Field A is mature hydrocarbon producing field located in east Malaysia discovered in 1963. With multistacked reservoirs more than 7,000 ft high, the reservoirs are predominantly friable and unconsolidated, requiring sand exclusion from the beginning. Most of the wells were completed using internal gravel pack (IGP) methods in the main reservoir. Being an aging producing field, many of the main reservoirs have been depleted and watered out, making the wells inactive. There are, however, several shallower marginal reservoirs, which have been bypassed and undeveloped, known as behind casing opportunity (BCO) reservoirs. The challenge is accessibility to this sand prone reservoir, which might require substantial workover operations, and thus higher costs. Remedial options with proven screen completion can be costly and economically difficult to justify. Mid-2020 marks seven and a half years since the application of a single treatment of epoxy resin in an idle well located in Field A as a remedial approach for BCO. The treatment, proven economically attractive by yielding cost savings of USD 5 million compared to the workover option, further supported by rigorous production monitoring, is unequivocally valuable based on the duration of sustained sand-free production, once again providing reassurance in making this solution a reliable sand-control remedial method for marginal reservoirs. It is important to note that the solution considered a range of laboratory data associated with the chemicals that effectively addressed the requirement based on the characteristics typical of this formation. Well test data from 2013 to 2019 supported sand-free production. Despite experiencing an increment of water cut percentages up to 93.29%, the well is still performing at acceptable production rates. The groundwork processes of candidate identification to the execution of converting the well are described, emphasizing technology comparisons applied in terms of resin fluid system type, execution plan, lessons learned, and best practices developed for maximizing the life of a sand-free producer well.
Immiscible Water Alternating Gas (iWAG) scheme was adopted in Echo field, offshore Sarawak Malaysia, to increase recovery factor of the matured oil reservoir after more than two (2) decades of peripheral water injection. It was implemented through four (4) horizontal wells located at reservoir’s eastern and western flanks. Since the commencement of iWAG injection, multiple challenges occured interrupting the stable injection that halting the success of this integrated mega scale project. It started with prolonged iWAG performance test run due to surface constraint, measurement and well issues on executing switching test, followed with low injectivity during switching operation. Subsequently, injectivity issues occured in the gas phase after several injection cycles. In addition to that, injector wells facing high downtime due to surface facilities and well integrity issues, causing low injection rates and unavailability to meet cycle volume within the stipulated duration. Reactivation of iWAG benefiter wells also prove to be challenging due to wells have been idle for a long time and multiple interventions required to revive the well. Injection data for both gas and water phase were analysed to improve iWAG operating procedure and understand the wells performance. INJ-J2 was installed with temporary pressure gauge during the water to gas switching, while the other two (2) wells are equipped with Permanent Downhole Gauge (PDG) to monitor the well injectivity. Application of non-intrusive flowmeter was also proven useful in calibrating the Flow Transmitter (FT) for both water and gas injectors, ensuring the accuracy and precision in the water and gas injection measurement. Besides that, fluid temperature trending was referred to validate on the meter measurement. Low injection rate compared to original plan were reviewed with the Reservoir Management Plan (RMP). Several approaches are implemented in order to achieve the iWAG RMP target and idle well reactivation. Analysis of injection data showed that gas injectivity issue occurred after the water to gas switching cycle. Injectivity improves slightly after long duration of continuous gas injection and applying higher Tubing Head Pressure (THP), unfortunately some wells remain with low injectivity because of insufficient discharge pressure to push the water from the near-wellbore deep into the reservoir to improve injection. Low injection rate issue is mitigated by extending injection cycle duration in order to meet the RMP cycle volume. Besides that, wells are normally injected with higher injection rate to cater for the high downtime. Both gas and water injection are balanced to ensure that the wells reached their cycle volume at similar duration. With limited new field discovery by the Operator, tertiary recovery on the mature field is inevitable. However, there is less implementation of iWAG in offshore field. Through this paper, authors wish to provide insights and lesson learnt for others when planning for iWAG tertiary recovery, taking account of various challenges faced.
Managing a 47-year brownfield, offshore Sarawak, with thin remaining oil rims has been a great challenge. The dynamic oil rim movement has remained as a key subsurface uncertainty especially with the commencing of redevelopment project. A Reservoir, Well and Facilities Management (RWFM) plan was detailed out to further optimize the development decisions. This paper is a continuation from SPE-174638-MS and outlines the outcome of the RWFM plan and the results’ impact towards the development decisions, such as infill well placement and gas/water injection scheme optimization. Key decisions impact by the RWFM findings are highlighted. One of the RWFM plans is oil rim monitoring through saturation logging to locate the current gas-oil contact (GOC) and oil-water contact (OWC). Cased-hole saturation logs were acquired at the identified observation-wells across the reservoir to map time-lapse oil rim movement and its thickness distribution. Pressure monitoring with regular static pressure gradient surveys (SGS) as well as production data, helped to understand the balance of aquifer strength between the Eastern and Western flanks. Data acquisition opportunity during infill drilling were also fully utilized to collect more solid evidences on oil rim positions, where extensive data acquisition program, including conventional open-hole log, wireline pressure test, formation pressure while drilling (FPWD) and reservoir mapping-while-drilling, were implemented. The timely collection, analysis and assimilation of data helped the team to re-strategize the development / reservoir management plans, through the following major activities: Re-strategizing water and gas injection plan to balance back oil rim between the Eastern and Western flanks, through deferment of drilling water injectors, optimization of water and gas injectors location and completion strategies due to stronger aquifer encroachment from east and south east.Optimizing infill wells drainage points where 2 wells were relocated based on cased-hole logs, as the first well original location was swept and the second well was successfully navigated through the oil rim using reservoir mapping-while-drilling techniques coupled with cased-hole log results. This resulted in securing an oil gain of 4000 BOPD from these 2 wells.Optimizing infill wells location and planning an additional infill well with potential additional oil gain of approximately 2000 BOPD.The understanding of current contact and aquifer strength from the surveillance data assisted in identifying fit-for-purpose technology for the new wells such as the application of viscosity-based autonomous inflow control device which assisted in placing the well closer to GOC due to the observed rapid rising of water table, this will help sustaining the well life. This paper highlights the importance of data integration from geological knowledge, production history, reservoir understanding and monitoring through regular SGS and time-lapse cased-hole saturation logging, coupled with extensive data acquisition during infill drilling. By analyzing and integrating the acquired data, project team can then confidently re-strategize and successfully execute the complex mature oil-rim brownfield redevelopment.
Poster Sessions interactions. NMR shows that there is a reduction in the backbone mobility on the regions of the PHD that participate in the peptide binding, and binding affinities differ depending on histone tail lengths. Thermodynamic analysis reveals that the discrimination in favor of methylated lysine is entropy driven, contrary to what has been described for chromodomains. The molecular basis of H3K4me3 recognition by ING4 differs from that of ING2, which is consistent with their different affinities for methylated histone tails. These differences suggest a distinct role in transcriptional regulation for these two ING family members due to the antagonistic effect of the complexes that they recruit onto chromatin. Our results illustrate the versatility of PHD fingers as readers of the histone code. Transition metal salts, such as Fe, Ni, Co, and Cr salt, are generally avoided in protein crystallization because of fear of protein inactivation or denaturation. However, if transition metal is incorporated in crystal structure, they are useful for SAD, or MAD phasing. Here we cast spotlight on metal cyanide complex salts as protein precipitant, because metal cyanide complex has relatively low affinity for protein and chemically stable over a wide range of pH. We tested five metal cyanide complex salts, K3Cr(CN)6, K3Fe(CN)6, K4Fe(CN)6, K3Co(CN)6, and K2Ni(CN)4. Three proteins, lysozyme, proteinase K, and trypsin were tried to crystallize using each salt as a precipitant by batch method. No additional compound added to mother liquid without buffer component (from pH 4 to pH 9). Diffraction data from grown crystals were collected using CuKα radiation. Metal sites were located using anomalous signal by the program SHELXD. Phase calculation was performed by SAD method using program MLPHARE and automatic model-building by ARP/ wARP were performed. All tested protein can be crystallized by metal cyanide complexes. The crystal form was isomorphous to that grown with non-metal precipitant except in the case of lysozyme with K4Fe(CN)6, where we obtained a new crystal form. In the crystal, metal complexes bind to positively-charged surfaces of the protein. KeywordsIn the case of Cr, Fe, and Co salt, location of metal sites, phasing by SAD method, and automatic model-building were accomplished easily and successfully. But, in the case of Ni salt, location of metal sites was difficult, and phasing power on SAD phasing is as low as that of native (non-metal) crystal because of low f" value of Ni at the wavelength of CuKα radiation. Microfluidic technology opened new possibilities for the crystallization of biological macromolecules. Indeed, microfluidic systems offer a lot of advanges for crystal growth: they enable easy handling of nano-volumes of solutions and, thus, extreme miniaturization and parallelization of crystallization assays. In addition they provide a convection-less environment a priori favorable to the growth of high quality crystals. Pioneer examples implementing free interface diffusion [1] and nano-batch [...
With the increasing energy demand and call for cleaner energy, industry has ventured out for challenging environment such as deepwater and unconventional natural gas resources. While new development is necessary, improvement in gas supply can also be achieved by relooking into the current system. Currently, associated gas produced from oil well are mainly used in petroleum operations, while the remaining gas are either flared or vented to the atmosphere. Inefficient usage of associated gas which has high heating value impose a great value leakage to the company. This paper introduces a new concept that demonstrates more efficient usage and monetization of gas by utilizing associated gas and non associated gas based on its composition instead of volume and sales agreement. The value addition of this new concept was evaluated across the process chain from the upstream operator, host authority, to the downstream plant processing and end product at customer level, using a case study at Field A and Field B. Field A is a brownfield which utilizes produced associated gas for petroleum operations including gas reinjection. Field B is a non-associated gas green field which is tied in to Field A’s processing facilities prior to gas export. Both gas from field A and field B were evaluated based on their gas composition, gross heating value and customer requirement to determine the best option of gas utilization to maximize its value. Feasibility study was carried out to ensure the practicality of the job execution and at the same time commit to the legal and sales requirements. Field A and B belongs to the same PSC, and gas sales are purely based on the heating value and contractual volume requirement. Hence, Field B lower heat value gas can be used for injection provided that the similar volume was replaced for sales. The gas swapping for optimization can be conducted through simple flowline modification with minimal cost. A portion of gas from field B will be directed for gas reinjection at field A, while the associated gas at field A originally intended for injection will be utilized for sales. Injecting gas with leaner hydrocarbon composition will not hinder the oil recovery efficiency of field A. However, gas sales using associated gas from field A allow additional 11% profit gain for the operator from existing scenario. The products of processing the swapped associated gas will reap more profits to the downstream sector, as the gas has higher ethane, propane, and butane molecules. In the current situation, existing fields have always considered gas utilization individually. There is potential for all fields to utilize gas more effectively to increase the economic value of the field and downstream facilities.
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