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Collaborating Authors
Iwama, Hiroki
Abstract Asphaltenes in the production process often cause significant damage to oil production operation through the continuous growth process (precipitation followed by aggregation and finally deposition) of their particles. To mitigate the asphaltene-induced problems, Asphaltene Inhibitor is used to control precipitation and/or deposition of asphaltene particles. In addition to the typical ambient-conditioned Asphaltene Inhibitor-evaluation known as Asphaltene Dispersancy Test, this study applied the Dynamic Asphaltene Inhibitor Test to select candidate Asphaltene Inhibitors at operating conditions. The Dynamic Asphaltene Inhibitor Test used a simple dynamic flow equipment consisting of capillary coil and filter to detect asphaltene precipitation and deposition independently. Based on Asphaltene Inhibitors experimentally screened through a series of Dynamic Asphaltene Inhibitor Test, four Asphaltene Inhibitor numerical models were reproduced to assess how Asphaltene Inhibitors mitigating asphaltene risks. A numerical model assuming no Asphaltene Inhibitor was built as reference by calibrating with conventional Pressure Volume Temperature (PVT) experimental results and asphaltene onset pressure. Asphaltene Inhibitor models were generated from the reference model on the basis of comprehensively interpreted data containing available Asphaltene Inhibitor characteristic information. In the Asphaltene Inhibitor models, pseudo heavy components of the crude oil used in Dynamic Asphaltene Inhibitor Test were characterized with cubic-plus-association equation of state. The Asphaltene Inhibitor models were validated by comparing with the relative Asphaltene Inhibitor's effectiveness in experimental evaluation. To understand transition from Asphaltene Precipitation Envelopes to Asphaltene Deposition Envelope, the findings of deposition-information from the Dynamic Asphaltene Inhibitor Test were incorporated into the Asphaltene Inhibitor models. To be more specific, the deposition behavior was estimated on thermodynamic plot by assuming the Dynamic Asphaltene Inhibitor Test condition as pseudo onset condition. The Asphaltene Precipitation Envelopes on thermodynamic plots revealed causing asphaltene precipitation possibly in part of the operation conditions even using Asphaltene Inhibitor. On the other hand, Asphaltene Deposition Envelope suggested that Asphaltene Inhibitor application could reduce asphaltene deposition over a wide range of the operation condition. The upper-boundary locations of Asphaltene Precipitation Envelopes and Asphaltene Deposition Envelope were apart from each other. The fact revealed that Asphaltene Inhibitor could delay asphaltene aggregation and deposition after precipitation. This paper describes a more realistic Asphaltene Inhibitor modeling method based on the Dynamic Asphaltene Inhibitor Test measurement results.
- North America > United States (0.68)
- Asia > Middle East > UAE (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.95)
Abstract Full field production profile is needed to evaluate enhanced oil recovery (EOR) option and to progress the EOR project. In general, the methodology of full-field profile estimation highly depends on the objective case: field development maturity level, technology readiness level of the EOR option to be planned, etc. Therefore, this paper is facilitating how we should select an adequate methodology to estimate full-field EOR profiles through comparison of four case studies. Case-1 was picked up as an example of type curve method based on sector models for water alternating gas (WAG) application using CO2 or hydrocarbon miscible gas. Case-2 represented a full-field simulation approach to incorporate facility capacities into account adequately because of produced gas re-injection (i.e. gas EOR). Case-3 demonstrated to use the identical flow model, which was history-matched with long production records, for estimating a new CO2 foam EOR technology which was unavailable as option in the identical commercial simulator. The last Case-4 dealt an emerging microbial EOR/EGR process without any commercial simulator and no pilot data yet. In Case-1, two type curves were generated to represent typical geologies in the objective field: homogeneous and heterogeneous areas. After sensitivity studies using the simple sector models to optimize each parameter, type curves were obtained from the detailed sector models. The type curves, assigned in corresponding areas, were summed to estimate full-field profile. In Case-2, even full-field simulation is debatable in general due to huge workload and computation, it still has important role to evaluate gas EOR with limited gas processing capacity because to ignore the facility limits might mislead to optimistic conclusion. In Case-3 in the mature field, the history-matched model was already established by a commercial simulator. Unfortunately, the simulator does not have an exact option to evaluate our emerging CO2 foam technology while available for the conventional foam EOR using surfactant as foaming agent. Thus, we managed to handle our EOR technology by matching laboratory experimental outputs with pseudo-calculated gas mobility reduction ratio. In Case-4, another emerging microbial EOR technique was estimated analytically even only laboratory experimental data was available. Any commercial simulator is not available, either. The unique approach took essence of experimental outputs into a well type curve, and then full-field profile was estimated. Each workflow has pros/cons, and an adequate one should be selected. However, in usual, a unique workflow is just applied to estimate full-field profile in the evaluation of objective EOR option. Furthermore, there has been little discussion of workflow selections from the aspect of development stage, EOR technological emerging level, and evaluation tool availability. This paper can provide ideas to consider guidelines for generating full-field profiles.
- North America > United States (1.00)
- Europe (1.00)
- Asia > Middle East (1.00)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Wara Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Ratawi Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Mauddud Formation (0.99)
- (4 more...)
Distribution Mechanism of Asphaltene Deposits in CO2 Flooding Path: Interpretation by Numerical Model Based on Experimental Observation
Yonebayashi, Hideharu (INPEX CORPORATION) | Iwama, Hiroki (INPEX CORPORATION) | Takabayashi, Katsumo (INPEX CORPORATION) | Miyagawa, Yoshihiro (INPEX CORPORATION) | Watanabe, Takumi (INPEX CORPORATION)
Abstract CO2 injection is one of widely applied enhanced oil recovery (EOR) techniques, moreover, it is expected to contribute to the climate change from a viewpoint of storing CO2 in reservoir. However, CO2 is well known to accelerate precipitating asphaltenes which often deteriorate production. To understand in-situ asphaltene-depositions, unevenly distributed in composite carbonate core during a CO2 flood test under reservoir conditions, were investigated through numerical modelling study. Tertiary mode CO2 core flood tests were performed. A core holder was vertically placed in an oven to maintain reservoir temperature and to avoid vertical segregation. A composite core consisting of four ร1.5" ร L2.75" plug cores, which had similar porosity range but slightly varied air permeabilities, was retrieved from a core holder after the flooding test. The remaining hydrocarbon was extracted by Dean-stark method, and heptane insoluble materials were extracted from each plug core via IP-143 method to observe distribution of asphaltene deposits. The variation of asphaltene mass in plug cores was investigated to explain its mechanism thermodynamically. The core flood test was completed to achieve a certain additional oil recovery by 15 pore volume CO2 injection without any unfavorable differential pressure. The remaining asphaltene mass in each plug core revealed a trend in which more asphaltene collected from the inlet-side core. We assumed a scenario to explain the uneven asphaltene distribution by incorporating the vaporized-gas-drive and CO2 condensing mechanism. Namely, asphaltenes deposited immediately when pure CO2 contacted with oil. The contact between more pure CO2 and oil might be more frequently occurred in inlet-side core. To reproduce the scenario, a cubic-plus-association (CPA) model was generated to estimate asphaltene precipitating behavior as injected gas composition varied. In the first plug core, more pure CO2 gas was considered to contact with fresh reservoir oil compared with the downstream cores which might have less pure CO2 because of its condensation. The light-intermediate hydrocarbon gas vaporized by CO2 was also considered to emphasize the trend of more asphaltene deposits in upstream-side cores. The CPA model revealed consistent phenomenon supporting the scenario.
- Asia > Middle East > UAE (0.29)
- North America > United States > Oklahoma (0.28)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Mission Canyon Formation (0.99)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Madison Formation (0.99)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Forbisher Formation (0.99)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Charles Formation:Middale Formation (0.99)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
A Novel Efficient Solution to Isolate Cross Communicating Reservoirs and Delay Water Advance without Impacting Well's Workover/Drilling Duration: Case Studies from Giant Offshore Field in Abu Dhabi
Elfeky, Mohamed Helmy (Abu Dhabi Marine Operating Co.) | Al-Neaimi, Ahmed (Abu Dhabi Marine Operating Co.) | Yousef, Omar (Abu Dhabi Marine Operating Co.) | Al-Hosani, Ibrahim (Abu Dhabi Marine Operating Co.) | Iwama, Hiroki (Abu Dhabi Marine Operating Co.) | Farhan, Salman (Abu Dhabi Marine Operating Co.) | Seoud, Abouel (Abu Dhabi Marine Operating Co.) | Channa, Zohaib (Abu Dhabi Marine Operating Co.) | Khemissa, Hocine (Abu Dhabi Marine Operating Co.) | Khan, Muhammad Navaid (Abu Dhabi Marine Operating Co.)
Abstract Facing a well control issue while drilling multi reservoirs with different reservoir pressure is very common in oil field worldwide, each and every engineer who is involved in the operations is dealing with this issue on daily basis. However, if the unexpected high pressure is observed while drilling a matured reservoir with known pressure, it is always a challenge to identify the source of the problem and to define the efficient remedial action plan, without compromising the well deliverables. The case study presented in this paper is related to a workover of a well in a giant offshore field in Abu Dhabi, where abnormally high pressure encountered while drilling the reservoir section with little amount of flow into the wellbore. Identifying the source of discrepancy and to establish the mitigate plan without impacting Well's Workover/Drilling duration was a serious challenge. What made the situation more complicated was the high risk of water in the heel section of 6" horizontal drain, which was prone to shorten the well life significantly. This paper will introduce an efficient novel solution to use 4 ยฝ" casing liner in a certain configuration, consisting of the mechanical and the Swellable packers to cure the cross communicating reservoirs (source of abnormal high pressure); and isolate the risky heel section of the well, to extend well life without impacting the planned well duration. This work will also describe the process of identifying the source of pressure, selecting the most suitable well completion strategy to meet the well objectives successfully. Moreover, it will also shed some light on the need of using reservoir simulation technique to assess different well completion options. Finally, the paper will be concluded with methodology on how to save time and cost whilst changing plans to cope with the unforeseen issues.
Gas Injection Optimization in a Giant Offshore Carbonate Field and Impact on Field Development Plan. Case Study
Ahmad, Fazeel (ADMAโOPCO) | Sarsekov, Arlen (ADMAโOPCO) | Iwama, Hiroki (ADMAโOPCO) | Saif, Omar Yousaf (ADMAโOPCO) | Abed, Abdalla (ADMAโOPCO) | Al-Naeimi, Ahmed Khalifa (ADMAโOPCO)
Abstract Gas injection is a part of secondary recovery factor to improve reservoir sweep efficiency and recovery factor. However defining optimum gas injection rate in a multi layered heterogeneous carbonate reservoirs is a big challenge and any deviation from optimum gas injection rate can cause fast Gas Cap expansion or fast reservoir depletion. Proper dynamic synthesis of the multi layered reservoir was performed. Openhole logs and available cased hole logs were QCed and reinterpreted for better undestanding of fluid movement. Efficient gas injection rate for each string and balance between water injection and gas injection were evaluated. Gas tracers study was carried out by injecting gas tracers into gas injection wells. The results of the study were used for optimizing the gas injection strategy. As a result of overall gas injection optimization, a positive impact is observed on the total field gas production rate or total field GOR which has been reduced and many oil wells became active resulted in additional oil production gain.
The Performance of Water Injection Wells Equipped with ICD Completions in One of the Giant Offshore Field, Abu Dhabi
Channa, Zohaib (Abu Dhabi Marine Operating Co.) | Khan, Muhammad Navaid (Abu Dhabi Marine Operating Co.) | Iwama, Hiroki (Abu Dhabi Marine Operating Co.) | Husain, Ali (Abu Dhabi Marine Operating Co.) | Al-blooshi, Jamal R. (Abu Dhabi Marine Operating Co.) | El-Sayed, H. S. (Abu Dhabi Marine Operating Co.) | Nofal, Salman F. (Abu Dhabi Marine Operating Co.) | Al-feky, Mohamed H. (Abu Dhabi Marine Operating Co.) | Ahmed, Fazeel (Abu Dhabi Marine Operating Co.)
Abstract As a part of the effective reservoir management in commingled water injection wells crossing different formation layers with varying characteristics (Thickness, permeability, reservoir pressure etc), ICD completions in combination with open hole have successfully been deployed in ADMA-OPCO in more than 10 wells since 2009 to control water injection in high permeable formation and ensure uniform fluid sweep. ICDs were placed against high permeable formation for controlling injection rates while keeping open hole in lower permeable formation. Production logs (PLT) were run in most of the ICD deployed wells to quantify the injection rates across ICDs and open hole section. Based on production logging results, down-hole completion design changes were considered and incorporated in newer wells as a part of continuous improvement. Case histories of ICD installations across high permeable zones showed the technique helped in better injection distribution and reservoir performance improvement. The aim of this paper is to discuss the performance in water injectors with different ICD completion configurations, improvement in injection distribution in different permeability reservoirs, lesson learned during completion running operation.
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
The History Matching of Commingled Injectors Through the Evaluation of Horizontal Well Performance in an Offshore Carbonate Oil Field in Abu Dhabi
Iwama, Hiroki (Abu Dhabi Marine Operating Company) | AL-Silwadi, Basil Mohamed (Abu Dhabi Marine Operating Company) | AL-Feky, Mohamed Helmy (Abu Dhabi Marine Operating Company) | Nakashima, Toshinori (Abu Dhabi Marine Operating Company) | AL-Shehhi, Omar Yousef (Abu Dhabi Marine Operating Company) | AL-Neaimi, Ahmed Khalifa (Abu Dhabi Marine Operating Company)
Abstract This paper introduces the history matching process of commingled wells and demonstrates how to reduce the uncertainty of the vertical permeability ratio (kV/kH) by analyzing the production logging results of horizontal wells which have been used only for allocation through the evaluation of horizontal well performance. The field discussed in this paper is an offshore carbonate oil field located to the Northwest of Abu Dhabi. In this field, a lot of horizontal water injectors have been drilled and completed for the purpose of reservoir pressure maintenance. Historically, most of horizontal water injectors were completed as comingled injector covering two layers isolated by thick dense layers. Due to the complexity of the well and the difficulty of well monitoring, the well performance of these horizontal water injectors was not fully integrated into the model history matching process. The kV/kH ratio is one of the important parameters for analyzing fluid movements in carbonate oil reservoirs. Generally, the value obtained from core analysis results is utilized for reservoir simulation models. In this paper, the effectiveness of analyzing production logging results for commingle wells is introduced as a method for evaluating kV/kH on the simulation model. The end result can reduce uncertainties of kV/kH resulting from heterogeneity of carbonate reservoirs. It is confirmed that production logging results of commingle horizontal wells are valuable for evaluating kV/kH to be defined the simulation model. They can help to reduce the uncertainty in kV/kH, although there is not enough data for the history matching process.
Rejuvenating a High GOR, Light Oil Reservoir Using AICD Completion Technology for Gas Control
Ahmad, Fazeel (ADMA-OPCO) | Al-Neaimi, Ahmed Khalifa (ADMA-OPCO) | Saif, Omar Yousef (ADMA-OPCO) | Channa, Zohaib (ADMA-OPCO) | Iwama, Hiroki (ADMA-OPCO) | Sarsekov, Arlen (ADMA-OPCO) | El-Sayed, Hussein Saad (ADMA-OPCO) | Konopczynski, Michael (Tendeka) | Ismail, Ismarullizam Mohd (Tendeka) | Abazeed, Osama (Tendeka)
Abstract The gaint oilfield offshore Abu Dhabi was discovered in 1963 and came online in 1967. Horizontal drilling was introduced in 1989 to enhance recovery efficiency, leading to a large stock of horizontal wells to date. With the maturation and depletion of the field, areas of high, non-associated gas saturation have developed, and subsequent breakthrough to the horizontal production wells have resulted in high GOR that is above the shareholder's guideline. Many wells have been shut in due to high GOR. Controlling uneven production and early gas breakthrough are the main challenges to achieving target production and maximum hydrocarbon recovery. Inflow control devices (ICDs) create additional pressure drop to balance the production flux, but cannot restrict unwanted effluents โgas/waterโ once they break through. The Autonomous Inflow Control Device (AICD) is an active flow control device that delivers a variable flow restriction in response to the properties (viscosity) of the fluid flowing through it. Gas flowing through the device is restricted more than oil. When used in an oil well segmented into multiple compartments, this design prevents excessive gas production when gas breakthrough occurs in one or more compartments. An evaluation of remedial advanced completion methods was conducted to select the best method of recompleting the shut-in wells and restoring oil production while controlling gas breakthrough. The solution must not only control gas production from zones of the well with high gas saturation now, but must be able to react to future increase in gas saturation in other zones as depletion continues. The "levitating disk" style AICD is ideally suited to this challenge, with the ability to greatly restrict the production from zones with high gas volume fractions. Modeling has indicated that total GOR can be reduced by 40% and total gas production reduced by over 60% compared to an open hole completion. This paper illustrates how AICD technology can enable operators to re-activate wells shut-in due to high GOR. This paper also describes a systematic approach for modelling flow in horizontal wells with AICD's, and presents an evaluation comparing different completion technologies used to control excessive gas production and maximize oil recovery.
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Sognefjord Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Heather Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Fensfjord Formation (0.99)
- (11 more...)
Improvement of Near Wellbore Permeability by Methanol Stimulation in a Methane Hydrate Production Well
Masuda, Yoshihiro (U. of Tokyo) | Konno, Yoshihiro (University of Tokyo) | Iwama, Hiroki (University of Tokyo) | Kawamura, Taro (National Institute of Advanced Industrial Science and Technology) | Kurihara, Masanori (Japan Oil Engineering Co.) | Ouchi, Hisanao (Japan Oil Engineering Co.)
Abstract Depressurization is a promising method for recovering gas from methane hydrate reservoirs, but its effectiveness is much influenced by near-wellbore formation permeability. For example, it is not effective when a production well is completed in the formation of high methane hydrate saturation, because pressure reduction is not transmitted into the reservoir due to its initial low permeability. In such a case, the stimulation to improve permeability near the wellbore is a key factor for assuring the success of methane-hydrate gas production. This paper proposes the methanol huff-and-puff stimulation as a possible way for improving gas productivity of such a methane hydrate well and presents our numerical studies to demonstrate that the huff-and- puff stimulation before depressurization works well in improving gas productivity. The methanol huff-and-puff stimulation we propose consists of the two-process cycles: injection of a methanol-solution slug into the well, and flowback with depressurization. Based on calculation using our numerical simulator, MH21-HYDRES (MH21 Hydrate Reservoir Simulator), we analyzed hydrate dissociation behavior during the huff-and-puff stimulation and successive gas production performance for a hypothetical methane hydrate well. Our calculations lead the following conclusions:Huff-and-puff stimulation dissociates hydrates near the wellbore for the formation to produce gas at much higher rates than the ones without stimulation. Formation temperature goes down below zero along the hydrate equilibrium curve during the huff-and-puff cycles and the decreased temperature helps the surrounding formation to supply heat for promoting hydrate dissociation. In some cases, hydrate regenerates in the region where hydrate-dissociated water dilutes methanol, but its influence is little. Huff-and-puff schedule like huff/puff time ratio and methanol-slug concentration affects the stimulation results. More studies on maximizing the stimulation effect are necessary, but the authors recommend the methanol huff-and-puff stimulation before depressurization in testing methane hydrate wells. Introduction Current research on methane hydrate as an energy resource makes a remarkable advance under the national research projects in Japan, Canada, and U.S. and several field production tests have been carried out for demonstrating methane hydrate gas production1. Among the methods proposed for methane-hydrate gas production, the depressurization is a promising and environmentally sound method because it uses natural geothermal energy for dissociating hydrates. The first step for future hydrate-gas production is to demonstrate and assure a long-term gas production with depressurization. However, the depressurization test in methane hydrate wells has a unique problem arising from the nature of hydrate. Since hydrate exists as a solid state in sediments, gas productivity depends on rate of hydrate dissociation. When a production well is located in the formation of high methane hydrate saturation, pressure in the wellbore is not easy to travel into the reservoir due to initial low permeability. In such a case, hydrate-dissociated region is limited to the vicinity of wellbore and there is little hope of continuous gas production with depressurization. This paper proposes the methanol huff-and-puff stimulation as a possible way for improving gas productivity of such a low-permeability methane hydrate well, and presents our numerical studies to demonstrate that the huff-and-puff stimulation before depressurization works well in improving gas productivity.
- North America > Canada (0.66)
- Asia > Japan (0.49)
- North America > United States > Texas (0.28)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)