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Collaborating Authors
Results
Transport and Plugging Performance Evaluation of a Novel Re-Crosslinkable Microgel Used for Conformance Control in Mature Oilfields with Super-Permeable Channels
Alotibi, Adel (Kuwait Institute for Scientific Research / Department of Geosciences and Geological and Petroleum Engineering, Missouri University of Science and Technology) | Song, T. (Department of Geosciences and Geological and Petroleum Engineering, Missouri University of Science and Technology) | Bai, Baojun (Department of Geosciences and Geological and Petroleum Engineering, Missouri University of Science and Technology) | Schuman, T. P. (Department of Chemistry, Missouri University of Science and Technology)
Abstract Preformed particle gels (PPG) have been widely applied in oilfields to control excessive water production. However, PPG has limited success in treating opening features because the particles can be flushed readily during post-water flooding. We have developed a novel micro-sized Re-crosslinkable PPG (micro-RPPG) to solve the problem. The microgel can re-crosslink to form a bulk gel, avoiding being washed out easily. This paper evaluates the novel microgelsโ transport and plugging performance through super-permeable channels. Micro-RPPG was synthesized and evaluated for this study. Its storage moduli after fully swelling are approximately 82 Pa. The microgel characterization, self-healing process, transportation behavior, and plugging performance were investigated. A sandpack model with multi-pressure taps was utilized to assess the microgel dispersionsโ transport behavior and plugging efficiency. In addition, micro-optical visualization of the gel particles was deployed to study the particle size changes before and after the swelling process. Tube tests showed that micro-RPPG could be dispersed and remain as separate particles in water with a concentration below 8,000 ppm, which is a favorable concentration for gel treatment. However, during the flooding test, the amount of microgel can be entrapped in the sandpack, resulting in a higher microgel concentration (higher than 8,000 ppm), endowing the gel particles with re-crosslinking ability even with excessive water. The microgel could propagate through the sandpack model, and the required pressure gradient mainly depends on the average particle/pore ratio and gel concentration. The gel dispersion significantly reduced channel permeability, providing sufficient resistance to post-water flooding (more than 99.97 % permeability reduction). In addition, the evaluation of micro-RPPG retention revealed that it is primarily affected by both gel concentration particle/pore ratios. We have demonstrated that the novel re-crosslinkable microgel can transport through large channels, but it can provide effective plugging due to its unique re-crosslinking property. However, by this property, the new microgel exhibits enhanced stability and demonstrates resistance to being flushed out in such high-permeability environments. Furthermore, with the help of novel technology, it is possible to overcome the inherited problems commonly associated with in-situ gel treatments, including chromatographic issues, low-quality control, and shearing degradation.
- North America > United States (0.46)
- Asia > China (0.28)
Experimental Study: Investigating the Anions and Cationsโ Effects on the Elasticity of the Anionic and Cationic High Viscosity Friction Reducers
Ge, Xiaojing (Missouri University of Science and Technology) | Biheri, Ghith (Missouri University of Science and Technology) | Imqam, Abdulmohsin (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology) | Zhang, Yuwei (Missouri University of Science and Technology)
Abstract High viscosity friction reducers (HVFRs) are widely used as friction-reducing agents and proppant carriers during hydraulic fracturing. The reuse of produced water has gained popularity due to environmental and economic benefits. Currently, the fieldโs most commonly used friction reducers are anionic and cationic HVFRs. Anionic HVFRs are typically pumped with freshwater, while cationic HVFRs are used with high Total Dissolved Solids (TDS) produced water. Cationic friction reducers are believed to have better TDS tolerance, friction reduction performance, and proppant transport capabilities compared to anionic friction reducers under high TDS conditions due to their superior viscoelastic properties. In addition, the impact of different anions and cations on the viscosity of HVFRs has been thoroughly studied, and viscosity reduction mechanisms include charge shielding, increasing the degree of hydrolysis, and forming coordination complexes. However, anions and cationsโ effects on the elasticity of HVFRs still remain to be investigated. Besides, most previous experimental studies either do not specify experimental procedures or control the experimental variables well. Therefore, the ultimate objective of this experimental study is to analyze various cations and anionsโ effects on the elasticity of anionic and cationic HVFRs comparably and precisely with experimental variables well controlled. Two hypotheses based on anions and cationsโ effects on the viscosity of HVFRs are proposed and will be tested in this study. First, the elasticity reduction of anionic HVFRs is mainly due to cations, whereas the elasticity reduction of cationic HVFRs is mainly due to anions. Second, the saltsโ effects on the elasticity reduction of HVFRs should follow the same trend as the saltsโ effects on the viscosity reduction of HVFRs. For anionic HVFRs, monovalent Alkali metals should have a similar effect; divalent Alkaline earth metals should have a similar effect; transition metals should have the most severe effect. For cationic HVFRs, SO4 should have more pronounced effects than Cl. To demonstrate both hypotheses, an anionic and a cationic HVFR at 4 gallons per thousand gallons (GPT) were selected and analyzed. The elasticity measurements of both anionic and cationic HVFRs were conducted with deionized (DI) water and various salts respectively. Fe and H (or pH) effects were specifically investigated. The results showed both hypotheses were accepted.
- North America > United States > Pennsylvania (0.47)
- North America > United States > Ohio (0.46)
- North America > United States > West Virginia (0.28)
- North America > United States > New York (0.28)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.90)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (4 more...)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Well Intervention (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (0.89)
The Success Story of First Ever Polymer Flood Field Pilot to Enhance the Recovery of Heavy Oils on Alaska's North Slope
Dandekar, Abhijit (University of Alaska Fairbanks) | Bai, Baojun (Missouri University of Science and Technology) | Barnes, John (Hilcorp Alaska LLC) | Cercone, Dave (DOE-National Energy Technology Laboratory) | Edwards, Reid (Hilcorp Alaska LLC) | Ning, Samson (Reservoir Experts, LLC/Hilcorp Alaska, LLC) | Seright, Randy (New Mexico Institute of Mining and Technology) | Sheets, Brent (University of Alaska Fairbanks) | Wang, Dongmei (University of North Dakota) | Zhang, Yin (University of Alaska Fairbanks)
Abstract The primary goal of the first ever polymer flood field pilot at Milne Point is to validate the use of polymers for heavy oil Enhanced Oil Recovery (EOR) on Alaska North Slope (ANS). The specific objectives are systematic evaluation of advanced technology that integrates polymer flooding, low salinity water flooding, horizontal wells, and numerical simulation based on polymer flood performance data. Accordingly, under the co-sponsorship of the US Department of Energy and Hilcorp Alaska LLC the first ever polymer field pilot commenced on August 28, 2018 in the Schrader Bluff heavy oil reservoir at the Milne Point Unit (MPU) on ANS. The pilot started injecting hydrolyzed polyacrylamide (HPAM), at a concentration of 1,750 ppm to achieve a target viscosity of 45 cP, into the two horizontal injectors in the J-pad flood pattern. Since July 2020, HPAM concentration was reduced to 1,200 ppm to control injectivity and optimize polymer utilization. Filter ratio tests conducted on site ensure uniform polymer solution properties. Injectivity is assessed by Hall plots, whereas production is monitored via oil and water rates from the two producers. Water samples are analyzed to determine the produced polymer concentration. Supporting laboratory corefloods on polymer retention, injection water salinity, polymer loading, and their combinations on oil recovery, match rock, fluid and test conditions. A calibrated and validated numerical multiphase reservoir model was developed for long-term reservoir performance prediction and for evaluating the project's economic performance in conjunction with an economic model. Concerns related to handling of produced fluids containing polymer are addressed by specialized experiments. As would be expected in a field experiment of this scale, barring some operational and hydration issues, continuous polymer injection has been achieved. As of September 30, 2022, a total of 1.41 million lbs of polymer or 2.99 million bbls of polymer solution (~18.8% of total pore volume), placed in the pattern serves as an effective indicator of polymer injectivity. During the first half of the pilot period, water cut (WC) drastically reduced in both producers and over the entire duration, the deemed EOR benefit over waterflood was in the range of 700-1,000 bopd, and that too at a low polymer utilization of 1.7 lbs/bbl. Low concentration polymer breakthrough was observed after 26-28 months, which is now stabilized at 600โ800 ppm in congruence with the WC. Although as indicated by laboratory experiments, polymer retention in core material is high; ~70% of the injected polymer propagates without any delay, while the remaining 30% tails over several PVs. History matched simulation models consistently forecasts polymer recovery of 1.5โ2 times that of waterflood, and when integrated with the economic modeling tool, establish the economic profitability of the first ever polymer flood field pilot. Produced fluid experiments provide operational guidance for treating emulsions and heater-treater operating temperature. Over a duration of ~4.5 years important outstanding technical issues that entail polymer flooding of heavy oils have been resolved, which forms the basis of the success story summarized in the paper. The first ever polymer pilot is deemed as a technical and economic success in significantly improving the heavy oil recovery on ANS. The pilot has provided impetus to not only apply polymer EOR throughout the Milne Point Field, but has paved the way for additional state-funded research targeting even heavier oils on the ANS. The combined success of this work and the future work will contribute to the longevity of the Trans Alaska Pipeline System (TAPS).
- Europe > United Kingdom > North Sea > Central North Sea (1.00)
- North America > United States > Alaska > North Slope Borough > Prudhoe Bay (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.87)
- North America > United States > Alaska > Schrader Bluff Formation (0.99)
- North America > United States > Alaska > North Slope Basin > Milne Point Field > Kuparuk Formation (0.99)
- North America > Canada > Alberta > Flood Field > Adamant Masters Flood 6-6-85-24 Well (0.99)
Synthesis and Application of a Low Formation Damage Clay Stabilizer
Liang, Lei (China University of Petroleum, East China) | Wang, Yanling (China University of Petroleum, East China) | Liu, Bin (China University of Petroleum, East China) | Li, Yongfei (China University of Petroleum, East China) | Tang, Longhao (China University of Petroleum, East China) | Bai, Baojun (Missouri University of Science and Technology) | Zhang, Ye (National Joint Engineering Research Center for Shale Gas Exploration and Development, Chongqing Institute of Geology & Mineral Resources)
Abstract To develop a low formation damage clay stabilizer, a kind of organic polyether amine clay stabilizer (OPACS) was synthesized. Compared with the commercial clay stabilizers, the application performance of the OPACS was investigated. OPACS was synthesized with 1, 2-propanediol, 2-(chloromethyl)oxirane and ammonia as main raw materials. The molecular structure of OPACS were characterized by FTIR and NMR, and its anti-swelling performance was tested by centrifugation. Other performance, including its temperature resistance, acid and alkali resistance, elution resistance and etc., were also researched. Different permeability cores were used to test the formation damage of OPACS, and its anti-swelling mechanism was studied by SEM. The FTIR and NMR spectra showed that the expected product structure was synthesized. When the clay stabilizer was adding with 2.0 wt.%, the anti-swelling rate of OPACS was over 90% which was better than the commercial clay stabilizers (about 80%) we bought. At the temperature range of 20 ยฐC-120 ยฐC and the pH range of 2-12, the anti-swelling rate of OPACS changed less than 2.5%. In the long-term efficacy test, the elution recovery rate of OPACS was higher than 92% within the concentration between 0.5 wt.%-3.0 wt.%. Natural cores with different permeability were selected for core flow experiments. The test results showed that the permeability recovery rate of cores were more than 95% treated with OPACS, which meant the formation damage value was less than 5%. From the SEM of clay treated with different clay stabilizers, we could find out the structure of clay treated with OPACS was more compact than those treated with other stabilizers we bought. These results have shown that OPACS can effectively inhibit the water absorption swelling of clay and recovery formation damage, which are helpful to the EOR and friendly to the environment.
- Asia > Middle East (0.47)
- North America > United States (0.46)
- Asia > China (0.29)
- South America > Brazil (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.49)
- Well Drilling > Formation Damage (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Downhole chemical treatments and fluid compatibility (1.00)
A Novel Branched Polymer Gel System with Delayed Gelation Property for Conformance Control
Song, Tao (Missouri University of Science and Technology) | Feng, Qi (China University of Petroleum (East China)) | Schuman, Thomas (Missouri University of Science and Technology) | Cao, Jie (China University of Petroleum (East China)) | Bai, Baojun (Missouri University of Science and Technology (Corresponding author))
Summary Excessive water production from oil reservoirs not only affects the economical production of oil, but it also results in serious environmental concerns. Polymer gels have been widely applied to decrease water production and thus improve oil production. However, traditional polymer gels such as partially hydrolyzed polyacrylamide (HPAM)/chromium (III) gel systems usually have a short gelation time and cannot meet the requirement of some conformance control projects. This paper introduces a novel polymer gel system of which crosslinking time can be significantly delayed. A branched polymer grafted from arginine by the surface initiation method is synthesized as the backbone, chromium acetate is used as the crosslinker, and no additional additives are used for the gel system. The results show that the gelation time of this system can be delayed to 61โdays at 45ยฐC and 20โdays at 65ยฐC because of the rigid structure of the branched polymer and the excellent chromium (III) chelating ability of arginine. The polymer gels have been stable for more than 150โdays at 45 and 65ยฐC. Coreflooding and rheology tests have demonstrated that this branched polymer has good injectivity and shear resistance in high-permeability rocks.
- Asia (0.93)
- North America > United States > Oklahoma (0.29)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Downhole chemical treatments and fluid compatibility (1.00)
Impact of Polymer Rheology on Gel Treatment Performance of Horizontal Wells with Severe Channeling
Leng, Jianqiao (Missouri University of Science and Technology (Corresponding author)) | Wei, Mingzhen (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology)
Summary Gel treatment has been a cost-effective method to control the conformance of a reservoir with severe heterogeneity problems. The water channels in such reservoirs can be classified as open fractures or high permeability porous media with pore-throat network. Many simulation studies have been conducted to discuss gel treatment performance for conformance control. However, nobody considered the polymer rheology difference in open fractures and porous media in simulation. Previous simulation studies also ignored the residual resistance factor as a function of rock permeability rather than a constant parameter. In this study, a conceptual simulation model was established to simulate the linear flow system for the reservoir with horizontal wells considering the two factors mentioned above. The results demonstrate that the gel treatment always provides the better placement results in the open fracture type channel than pore-throat network type channel. Moreover, it is very necessary to consider residual resistance factor as a function of permeability, which is based on the experimental results and can provide much greater plugging efficiency in the higher permeable channels than constant residual resistance factor. Sensitivity analysis studies and multifactor analysis indicate that increasing oil viscosity and permeability ratio has a strong positive influence on conformance control results, which indicate in-situ gel treatment can be better applied in heavy or viscous oil reservoirs with fracture-like channels. Besides, the results also indicate that in reservoirs with severe channeling problem where channel velocity was high, the differences of gelant placement and profile improvement in models with two different types of channels could be enlarged greatly.
- North America > United States > Texas (0.46)
- North America > United States > Oklahoma (0.29)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
A Novel Branched Polymer Gel System with Delayed Gelation Property for Conformance Control
Song, Tao (Missouri University of Science and Technology) | Feng, Qi (China University of Petroleum (East China)) | Schuman, Thomas (Missouri University of Science and Technology) | Cao, Jie (China University of Petroleum (East China)) | Bai, Baojun (Missouri University of Science and Technology (*Corresponding author)
Summary Excessive water production from oil reservoirs not only affects the economical production of oil, but it also results in serious environmental concerns. Polymer gels have been widely applied to decrease water production and thus improve oil production. However, traditional polymer gels such as partially hydrolyzed polyacrylamide (HPAM)/chromium (III) gel systems usually have a short gelation time and cannot meet the requirement of some conformance control projects. This paper introduces a novel polymer gel system of which crosslinking time can be significantly delayed. A branched polymer grafted from arginine by the surface initiation method is synthesized as the backbone, chromium acetate is used as the crosslinker, and no additional additives are used for the gel system. The results show that the gelation time of this system can be delayed to 61โdays at 45ยฐC and 20โdays at 65ยฐC because of the rigid structure of the branched polymer and the excellent chromium (III) chelating ability of arginine. The polymer gels have been stable for more than 150โdays at 45 and 65ยฐC. Coreflooding and rheology tests have demonstrated that this branched polymer has good injectivity and shear resistance in high-permeabilityrocks.
- Asia (0.93)
- North America > United States > Oklahoma (0.29)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Downhole chemical treatments and fluid compatibility (1.00)
The aim of this study is to examine the effect of a novel combination that consists of polymeric nanogel and surfactant on oil recovery. The paper will report the extent to what the nanogel, alone and combined with surfactant, can improve oil recovery for sandstone reservoirs and reveal the mechanisms behind it. A negatively charged nanogel was synthesized using a typical free radical suspension polymerization process by employing 2-acrylamido-2-methyl propane sulfonic acid monomer. In addition, a fixed concentration of negatively charged surfactant (sodium dodecyl sulfate or SDS) was combined with different concentrations of the nanogel using seawater. The combination effect on sandstone core plugs was examined by running a series of core flooding experiments using multiple flow schemes. The synthesized nanogels showed a narrow size distribution with one peak pointing to a predominant homogeneous droplet size. They were also able to adsorb at the oil-water interfaces to reduce interfacial tension and stabilize oil-in-water emulsions, which ultimately improved the recovered oil from hydrocarbon reservoirs. The results suggest the ability of the nanogel, both alone and combined with SDS, to improve the oil recovery by a factor of 15% after initial seawater flooding. Although nanoparticles have received a great attention in the research aspect of the oil industry, however, the characterization of polymeric nanogels, alone and combined with other additives, is still to be investigated. Due to their unique properties and mechanisms, nanogels have a great potential for application in the oil industry. This study is aimed to examine and evaluate the combination of charged polymeric nanogel and surfactant dispersed in seawater through core flooding experiments using multiple injection schemes.
- North America > United States (0.48)
- Asia > Middle East > Saudi Arabia (0.28)
- Research Report > New Finding (0.88)
- Research Report > Experimental Study (0.68)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Core analysis (0.91)
Combining Preformed Particle Gel and Curable Resin-Coated Particles To Control Water Production from High-Temperature and High-Salinity Fractured Producers
Sun, Lin (Southwest Petroleum University) | Li, Daibo (Southwest Petroleum University) | Pu, Wanfen (Southwest Petroleum University) | Li, Liang (Northwest Oilfield Company) | Bai, Baojun (Missouri University of Science and Technology) | Han, Qi (Southwest Petroleum University) | Zhang, Yongchang (Southwest Petroleum University) | Tang, Ximing (Southwest Petroleum University)
Summary Preformedโparticleโgel (PPG) treatments have been successfully used in injection wells to reduce excessive water production from highโtemperature, highโsalinity fractured reservoirs. However, PPG itself cannot be used in fractured producers because it tends to wash out after the wells resume production. Therefore, we proposed to combine curable resinโcoated particles (CRPs) with PPG to control water production from fractured producers. In this paper, millimeterโsized tubes and fractured carbonate cores were designed to comprehensively investigate waterโplugging behaviors of the combined system under the conditions of various fracture parameters and PPG/CRP sizes. Particular attention was given to control the PPG washout after production was resumed. The results showed the cured CRPs could generate immobile packs in fractures and dramatically mitigate the PPG washout. The small size of the CRPs and the small ratio of CRP size to tube diameter contributed low permeability and homogeneity to CRP packs. Meanwhile, the lessโpermeable and moreโhomogeneous CRP pack, as well as the largerโsized PPGs, contributed to a higher PPG breakthrough pressure gradient. Moreover, some of the PPG particles blocked in the CRP packs could be released through highโspeed brine injection from producers, which indicated the recoverability of the water plugging. This study provides a promising approach to reduce the highโwaterโcut problem in fractured producers.
- Asia (1.00)
- North America > United States > Oklahoma (0.47)
- North America > United States > Texas (0.28)
- North America > United States > Texas > Fort Worth Basin > Northwest Field (0.99)
- Asia > China > Henan > North China Basin > Zhongyuan Field (0.99)
- North America > United States > Louisiana > China Field (0.98)
Predicting Mean Time to Failure in Horizontal Wells through Metal Loss Analysis and Produced Water Composition
Ofori, Bruce Agyapong (Missouri University of Science and Technology) | Wei, Mingzhen (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology) | Al-Kamil, Ethar Hisham (University of Basrah)
Abstract Loss of well integrity in many horizontal wells in the United States has resulted in huge capital losses to several operating companies. The occurrence of corrosion in horizontal wells in the US is attributed to several reasons. The deposition of iron (Fe) and manganese (Mn) from manufactured steel pipe and the inability to effectively treat the laterals plays a major role in corrosion mitigation in horizontal wells. Corrosion inhibitors are injected into the wells to help reduce the corrosion rates, however the effectiveness of these injection applications is hampered by the types of well design and fluid dynamics. Loss of Fe/Mn in the lateral sections of the well is a major concern for the oil industry. This research will investigate the amounts of Fe/Mn contributions from the laterals and also investigate the relationship between iron and manganese counts from produced water from oil fields in the US. This research will further investigate the mean time to failure in the laterals and suggest proactive plans for mitigating failures based on findings. High Fe/Mn concentrations could lead to corrosion in producing wells. High densities of Fe/Mn found in produced water analysis reports has been attributed to the abundance of these two elements used in manufactured steel pipe. These elements are used due to their abundance in manufactured steel pipe and their lack of natural presence in formation fluids. Fe and Mn have a known ratio in steel pipe of approximately 100:1 (depending on steel type). These high concentrations could ultimately compromise the wells integrity. This research emphasizes the need for considering iron and manganese counts as integral part of the corrosion monitoring. Moreover, considering the long lateral casings, which spans several thousands of feet in the US, injection of corrosion inhibitors will be ineffective in reducing Fe and Mn loss in the lateral sections. Monitoring of Fe and Mn over such long laterals is challenging and costly. It has therefore become crucial for oil companies to thoroughly understand the Fe/Mn contribution from the laterals that could lead to corrosion and develop mitigation strategies to lower corrosion rates in such high-risk wells. This will help to implement remedial measures to better define corrosion rates and quantify the risk of failure. This will also enable oil companies allocate resources for further development and not several remediation efforts.
- Asia > Middle East > Saudi Arabia > Saudi Arabia - Kuwait Neutral Zone ("Partitioned Zone") > Arabian Basin > Widyan Basin > Wafra Joint Operations Block > Wafra Field (0.99)
- Asia > Middle East > Kuwait > Saudi Arabia - Kuwait Neutral Zone ("Partitioned Zone") > Arabian Basin > Widyan Basin > Wafra Joint Operations Block > Wafra Field (0.99)
- Asia > Middle East > UAE > Abu Dhabi > Arabian Gulf > Rub' al Khali Basin > Ghasha Concession > Umm Shaif and Nasr Block > Umm Shaif and Nasr Field > Umm Shaif Field > Arab Formation (0.97)