations between the predicted and the logging porosity showed the correlations from neural network training were higher than those achieved with multi-attribute regression. The porosity from the logging data of the 5 wells, which were not evolved in neural network training, coincided well with those from the inverted 3D porosity volume. That verified the accuracy of the inverted porosity volume from neural network inversion. Vertical sections and lateral slices of the inverted porosity volume were extracted to demonstrate the vertical and lateral distributions of the porosity, respectively. Data slices showed that the porosity were higher in the north and south area, and lower in the middle area. The study shows the porosity inverted from neural network technology is more reliable than that from muti-attribute regression. In addition, through this study, we demonstrate the porosity distribution in the project area. The new knowledge of the spatial distribution of reservoir porosity provides important guidance to the well deployment in the oilfield.
{"title":"Seismic Inversion of Reservoir Porosity with Neural Network Technology-A Case Study in Central Iraq","authors":"Chao Xu, Chunqiang Chen, Jixin Deng, Tao Yang, Hong Yang, Hua Bai","doi":"10.2118/200104-ms","DOIUrl":"https://doi.org/10.2118/200104-ms","url":null,"abstract":"\u0000 Understanding the interwell distribution of the reservoir porosity is of great importance for well deployment to improve EOR. Seismic inversion with seismic and logging data is an efficient method to obtain the reservoir porosity. This study aims to demonstrate the spatial distribution of the reservoir porosity in an important formation in Central Iraq. 3D seismic attributes and logging data were combined to invert the reservoir porosity through neural network technology. The migrated 3D seismic volume, inverted P-wave impedance volume, seismic attributes and the logging data of 10 wells, were employed for training neural networks. Based on the training network, we generated the 3D porosity volume. To verify the accuracy of the inverted result, the inverted porosity were compared with those from the logging data of other 5 wells. Data slices were extracted with seismic horizons to show the lateral distribution of the reservoir porosity. The validation error shows the best multi-attribute pair is the pair of square root of P-wave impedance, quadrature trace, and instantaneous frequency. Neural network was trained with the three attribute pair. Analysis of the correlations between the predicted and the logging porosity showed the correlations from neural network training were higher than those achieved with multi-attribute regression. The porosity from the logging data of the 5 wells, which were not evolved in neural network training, coincided well with those from the inverted 3D porosity volume. That verified the accuracy of the inverted porosity volume from neural network inversion. Vertical sections and lateral slices of the inverted porosity volume were extracted to demonstrate the vertical and lateral distributions of the porosity, respectively. Data slices showed that the porosity were higher in the north and south area, and lower in the middle area. The study shows the porosity inverted from neural network technology is more reliable than that from muti-attribute regression. In addition, through this study, we demonstrate the porosity distribution in the project area. The new knowledge of the spatial distribution of reservoir porosity provides important guidance to the well deployment in the oilfield.","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 2022","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91364403","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}
Mazin Al-Yaqoubi, H. Abass, Hamyar Masaaod Al Riyami, Dalil Ainouche, Khalfan Mubarak Al Bahri, S. Persac
Hydraulic fracturing is a challenge when the reservoir is adjacent to a water zone as it will extremely limit hydrocarbon production. The challenge becomes tougher when there is no stress barrier below the reservoir to contain the fracture. Several technologies have been applied by the oil and gas industry such as reducing injecting rate, using low viscosity, employing dual viscosity/density fracturing fluids, perforation location, and using proppant settling with dual fracturing treatment. The focus of this paper is to achieve two objectives; 1) place a long hydraulic fracture in the pay zone, and 2) avoid penetrating nearby water zone. This paper presents the proppant settling concept with essential augmentation that makes it a novel technology. The paper provides the oil and gas industry with a successful case history on fracturing low permeability reservoirs situated close to a water zone.
{"title":"Hydraulic Fracturing a Reservoir in Proximity to a Water Zone – Oman Case History","authors":"Mazin Al-Yaqoubi, H. Abass, Hamyar Masaaod Al Riyami, Dalil Ainouche, Khalfan Mubarak Al Bahri, S. Persac","doi":"10.2118/200287-ms","DOIUrl":"https://doi.org/10.2118/200287-ms","url":null,"abstract":"\u0000 Hydraulic fracturing is a challenge when the reservoir is adjacent to a water zone as it will extremely limit hydrocarbon production. The challenge becomes tougher when there is no stress barrier below the reservoir to contain the fracture. Several technologies have been applied by the oil and gas industry such as reducing injecting rate, using low viscosity, employing dual viscosity/density fracturing fluids, perforation location, and using proppant settling with dual fracturing treatment. The focus of this paper is to achieve two objectives; 1) place a long hydraulic fracture in the pay zone, and 2) avoid penetrating nearby water zone. This paper presents the proppant settling concept with essential augmentation that makes it a novel technology. The paper provides the oil and gas industry with a successful case history on fracturing low permeability reservoirs situated close to a water zone.","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 2022","volume":"130 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83901360","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 presents the state-of-the-art of the artificial intelligence algorithm, named dual heuristic dynamic programming (DHP) that uses to solve the petroleum optimization-control problems. Fast self-learning control based on DHP is illustrated for trajectory tracking levels on a quadruple tank system (QTS), which consists of four tanks and two electrical-pumps with two pressure control valves. Two artificial neural networks are constructed the DHP approach, which are the critic network (the provider of a critique/evaluated signals) and the actor-network or controller (the provider of control signals). DHP controller is learnt without human intervention via repeating the interaction between an equipment and environment/process. In other words, the equipment receives the system states of the process via sensors, and the algorithm maximizes the reward by selecting the correct optimal action (control signal) to feed the equipment. The simulation results are shown for applying DHP with QTS as a benchmark test problem by using MATLAB. QTS is taken in the paper because QTS is widely used in the most petroleum exploration/production fields as entire system or parts. The second reason for using QTS as a test problem is QTS has a difficult model to control, which has a limited zone of operating parameters to be stable. Multi-input-multi-output (MIMO) model of QTS is a similar model with most MIMO devises in the oil and gas field. The overall learning control system performance is tested and compared with a heuristic dynamic programming (HDP) and a well-known industrial controller, which is a proportional integral derivative (PID) by using MATLAB programming. The simulation results of DHP provide enhanced performance compared with the PID approach with 98.9002 % improvement. Furthermore, DHP is faster than HDP, whereas DHP needs 6 iterations, while HDP requires 652 iterations to stabilize the system at minimum error. Because of most equipment in the oil and gas industry has programmable logic control (PLC), the neural network block has already existed in the toolbox of the PLC program. Therefore, this project can apply in real by installing PLC to any equipment with DHP toolbox that connects to the sensors and actuators. At the first time, the DHP toolbox in PLC is learnt by itself to build a suitable robust controller. Then, the DHP controller is used during normal situations, while if any hard events happen to the equipment (the PID controller cannot handle it), the DHP toolbox starts learning from scratch again to overcome the new situations.
{"title":"Dual Heuristic Dynamic Programming in the Oil and Gas Industry for Trajectory Tracking Control","authors":"Seaar Al-Dabooni, Alaa Azeez Tawiq, H. Alshehab","doi":"10.2118/200271-ms","DOIUrl":"https://doi.org/10.2118/200271-ms","url":null,"abstract":"\u0000 This paper presents the state-of-the-art of the artificial intelligence algorithm, named dual heuristic dynamic programming (DHP) that uses to solve the petroleum optimization-control problems. Fast self-learning control based on DHP is illustrated for trajectory tracking levels on a quadruple tank system (QTS), which consists of four tanks and two electrical-pumps with two pressure control valves. Two artificial neural networks are constructed the DHP approach, which are the critic network (the provider of a critique/evaluated signals) and the actor-network or controller (the provider of control signals). DHP controller is learnt without human intervention via repeating the interaction between an equipment and environment/process. In other words, the equipment receives the system states of the process via sensors, and the algorithm maximizes the reward by selecting the correct optimal action (control signal) to feed the equipment. The simulation results are shown for applying DHP with QTS as a benchmark test problem by using MATLAB. QTS is taken in the paper because QTS is widely used in the most petroleum exploration/production fields as entire system or parts. The second reason for using QTS as a test problem is QTS has a difficult model to control, which has a limited zone of operating parameters to be stable. Multi-input-multi-output (MIMO) model of QTS is a similar model with most MIMO devises in the oil and gas field. The overall learning control system performance is tested and compared with a heuristic dynamic programming (HDP) and a well-known industrial controller, which is a proportional integral derivative (PID) by using MATLAB programming. The simulation results of DHP provide enhanced performance compared with the PID approach with 98.9002 % improvement. Furthermore, DHP is faster than HDP, whereas DHP needs 6 iterations, while HDP requires 652 iterations to stabilize the system at minimum error. Because of most equipment in the oil and gas industry has programmable logic control (PLC), the neural network block has already existed in the toolbox of the PLC program. Therefore, this project can apply in real by installing PLC to any equipment with DHP toolbox that connects to the sensors and actuators. At the first time, the DHP toolbox in PLC is learnt by itself to build a suitable robust controller. Then, the DHP controller is used during normal situations, while if any hard events happen to the equipment (the PID controller cannot handle it), the DHP toolbox starts learning from scratch again to overcome the new situations.","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 2022","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90065738","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}
I. D. Piñerez Torrijos, T. Puntervold, S. Strand, P. Hopkins, P. Aslanidis, Hae Sol Yang, Magnus Sundby Kinn
With the current reservoir engineering technology, it is not possible to measure wettability at downhole conditions. Therefore, laboratory work is necessary to correctly assess this parameter. Countless efforts have been made by reservoir engineers to obtain decent estimates of reservoir wettability. However, in many cases this objective remains elusive. This means that the current special core analyses (SCAL) protocols have not overcome this hurdle, and new approaches must be tested. In this work, the effects on wettability of two different sets of organic solvents are studied in carbonates, and a new cleaning and restoration protocol is tested to reproduce wettability in carbonate core samples. Two water-wet chalk core plugs were restored with the same initial formation water saturation (Swi=10%), and then were saturated and aged in crude oil to create an initial wetting. Spontaneous imbibition (SI) experiments confirmed the reproducibility of the restoration process used. After spontaneous imbibition, the two cores were cleaned with different methods, the first core plug was subjected to a mild cleaning process (kerosene-heptane) and the second one was cleaned with a harsh method (toluene-methanol). It was found that the mildly cleaned chalk core was slightly water-wet, and the harshly cleaned core appeared to have changed to a more water-wet state. Therefore, the solvent pair, kerosene-heptane, preserved more polar components at the carbonate surface than the toluene-methanol pair, the latter, was more effective in solvating and removing polar components from the rock surface, showing increased capillary forces in the SI test with heptane. The last stage of the study aimed to reproduce the first induced wettability, this was carried out in two cores after a mild cleaning process. It was possible to closely reproduce the initial wetting of these cores. This was accomplished by controlling the injected amount of mild cleaning solvents and crude oil during the second restoration process. These results represent a successful first phase of research towards wettability reproduction and improved reservoir wettability evaluation. Furthermore, it represents a solid and modern alternative to the traditional SCAL approach.
{"title":"Reproducing Core Wettability in Laboratory Core Restorations and the Influence of Solvent Cleaning on Carbonate Wetting","authors":"I. D. Piñerez Torrijos, T. Puntervold, S. Strand, P. Hopkins, P. Aslanidis, Hae Sol Yang, Magnus Sundby Kinn","doi":"10.2118/200160-ms","DOIUrl":"https://doi.org/10.2118/200160-ms","url":null,"abstract":"\u0000 With the current reservoir engineering technology, it is not possible to measure wettability at downhole conditions. Therefore, laboratory work is necessary to correctly assess this parameter. Countless efforts have been made by reservoir engineers to obtain decent estimates of reservoir wettability. However, in many cases this objective remains elusive. This means that the current special core analyses (SCAL) protocols have not overcome this hurdle, and new approaches must be tested.\u0000 In this work, the effects on wettability of two different sets of organic solvents are studied in carbonates, and a new cleaning and restoration protocol is tested to reproduce wettability in carbonate core samples. Two water-wet chalk core plugs were restored with the same initial formation water saturation (Swi=10%), and then were saturated and aged in crude oil to create an initial wetting. Spontaneous imbibition (SI) experiments confirmed the reproducibility of the restoration process used.\u0000 After spontaneous imbibition, the two cores were cleaned with different methods, the first core plug was subjected to a mild cleaning process (kerosene-heptane) and the second one was cleaned with a harsh method (toluene-methanol). It was found that the mildly cleaned chalk core was slightly water-wet, and the harshly cleaned core appeared to have changed to a more water-wet state. Therefore, the solvent pair, kerosene-heptane, preserved more polar components at the carbonate surface than the toluene-methanol pair, the latter, was more effective in solvating and removing polar components from the rock surface, showing increased capillary forces in the SI test with heptane.\u0000 The last stage of the study aimed to reproduce the first induced wettability, this was carried out in two cores after a mild cleaning process. It was possible to closely reproduce the initial wetting of these cores. This was accomplished by controlling the injected amount of mild cleaning solvents and crude oil during the second restoration process. These results represent a successful first phase of research towards wettability reproduction and improved reservoir wettability evaluation. Furthermore, it represents a solid and modern alternative to the traditional SCAL approach.","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 2022","volume":"46 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81008142","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}
Hommer Herbert, Reichenbach-Klinke Roland, Giesbrecht Russell, Lohateeraparp Prapas, H. George, Mai Kahnery
Chemical EOR flooding using hydrolyzed polyacrylamide (HPAM) is considered nowadays a state-of-the-art tertiary recovery process and has been conventionally applied on a full-field scale worldwide. The addition of these standard polymers improves the mobility of the injected fluid and thus maximize sweep; however, application is only limited to mild reservoir temperatures and low brine salinity ranges. Therefore, a more thermally stable and more resistant "associative polymers" were derived, by incorporating specific hydrophobic groups into the HPAM polymer backbone, to offer performance advantages with regards to viscosifying efficiency and salt tolerance when compared to the standard HPAM. However, only a handful of field cases were reported in the literature. Thus, this paper will present the unique application of this associative polymer technology in a field pilot for one of the major E&P companies and discusses the corresponding lab evaluations leading up to the field trial. To confirm the advantages of using associative polymer over of standard HPAM, rheology and filterability measurements were conducted. Moreover, linear coreflood experiments in presence of oil have been performed at target field conditions (low temperature and higher salinity) with various polymer concentrations. The resistance factors measured in the coreflood experiments indicated that 750 and 1,250 ppm of associative polymer and HPAM, respectively, are adequate to deliver the required mobility ratio of 1 and accordingly the oil recovery can be similar for the two different polymers at these concentrations. Moreover, dynamic adsorption measurements conducted at the same polymer concentration reveal a smooth propagation of the associative polymer through the porous medium. Based on these findings, it is concluded that the associative polymer offers a significant performance advantage over the HPAM due to the lower polymer dose required to achieve the target performance. After successful lab evaluations and in preparation for a multi-well pilot, a field injectivity trial was planned accordingly to test the propagation of the synthesized polymer in the reservoir. Subsequently, the selected associative polymer was successfully injected into the reservoir over a period of two months in two injectors at a steady injection rate of 50 and 300 m3/d. The measured well head pressures of the two injection wells was stable for the entire test duration, indicating a good polymer injectivity with no observed formation plugging. This newly developed associative polymer was proposed to the field's operator as a promising alternative solution to unlock additional reserves increase oil recovery and a full-field polymer flood expansion is planned next. To our knowledge, this is one of the few reported field trials with associative polymers and should facilitate field implementation of this technology.
{"title":"Field Application of an Associative Polymer Reveals Excellent Polymer Injectivity","authors":"Hommer Herbert, Reichenbach-Klinke Roland, Giesbrecht Russell, Lohateeraparp Prapas, H. George, Mai Kahnery","doi":"10.2118/200144-ms","DOIUrl":"https://doi.org/10.2118/200144-ms","url":null,"abstract":"\u0000 Chemical EOR flooding using hydrolyzed polyacrylamide (HPAM) is considered nowadays a state-of-the-art tertiary recovery process and has been conventionally applied on a full-field scale worldwide. The addition of these standard polymers improves the mobility of the injected fluid and thus maximize sweep; however, application is only limited to mild reservoir temperatures and low brine salinity ranges. Therefore, a more thermally stable and more resistant \"associative polymers\" were derived, by incorporating specific hydrophobic groups into the HPAM polymer backbone, to offer performance advantages with regards to viscosifying efficiency and salt tolerance when compared to the standard HPAM. However, only a handful of field cases were reported in the literature. Thus, this paper will present the unique application of this associative polymer technology in a field pilot for one of the major E&P companies and discusses the corresponding lab evaluations leading up to the field trial.\u0000 To confirm the advantages of using associative polymer over of standard HPAM, rheology and filterability measurements were conducted. Moreover, linear coreflood experiments in presence of oil have been performed at target field conditions (low temperature and higher salinity) with various polymer concentrations. The resistance factors measured in the coreflood experiments indicated that 750 and 1,250 ppm of associative polymer and HPAM, respectively, are adequate to deliver the required mobility ratio of 1 and accordingly the oil recovery can be similar for the two different polymers at these concentrations. Moreover, dynamic adsorption measurements conducted at the same polymer concentration reveal a smooth propagation of the associative polymer through the porous medium. Based on these findings, it is concluded that the associative polymer offers a significant performance advantage over the HPAM due to the lower polymer dose required to achieve the target performance.\u0000 After successful lab evaluations and in preparation for a multi-well pilot, a field injectivity trial was planned accordingly to test the propagation of the synthesized polymer in the reservoir. Subsequently, the selected associative polymer was successfully injected into the reservoir over a period of two months in two injectors at a steady injection rate of 50 and 300 m3/d. The measured well head pressures of the two injection wells was stable for the entire test duration, indicating a good polymer injectivity with no observed formation plugging.\u0000 This newly developed associative polymer was proposed to the field's operator as a promising alternative solution to unlock additional reserves increase oil recovery and a full-field polymer flood expansion is planned next. To our knowledge, this is one of the few reported field trials with associative polymers and should facilitate field implementation of this technology.","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 2022","volume":"2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81756493","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A. Alshawaf, Mohammad Al Momen, Ghaliah Khoja, Jaime Rabines, Hassan Al Doukhi, M. Issaka
Developing tight sandstone across vast area requires proper data collection and analysis. Due to the tight nature and heterogeneity of these reservoirs, several vertical and horizontal wells need to be drilled and completed with multistage hydraulic fractures to assess their potential. Initial post-frac flowback tests, in addition to long-term pressure build-ups, have already been conducted on several of the wells. Data Analysis have assisted in characterization of the tight hydrocarbon reservoirs and evaluating of hydraulic fracture geometry. The results have aided to investigate the drainage radius and well interference, to determine the optimal frac and well spacing design. These information are highly needed to build and calibrate single and full field dynamic models to estimate and address the uncertainty on the ultimate recovery and to come up with an optimized development strategy of the field. The paper presents findings and key lessons learned to efficiently design pressure build-up tests in tight sandstone reservoirs.
{"title":"Lessons Learned from Recent Post-Frac Drawdown-Buildup Tests in Tight Sands Reservoirs","authors":"A. Alshawaf, Mohammad Al Momen, Ghaliah Khoja, Jaime Rabines, Hassan Al Doukhi, M. Issaka","doi":"10.2118/200206-ms","DOIUrl":"https://doi.org/10.2118/200206-ms","url":null,"abstract":"\u0000 Developing tight sandstone across vast area requires proper data collection and analysis. Due to the tight nature and heterogeneity of these reservoirs, several vertical and horizontal wells need to be drilled and completed with multistage hydraulic fractures to assess their potential.\u0000 Initial post-frac flowback tests, in addition to long-term pressure build-ups, have already been conducted on several of the wells. Data Analysis have assisted in characterization of the tight hydrocarbon reservoirs and evaluating of hydraulic fracture geometry. The results have aided to investigate the drainage radius and well interference, to determine the optimal frac and well spacing design. These information are highly needed to build and calibrate single and full field dynamic models to estimate and address the uncertainty on the ultimate recovery and to come up with an optimized development strategy of the field. The paper presents findings and key lessons learned to efficiently design pressure build-up tests in tight sandstone reservoirs.","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 2022","volume":"9 10","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72578008","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}
R.. Al Shidhani, A. Al Shueili, R. Shehab, Nabeel Masood
The Oil and Gas industry currently faces the dual challenge of meeting the global energy demand with minimal carbon footprint. The Barik formation is a tight to low-end conventional reservoir in Khazzan/Ghazeer Field (Block 61) in the central of the Sultanate of Oman. The field requires hydraulic fracturing to economically produce the wells, in which chemicals and proppant are pumped into the formation. Each well requires a period of clean up after pumping the frac and before connecting it to the facility in order to get rid of all the undesirable material from entering the processing facility. During this clean up and testing period, all produced gas and condensate are flared in the atmosphere. This paper presents an optimization project which was implemented in Khazzan and Ghazeer fields in Block 61 to optimize the post frac clean up and testing period in order to reduce hydrocarbon flaring and CO2 emissions as well as reducing the testing cost, without compromising the overall well clean up and testing objectives. The optimization project was originally started in 2015 where the clean-up and testing period was reduced gradually by optimizing the well bean up schedule (choke management and duration for each choke).
{"title":"Post-Frac Clean Up and Testing Optimization","authors":"R.. Al Shidhani, A. Al Shueili, R. Shehab, Nabeel Masood","doi":"10.2118/200179-ms","DOIUrl":"https://doi.org/10.2118/200179-ms","url":null,"abstract":"\u0000 The Oil and Gas industry currently faces the dual challenge of meeting the global energy demand with minimal carbon footprint. The Barik formation is a tight to low-end conventional reservoir in Khazzan/Ghazeer Field (Block 61) in the central of the Sultanate of Oman. The field requires hydraulic fracturing to economically produce the wells, in which chemicals and proppant are pumped into the formation. Each well requires a period of clean up after pumping the frac and before connecting it to the facility in order to get rid of all the undesirable material from entering the processing facility. During this clean up and testing period, all produced gas and condensate are flared in the atmosphere.\u0000 This paper presents an optimization project which was implemented in Khazzan and Ghazeer fields in Block 61 to optimize the post frac clean up and testing period in order to reduce hydrocarbon flaring and CO2 emissions as well as reducing the testing cost, without compromising the overall well clean up and testing objectives.\u0000 The optimization project was originally started in 2015 where the clean-up and testing period was reduced gradually by optimizing the well bean up schedule (choke management and duration for each choke).","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 2022","volume":"45 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82803899","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}
F. Saadi, Ali Al Jumah, Khalfan Harthy, S. Khaburi, Fathiya Battashi
This paper will discuss a polymerflood field application, the data has been gathered, and the new project designed specifically to test the concept of Nothing-Alternating-Polymer (NAP) mechanism, in a current Polymer flood pattern, in a horizontal wells environment. This specific project will be utilized to fast track the implementation of the NAP concept, and accelerating Fullfield development, and highlight the associated benefits from a project's perspective, leading towards attractive, competitive development cost, and flexible operating conditions.
{"title":"Cost Efficient Polymer Full Field Development by Fast Tracking Nap Concept in Horizontal Polymer Injectors","authors":"F. Saadi, Ali Al Jumah, Khalfan Harthy, S. Khaburi, Fathiya Battashi","doi":"10.2118/200166-ms","DOIUrl":"https://doi.org/10.2118/200166-ms","url":null,"abstract":"\u0000 This paper will discuss a polymerflood field application, the data has been gathered, and the new project designed specifically to test the concept of Nothing-Alternating-Polymer (NAP) mechanism, in a current Polymer flood pattern, in a horizontal wells environment. This specific project will be utilized to fast track the implementation of the NAP concept, and accelerating Fullfield development, and highlight the associated benefits from a project's perspective, leading towards attractive, competitive development cost, and flexible operating conditions.","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 2022","volume":"503 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75544698","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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