Pub Date : 2021-02-01DOI: 10.1016/j.upstre.2021.100032
Muhammad Rabiu Ado
In-situ-combustion-type processes such as the Toe-to-Heel Air Injection (THAI) process have been shown to have advantages over other thermal enhanced oil recovery processes. The THAI process uses in situ combustion to mobilise and upgrade bitumen or heavy oil within the reservoir. This study compares the effect of injecting pure oxygen instead of air on the performance of the THAI process. It is found that over the 833 days of the process time, an additional 3.85% of oil originally in place (OOIP) was recovered with injecting pure oxygen compared to with injecting air. It is found that as the combustion front advances, higher axial length fraction of the HP well is used for oil production. Observing the oil production rate distribution along the HP well, it is concluded that highest oil flow rate enters the HP well at the toe in both models. It has been shown that it is likely that gas production might have negatively affected the oil production when air is the injected fluid (i.e. in the air model).
{"title":"Improving oil recovery rates in THAI in situ combustion process using pure oxygen","authors":"Muhammad Rabiu Ado","doi":"10.1016/j.upstre.2021.100032","DOIUrl":"10.1016/j.upstre.2021.100032","url":null,"abstract":"<div><p><span>In-situ-combustion-type processes such as the Toe-to-Heel Air Injection (THAI) process have been shown to have advantages over other thermal enhanced oil recovery<span> processes. The THAI process uses in situ combustion to mobilise and upgrade bitumen or heavy oil within the reservoir. This study compares the effect of injecting pure oxygen instead of air on the performance of the THAI process. It is found that over the 833 days of the process time, an additional 3.85% of oil originally in place (OOIP) was recovered with injecting pure oxygen compared to with injecting air. It is found that as the combustion front advances, higher axial length fraction of the HP well is used for oil production. Observing the oil production rate distribution along the HP well, it is concluded that highest </span></span>oil flow rate enters the HP well at the toe in both models. It has been shown that it is likely that gas production might have negatively affected the oil production when air is the injected fluid (i.e. in the air model).</p></div>","PeriodicalId":101264,"journal":{"name":"Upstream Oil and Gas Technology","volume":"6 ","pages":"Article 100032"},"PeriodicalIF":0.0,"publicationDate":"2021-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1016/j.upstre.2021.100032","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"94785799","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 design optimization and testing of a novel screw conveyor based system to scoop crude oil sludge from the floor of oil storage tanks. This proposed new system consists of a screw conveyor mounted on a ‘C’ shaped casing with a bearing on both sides driven by a waterproof motor through a worm drive. A novel mathematical model is developed to help the design of a screw conveyor for a maximum amount of sludge scooping per turn, and numerical simulations are performed using computational fluid dynamics to visualize the flow of material particles in various possible designs of the system. The proposed mechanism was 3D printed, and laboratory tests were conducted to quantify the amount of sludge removal by the different designs of the screw. Optimized design of a mechanism screw with a radius ratio of 0.40 and a pitch ratio of 0.15 scoops up to a maximum of 5.88 of material at 110 .
{"title":"Design optimization of a novel screw conveyor based system to scoop oil sludge from floor of storage tanks","authors":"Bhavesh Narayani , Santhosh Ravichandran , Prabhu Rajagopal","doi":"10.1016/j.upstre.2020.100029","DOIUrl":"10.1016/j.upstre.2020.100029","url":null,"abstract":"<div><p>This paper presents the design optimization and testing of a novel screw conveyor based system to scoop crude oil sludge from the floor of oil storage tanks. This proposed new system consists of a screw conveyor mounted on a ‘C’ shaped casing with a bearing on both sides driven by a waterproof motor through a worm drive. A novel mathematical model is developed to help the design of a screw conveyor for a maximum amount of sludge scooping per turn, and numerical simulations are performed using computational fluid dynamics to visualize the flow of material particles in various possible designs of the system. The proposed mechanism was 3D printed, and laboratory tests were conducted to quantify the amount of sludge removal by the different designs of the screw. Optimized design of a mechanism screw with a radius ratio of 0.40 and a pitch ratio of 0.15 scoops up to a maximum of 5.88 <span><math><mfrac><mtext>kg</mtext><mtext>hr</mtext></mfrac></math></span> of material at 110 <span><math><mfrac><mtext>rev</mtext><mtext>min</mtext></mfrac></math></span>.</p></div>","PeriodicalId":101264,"journal":{"name":"Upstream Oil and Gas Technology","volume":"6 ","pages":"Article 100029"},"PeriodicalIF":0.0,"publicationDate":"2021-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1016/j.upstre.2020.100029","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"105311328","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}
Pub Date : 2020-10-01DOI: 10.1016/j.upstre.2020.100020
Salam Al-Rbeawi , Mohammed Hliyil Hafiz Al-Kaabi
A hybrid model for unconventional gas reservoirs that couples three different parameters is presented in this paper. The first is the anomalous diffusion in a fractal porous media. The second is the stimulated or induced matrix permeability in the stimulated reservoir volume (SRV). The third is the non-Darcy flow permeability in the hydraulic fractures. This model is generated from the multi-linear flow model for fractal reservoirs controlled by diffusive flow mechanism with adjustment for fluid flux through hydraulic fracture face considering minimum fracture relative permeability (kmr) and non-Darcy flow Number (FND).
Pressure distributions, flow regimes, and reservoir performances have been investigated for three types of unconventional reservoirs. The first is formations with homogenous matrix permeability where petrophysical properties of stimulated and un-stimulated reservoir volume are the same. The second is fractal reservoirs with different petrophysical properties in the two volumes without considering normal or classic diffusion mechanism. The third is the fractal reservoirs where anomalous diffusive flow mechanism dominates fluid flow. A set of comparisons has been generated between the three types for better understand the impact of non-Darcy flow permeability and stimulated matrix permeability on reservoir performance under normal and anomalous diffusion flow mechanisms.
The outcomes of this study are: (1) Generating a new analytical model that describes pressure distribution in fractal unconventional reservoirs and couples non-Darcy flow, stimulated or induced matrix permeability with the anomalous diffusion in porous media. (2) Understanding the impact of these different parameters on reservoir performance. (3) Developing different models for all types of flow regimes that are expected to be observed during the entire production life. (4) Comparing the productivity index of reservoirs: having homogeneous matrix permeability, fractal with normal diffusion, and fractal with anomalous diffusion. The most interesting points in this study are: (1) Minimum fracture relative permeability (kmr) significantly enhances the productivity index by eliminating the impact of non-Darcy flow while non-Darcy flow number (FND) works conversely (2) Increasing stimulated matrix permeability enhances reservoir performance (3) The impact of non-Darcy flow permeability of hydraulic fractures is seen at early and intermediate production time where transient flow is dominant. (4) Two different trends are recognized for the impact of anomalous diffusion flow: the first is a positive impact on the transient flow period and the second is negative in the pseudo-steady state flow.
{"title":"A hybrid model for the combined impact of non-Darcy flow, stimulated matrix permeability, and anomalous diffusion flow in the unconventional reservoirs","authors":"Salam Al-Rbeawi , Mohammed Hliyil Hafiz Al-Kaabi","doi":"10.1016/j.upstre.2020.100020","DOIUrl":"10.1016/j.upstre.2020.100020","url":null,"abstract":"<div><p><span><span>A hybrid model for unconventional gas reservoirs that couples three different parameters is presented in this paper. The first is the anomalous diffusion in a fractal porous media<span>. The second is the stimulated or induced matrix permeability in the stimulated reservoir volume (SRV). The third is the non-Darcy flow permeability in the hydraulic fractures. This model is generated from the multi-linear flow model for fractal reservoirs controlled by diffusive flow mechanism with adjustment for fluid flux through hydraulic fracture face considering minimum fracture </span></span>relative permeability (</span><em>k<sub>mr</sub></em>) and non-Darcy flow Number (<em>F<sub>ND</sub></em>).</p><p>Pressure distributions, flow regimes, and reservoir performances have been investigated for three types of unconventional reservoirs. The first is formations with homogenous matrix permeability where petrophysical properties of stimulated and un-stimulated reservoir volume are the same. The second is fractal reservoirs with different petrophysical properties in the two volumes without considering normal or classic diffusion mechanism<span>. The third is the fractal reservoirs where anomalous diffusive flow mechanism dominates fluid flow. A set of comparisons has been generated between the three types for better understand the impact of non-Darcy flow permeability and stimulated matrix permeability on reservoir performance under normal and anomalous diffusion flow mechanisms.</span></p><p>The outcomes of this study are: (1) Generating a new analytical model that describes pressure distribution in fractal unconventional reservoirs and couples non-Darcy flow, stimulated or induced matrix permeability with the anomalous diffusion in porous media. (2) Understanding the impact of these different parameters on reservoir performance. (3) Developing different models for all types of flow regimes that are expected to be observed during the entire production life. (4) Comparing the productivity index of reservoirs: having homogeneous matrix permeability, fractal with normal diffusion, and fractal with anomalous diffusion. The most interesting points in this study are: (1) Minimum fracture relative permeability (<em>k<sub>mr</sub></em>) significantly enhances the productivity index by eliminating the impact of non-Darcy flow while non-Darcy flow number (<em>F<sub>ND</sub></em>) works conversely (2) Increasing stimulated matrix permeability enhances reservoir performance (3) The impact of non-Darcy flow permeability of hydraulic fractures is seen at early and intermediate production time where transient flow is dominant. (4) Two different trends are recognized for the impact of anomalous diffusion flow: the first is a positive impact on the transient flow period and the second is negative in the pseudo-steady state flow.</p></div>","PeriodicalId":101264,"journal":{"name":"Upstream Oil and Gas Technology","volume":"5 ","pages":"Article 100020"},"PeriodicalIF":0.0,"publicationDate":"2020-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1016/j.upstre.2020.100020","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"106553120","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}
Pub Date : 2020-10-01DOI: 10.1016/j.upstre.2020.100013
Abdulaziz Al-Qasim
With maturing oil fields, there is an increasing focus on improving the oil recovery factor and pushing the envelope towards a 70% target. This target is indeed very challenging and can be reached by fully understanding the reservoir characteristics before using an enhanced oil recovery method. These include reservoir heterogeneities, displacement efficiency, horizontal sweep, vertical sweep due to flow behind the casing, and the presence of conductive faults or fractures. Therefore, a proper surveillance should be performed to evaluate the injectant plume front, reservoir conformance, well connectivity, and the assessment of well integrity, which can be crucial for the success of the project and its future development.
This paper discusses a special downhole logging technique including a set of conventional multiphase sensors alongside high precision temperature (HPT) and high-definition spectral noise logging (SNL-HD). It was run for an injector and producer pair near the wellbore area to provide complete assessment of the integrity issues that might impair the lateral sweep of injectants into the target layer. The operation was carried out with a tool string that contained no mechanical parts and was not affected by downhole fluid properties. It was also conducted under both flowing and shut-in conditions to identify flow zones, to check fracture signatures and to provide multiphase fluid velocity profiles.
The results of the survey allowed for in-depth assessment of borehole and behind casing flow, confirming lateral continuity, and allow for better well planning and anticipation of possible loss of well integrity. Combining the behind casing flow assessment with borehole multiphase flow distribution can be used for production optimization by sealing unwanted water contributing zones that might impair production in the future.
{"title":"Monitoring and surveillance of subsurface multiphase flow and well integrity","authors":"Abdulaziz Al-Qasim","doi":"10.1016/j.upstre.2020.100013","DOIUrl":"10.1016/j.upstre.2020.100013","url":null,"abstract":"<div><p>With maturing oil fields, there is an increasing focus on improving the oil recovery factor and pushing the envelope towards a 70% target. This target is indeed very challenging and can be reached by fully understanding the reservoir characteristics<span><span> before using an enhanced oil recovery method. These include </span>reservoir heterogeneities, displacement efficiency, horizontal sweep, vertical sweep due to flow behind the casing, and the presence of conductive faults or fractures. Therefore, a proper surveillance should be performed to evaluate the injectant plume front, reservoir conformance, well connectivity, and the assessment of well integrity, which can be crucial for the success of the project and its future development.</span></p><p><span><span>This paper discusses a special downhole logging technique including a set of conventional multiphase sensors alongside high precision temperature (HPT) and high-definition spectral noise logging (SNL-HD). It was run for an </span>injector and producer pair near the </span>wellbore<span> area to provide complete assessment of the integrity issues that might impair the lateral sweep of injectants into the target layer. The operation was carried out with a tool string that contained no mechanical parts and was not affected by downhole fluid properties. It was also conducted under both flowing and shut-in conditions to identify flow zones, to check fracture signatures and to provide multiphase fluid velocity profiles.</span></p><p>The results of the survey allowed for in-depth assessment of borehole and behind casing flow, confirming lateral continuity, and allow for better well planning and anticipation of possible loss of well integrity. Combining the behind casing flow assessment with borehole multiphase flow distribution can be used for production optimization by sealing unwanted water contributing zones that might impair production in the future.</p></div>","PeriodicalId":101264,"journal":{"name":"Upstream Oil and Gas Technology","volume":"5 ","pages":"Article 100013"},"PeriodicalIF":0.0,"publicationDate":"2020-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1016/j.upstre.2020.100013","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"111665662","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}
Pub Date : 2020-10-01DOI: 10.1016/j.upstre.2020.100008
Carlos Melo , Markus R. Dann , Ronald J. Hugo , Alberto Janeta
This paper introduces a method for risk-based inspection planning based on maximizing the value of information (VOI) to select optimal verification sites for validating the results of direct assessment (DA) of internally corroded pipelines. The proposed method improves existing industry practices for DA, which are not risk-based. The effect of different corrosion growth assumptions on the VOI and optimal inspection strategies is investigated. The results show that different corrosion growth assumptions lead to different optimal verification sites. They also demonstrate that the proposed model is effective at facilitating the selection of optimal verification sites and for improved decisions regarding maintenance actions for internally-corroded pipelines.
{"title":"Optimal locations for non-destructive inspections to verify direct assessment of internally corroded pipelines","authors":"Carlos Melo , Markus R. Dann , Ronald J. Hugo , Alberto Janeta","doi":"10.1016/j.upstre.2020.100008","DOIUrl":"10.1016/j.upstre.2020.100008","url":null,"abstract":"<div><p>This paper introduces a method for risk-based inspection planning based on maximizing the value of information (VOI) to select optimal verification sites for validating the results of direct assessment (DA) of internally corroded pipelines. The proposed method improves existing industry practices for DA, which are not risk-based. The effect of different corrosion growth assumptions on the VOI and optimal inspection strategies is investigated. The results show that different corrosion growth assumptions lead to different optimal verification sites. They also demonstrate that the proposed model is effective at facilitating the selection of optimal verification sites and for improved decisions regarding maintenance actions for internally-corroded pipelines.</p></div>","PeriodicalId":101264,"journal":{"name":"Upstream Oil and Gas Technology","volume":"5 ","pages":"Article 100008"},"PeriodicalIF":0.0,"publicationDate":"2020-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1016/j.upstre.2020.100008","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"102253372","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}
Pub Date : 2020-10-01DOI: 10.1016/j.upstre.2020.100023
Sukru Merey , Hakki Aydin , Tuna Eren
Gas hydrate industry aims to conduct long-term gas hydrate production trials after gaining the experiences in short-term gas hydrate production trials. Electrical submersible pumps (ESP) were mostly chosen in gas hydrate production trials to depressurize gas hydrate reservoirs. However, there is a knowledge gap about the usage and design of ESP systems in gas hydrate wells. Therefore, in this study, it is aimed to design ESP systems in methane hydrate production well in the conditions of Nankai Trough (Japan) methane hydrate reservoirs. For this purpose, a set of python codes was written to design ESP in the case study gas hydrate well and also HEP simulator was used to predict gas hydrate formation risks along the wellbore during gas production from methane hydrates via ESP production string. It was shown that high variances in water production rates (50–794 m3/day) affect the pump performance negatively, especially in the outside of suggested pump working flow rates. Moreover, pump efficiencies decrease from 70 s% to 20 s% in the outside of pump working flow rates due to huge variances in water flow rates during production. Different than conventional gas wells, the temperature rise generated by the motor is important to avoid any gas hydrate formation in gas hydrate well, which was affected by the operating frequency. Above 40 Hz of operating frequency, well temperature increases (nearly 0.65–1.75°C) by the motor with increasing frequency, which is good for the prohibition of gas hydrate formation in the well. In terms of pump power requirements, there is no difference of producing water at sea surface and releasing produced water to the seafloor. According to the methane hydrate equilibrium predictions in the wellbore during production with ESP, methane hydrate is not like to form in the design conditions. However, with ESP malfunction, methane hydrate might form inside the well due to increasing wellbore pressure and decreasing well temperature.
{"title":"Design of electrical submersible pumps in methane hydrate production wells: A case study in Nankai trough methane hydrates","authors":"Sukru Merey , Hakki Aydin , Tuna Eren","doi":"10.1016/j.upstre.2020.100023","DOIUrl":"10.1016/j.upstre.2020.100023","url":null,"abstract":"<div><p><span><span>Gas hydrate<span> industry aims to conduct long-term gas hydrate production trials after gaining the experiences in short-term gas hydrate production trials. Electrical submersible pumps (ESP) were mostly chosen in gas hydrate production trials to depressurize gas hydrate reservoirs. However, there is a knowledge gap about the usage and design of ESP systems in gas hydrate wells. Therefore, in this study, it is aimed to design ESP systems in </span></span>methane hydrate<span><span> production well in the conditions of Nankai Trough (Japan) methane hydrate reservoirs. For this purpose, a set of python codes was written to design ESP in the case study gas hydrate well and also HEP simulator was used to predict gas hydrate formation risks along the </span>wellbore during gas production from methane hydrates via ESP production string. It was shown that high variances in water production rates (50–794 m</span></span><sup>3</sup>/day) affect the pump performance negatively, especially in the outside of suggested pump working flow rates. Moreover, pump efficiencies decrease from 70 s% to 20 s% in the outside of pump working flow rates due to huge variances in water flow rates during production. Different than conventional gas wells, the temperature rise generated by the motor is important to avoid any gas hydrate formation in gas hydrate well, which was affected by the operating frequency. Above 40 Hz of operating frequency, well temperature increases (nearly 0.65–1.75<span></span>°C) by the motor with increasing frequency, which is good for the prohibition of gas hydrate formation in the well. In terms of pump power requirements, there is no difference of producing water at sea surface and releasing produced water to the seafloor. According to the methane hydrate equilibrium predictions in the wellbore during production with ESP, methane hydrate is not like to form in the design conditions. However, with ESP malfunction, methane hydrate might form inside the well due to increasing wellbore pressure and decreasing well temperature.</p></div>","PeriodicalId":101264,"journal":{"name":"Upstream Oil and Gas Technology","volume":"5 ","pages":"Article 100023"},"PeriodicalIF":0.0,"publicationDate":"2020-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1016/j.upstre.2020.100023","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"104732464","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}
Pub Date : 2020-10-01DOI: 10.1016/j.upstre.2020.100010
Iman Jafarifar , Babak Karimi Dehkordi , Hassan Abbasi , Mahin Schaffie , Mohammad Ranjbar
Slim-hole drilling in oil and gas industry has been developed extensively in recent years. Drilling fluid, in addition to providing appropriate rheological properties should produce a low annular pressure loss (APL) gradient while drilling. During slim-hole drilling, drilling mud hydraulics is an important concern, because due to reduced annular clearance, pressure loss can occur in drill pipe and annulus considerably. In this research, water based drilling muds were selected for the experimental work due to its low price, simple preparation and easy access to the required water. The research includes development and testing of water-salt based fluids. In this study, sixty-five samples of fluids were analyzed for their rheological parameters, the were considered using three various case study gas field wellbore configurations 6 1/8, 5 7/8 and 4 1/8 inch for their calculate APL gradients. Each composition was evaluated by the Power-Law and Bingham Plastic models and results of both models were compared. Choose of optimum fluids is based on suitable rheological properties, minimum annular pressure losses and maximum fluid transport ratio. Also, the effect of high temperature (180°F) on frictional pressure losses was studied. For an optimal formulation at high temperature from a well with distinct configuration 6 1/8 inch had an APL gradient of 0.149 psi/ft compared to 0.176 psi/ft at atmospheric condition. It was found that effect of high temperature on drilling fluids behavior is affirmative. On the other hand, the observed effect of high temperature on Power-Law fluids greater than Bingham Plastic fluids. Fluids with xanthan, in spite of high cutting carrying capacity and due to high viscosity have exhibited high frictional pressure loss. However, for some fluids, the annular pressure loss increased at high temperature due to green starch fermentation.
{"title":"Evaluation and optimization of water-salt based drilling fluids for slim-hole wells in one of Iranian central oil fields","authors":"Iman Jafarifar , Babak Karimi Dehkordi , Hassan Abbasi , Mahin Schaffie , Mohammad Ranjbar","doi":"10.1016/j.upstre.2020.100010","DOIUrl":"10.1016/j.upstre.2020.100010","url":null,"abstract":"<div><p>Slim-hole drilling in oil and gas industry has been developed extensively in recent years. Drilling fluid, in addition to providing appropriate rheological properties should produce a low annular pressure loss (APL) gradient while drilling. During slim-hole drilling, drilling mud hydraulics is an important concern, because due to reduced annular clearance, pressure loss can occur in drill pipe and annulus considerably. In this research, water based drilling muds were selected for the experimental work due to its low price, simple preparation and easy access to the required water. The research includes development and testing of water-salt based fluids. In this study, sixty-five samples of fluids were analyzed for their rheological parameters, the were considered using three various case study gas field wellbore configurations 6 1/8, 5 7/8 and 4 1/8 inch for their calculate APL gradients. Each composition was evaluated by the Power-Law and Bingham Plastic models and results of both models were compared. Choose of optimum fluids is based on suitable rheological properties, minimum annular pressure losses and maximum fluid transport ratio. Also, the effect of high temperature (180°F) on frictional pressure losses was studied. For an optimal formulation at high temperature from a well with distinct configuration 6 1/8 inch had an APL gradient of 0.149 psi/ft compared to 0.176 psi/ft at atmospheric condition. It was found that effect of high temperature on drilling fluids behavior is affirmative. On the other hand, the observed effect of high temperature on Power-Law fluids greater than Bingham Plastic fluids. Fluids with xanthan, in spite of high cutting carrying capacity and due to high viscosity have exhibited high frictional pressure loss. However, for some fluids, the annular pressure loss increased at high temperature due to green starch fermentation.</p></div>","PeriodicalId":101264,"journal":{"name":"Upstream Oil and Gas Technology","volume":"5 ","pages":"Article 100010"},"PeriodicalIF":0.0,"publicationDate":"2020-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1016/j.upstre.2020.100010","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"93732206","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}
Design of drilling fluids is critical to the techno-economic success of drilling a petroleum well bore and the present study is a forward step in that direction. Effect of TiO2 nanoparticles on the thermal stability of drilling fluid properties is evaluated using two different mud systems based on polyanionic cellulose (PAC) and hydroxyethyl cellulose (HEC). Drilling fluids were subjected to high temperature rolling conditions at 110 °C and 30 rpm for 16 hours in order to simulate the wellbore environment using a roller oven. Due to 16 h long hot rolling, the API FL values for DFB (base mud), DFP3 (1.0 w/v% PAC) and DFH3 (1.0 w/v% HEC) increased by ~56%, ~18% and ~46% respectively; whereas in presence of 0.5 w/v% nanoparticles respective figures were ~28%, ~16% and ~25%. In case of DFP3, AV at 25 °C was reduced due to hot rolling by ~34% without nanoparticles and by only ~15% in presence of nanoparticles. For DFH3, the percentage reduction in AV at 25 °C due to ageing was ~24% which decreased to ~16% for DFHN (1.0 w/v% HEC and 0.5 w/v% TiO2). It was found that nanoparticles imparted resistance to thermal degradation in rheological and filtration characteristics of drilling fluids. Filter cakes were studied using scanning electron microscopy and showed nanoparticles scattered over the surface of filter cakes which were filling the micro and nano sized gaps in the porous structure of mud cake and reducing the filtration rate. This study shows that using TiO2 nanoparticles along with a conventional fluid loss reducer additive not only enhances the efficacy of that additive but also improves the thermal stability and rheological properties of mud systems.
{"title":"Effect of high temperature ageing on TiO2 nanoparticles enhanced drilling fluids: A rheological and filtration study","authors":"Mukarram Beg, Pranav Kumar , Pratham Choudhary , Shivanjali Sharma","doi":"10.1016/j.upstre.2020.100019","DOIUrl":"10.1016/j.upstre.2020.100019","url":null,"abstract":"<div><p>Design of drilling fluids is critical to the techno-economic success of drilling a petroleum well bore and the present study is a forward step in that direction. Effect of TiO<sub>2</sub> nanoparticles on the thermal stability of drilling fluid properties is evaluated using two different mud systems based on polyanionic cellulose (PAC) and hydroxyethyl cellulose (HEC). Drilling fluids were subjected to high temperature rolling conditions at 110 °C and 30 rpm for 16 hours in order to simulate the wellbore environment using a roller oven. Due to 16 h long hot rolling, the API FL values for DFB (base mud), DFP3 (1.0 w/v% PAC) and DFH3 (1.0 w/v% HEC) increased by ~56%, ~18% and ~46% respectively; whereas in presence of 0.5 w/v% nanoparticles respective figures were ~28%, ~16% and ~25%. In case of DFP3, AV at 25 °C was reduced due to hot rolling by ~34% without nanoparticles and by only ~15% in presence of nanoparticles. For DFH3, the percentage reduction in AV at 25 °C due to ageing was ~24% which decreased to ~16% for DFHN (1.0 w/v% HEC and 0.5 w/v% TiO<sub>2</sub>). It was found that nanoparticles imparted resistance to thermal degradation in rheological and filtration characteristics of drilling fluids. Filter cakes were studied using scanning electron microscopy and showed nanoparticles scattered over the surface of filter cakes which were filling the micro and nano sized gaps in the porous structure of mud cake and reducing the filtration rate. This study shows that using TiO<sub>2</sub> nanoparticles along with a conventional fluid loss reducer additive not only enhances the efficacy of that additive but also improves the thermal stability and rheological properties of mud systems.</p></div>","PeriodicalId":101264,"journal":{"name":"Upstream Oil and Gas Technology","volume":"5 ","pages":"Article 100019"},"PeriodicalIF":0.0,"publicationDate":"2020-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1016/j.upstre.2020.100019","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"93649484","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}
Formation damage resulting from organic and inorganic depositions, such as calcium carbonate, asphaltene and paraffin, is one of the most commonly encountered types of damage in the oil and gas industry. These depositions are usually associated with a decrease in crude productivity, accelerated failure of production equipment, such as electrical submersible pumps (ESPs), and less footage covered while running with production and flow profile logging tools. Therefore, formation damage and in particular organic deposits should be analyzed and complete testing should be performed to increase the productivity and ensure smooth operations.
This paper presents a comprehensive analysis procedure for heavy organic sample deposits collected from wells located in one of the oilfields in Saudi Arabia. The samples were collected from different sources such as production logging tools, pulling out a failed ESP, and lowering completion equipment. The hydrocarbon phase was removed by organic solvent and the precipitated solid materials were collected for a lab analysis and solubility test. An identification and evaluation of the organic deposit compositions were investigated using SARA analysis and coreflood techniques. Organic solvents are used to replace the aromatic ones in order to minimize the toxicity and health concerns.
Several testing techniques were used for better understanding of the collected samples including thermogravimetric analysis (TGA) and X-ray diffraction (XRD). The TGA was used to determine the rate of thermal decomposition and measure and change in weight of the samples. Three temperatures were used, 180 °C, 550 °C, and 990 °C and the total weight loss values ranged from 19 to 66 wt% except for the oriental sample, which showed a 71%. The XRD was used to identify the complete structure of the samples and found that they are mainly carbonate of Calcite and Halite in which can be removed by acids like 15 wt% of HCI at reservoir conditions. A small fraction of dolomites, quartz, microcline, chlorite, and illite were identified as well. Static and dynamic solubility tests were performed with more solids observed in the static one. Two different soaking times: 3 and 24 h at both room temperature and 50 °C were implemented using 1:10 ratio of weight to solvent. The samples were found to be purely organic with between 20% and 60% asphaltene content. The performance of the solvents was negatively affected by the soaking time and better to be limited to 3–5 h.
{"title":"Heavy organic deposit comprehensive analysis and testing techniques","authors":"Abdulaziz Al-Qasim, Fahad Almudairis, Mutaz Alsubhi","doi":"10.1016/j.upstre.2020.100021","DOIUrl":"10.1016/j.upstre.2020.100021","url":null,"abstract":"<div><p>Formation damage resulting from organic and inorganic depositions, such as calcium carbonate<span>, asphaltene and paraffin, is one of the most commonly encountered types of damage in the oil and gas industry<span>. These depositions are usually associated with a decrease in crude productivity, accelerated failure of production equipment, such as electrical submersible pumps (ESPs), and less footage covered while running with production and flow profile logging tools. Therefore, formation damage and in particular organic deposits should be analyzed and complete testing should be performed to increase the productivity and ensure smooth operations.</span></span></p><p>This paper presents a comprehensive analysis procedure for heavy organic sample deposits collected from wells located in one of the oilfields in Saudi Arabia. The samples were collected from different sources such as production logging tools, pulling out a failed ESP, and lowering completion equipment. The hydrocarbon phase was removed by organic solvent and the precipitated solid materials were collected for a lab analysis and solubility test. An identification and evaluation of the organic deposit compositions were investigated using SARA analysis and coreflood techniques. Organic solvents are used to replace the aromatic ones in order to minimize the toxicity and health concerns.</p><p><span><span><span>Several testing techniques were used for better understanding of the collected samples including thermogravimetric analysis (TGA) and X-ray diffraction (XRD). The TGA was used to determine the rate of </span>thermal decomposition and measure and change in weight of the samples. Three temperatures were used, 180 °C, 550 °C, and 990 °C and the total weight loss values ranged from 19 to 66 wt% except for the oriental sample, which showed a 71%. The XRD was used to identify the complete structure of the samples and found that they are mainly carbonate of </span>Calcite<span> and Halite in which can be removed by acids like 15 wt% of HCI at reservoir conditions. A small fraction of dolomites, quartz, </span></span>microcline<span><span>, chlorite, and illite were identified as well. Static and dynamic solubility tests were performed with more solids observed in the static one. Two different soaking times: 3 and 24 h at both room temperature and 50 °C were implemented using 1:10 ratio of weight to solvent. The samples were found to be purely organic with between 20% and 60% </span>asphaltene content. The performance of the solvents was negatively affected by the soaking time and better to be limited to 3–5 h.</span></p></div>","PeriodicalId":101264,"journal":{"name":"Upstream Oil and Gas Technology","volume":"5 ","pages":"Article 100021"},"PeriodicalIF":0.0,"publicationDate":"2020-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1016/j.upstre.2020.100021","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"103042253","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}
Pub Date : 2020-10-01DOI: 10.1016/j.upstre.2020.100011
Fadhil S. Kadhim , Salam Al-Rbeawi , Ghanim M. Farman
The motivation is eliminating the uncertainties in predicting reservoir performance, and reducing the errors in the reservoir characterization resulted by neglecting the impact of non-Darcy flow. In this study, an analytical multi-linear flow regimes model has been developed for pressure distribution in hydraulically fractured reservoirs and modified for the existence of non-Darcy flow by introducing the rate-dependent skin factor to the flow equations. This model is solved for different impacts of non-Darcy flow by assuming a constant flow rate and different non-Darcy flow coefficients. The effects of different cross-section areas of flow inside hydraulic fractures on the non-Darcy flow coefficient are considered in this study as well as different fracture conductivities. Reservoir configurations and petrophysical properties are also considered in calculating pressure distributions. Analytical models for hydraulic fracture linear flow regime, bi-linear flow regime, and boundary-dominated flow regime are developed based on pressure responses for different non-Darcy flow impact. Analytical models for transient and pseudo-steady state productivity indices are presented in this paper to demonstrate the impact of non-Darcy flow on these indices. The results of this study showed there are considerable effects of non-Darcy flow on reservoir performance and developed analytical mathematical models for recognized flow regimes which observed during reservoir production period. Additionally, results illustrated the reservoir configurations and petrophysical properties may not have significant contribution in developing non-Darcy flow. Finally, the productivity index has been sharply declined for later production time. Meanwhile, it is constant for high rate-dependent skin factors at the early time of production.
{"title":"Integrated approach for non-Darcy flow in hydraulic fractures considering different fracture geometries and reservoir characteristics","authors":"Fadhil S. Kadhim , Salam Al-Rbeawi , Ghanim M. Farman","doi":"10.1016/j.upstre.2020.100011","DOIUrl":"10.1016/j.upstre.2020.100011","url":null,"abstract":"<div><p>The motivation is eliminating the uncertainties in predicting reservoir performance, and reducing the errors in the reservoir characterization<span> resulted by neglecting the impact of non-Darcy flow. In this study, an analytical multi-linear flow regimes model has been developed for pressure distribution in hydraulically fractured reservoirs and modified for the existence of non-Darcy flow by introducing the rate-dependent skin factor to the flow equations. This model is solved for different impacts of non-Darcy flow by assuming a constant flow rate<span> and different non-Darcy flow coefficients. The effects of different cross-section areas of flow inside hydraulic fractures on the non-Darcy flow coefficient are considered in this study as well as different fracture conductivities. Reservoir configurations and petrophysical properties are also considered in calculating pressure distributions. Analytical models for hydraulic fracture linear flow regime, bi-linear flow regime, and boundary-dominated flow regime are developed based on pressure responses for different non-Darcy flow impact. Analytical models for transient and pseudo-steady state productivity indices are presented in this paper to demonstrate the impact of non-Darcy flow on these indices. The results of this study showed there are considerable effects of non-Darcy flow on reservoir performance and developed analytical mathematical models for recognized flow regimes which observed during reservoir production period. Additionally, results illustrated the reservoir configurations and petrophysical properties may not have significant contribution in developing non-Darcy flow. Finally, the productivity index has been sharply declined for later production time. Meanwhile, it is constant for high rate-dependent skin factors at the early time of production.</span></span></p></div>","PeriodicalId":101264,"journal":{"name":"Upstream Oil and Gas Technology","volume":"5 ","pages":"Article 100011"},"PeriodicalIF":0.0,"publicationDate":"2020-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1016/j.upstre.2020.100011","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"104895692","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}