Controlling sand has been one of the most difficult challenges in oil production in Upstream Malaysia operations. Conventionally, Cased Hole Gravel Packs (CHGP) or Open Hole Gravel Packs (OHGP) are installed to prevent sand from being produced with the oil to the surface facilities. However, both methods require massive operations and high cost which impact the overall economics of the project. This paper summarizes the technology evaluation of Shape Memory Polymer (SMP). This includes the working philosophies, candidate selection, risk identification and mitigation plan, and success criteria developed for this technology. Common gravel packing technique is accomplished by packing gravel in the annulus between the screen and formation sand face, where the gravel acts as a barrier preventing the migration of the formation sand. The new technology does exactly the same task by expanding SMP which conforms to the sand face. The only difference, in gravel packing, the contact medium with the sand face is the gravel whereas in this technology the contact medium is the SMP. The operational sequence is very similar to the installation of Open Hole Stand Alone Screens (OHSAS). From the evaluation, one well was identified by the team at BS field for piloting this technology. The well will be part of a development campaign executed in Q2 2020. Details of the well design and scope will be shared briefly, as well as a commercial comparison between conventional sand control methods and SMP. The pilot test at BS field will be discussed including technology evaluation, candidate selection, well completion design, risk mitigation and others. Several case histories and current available field implementation are also taken into consideration to properly plan the pilot test. The success criteria outlined would help to oversee the performance and continuous monitoring of the system before it can be declared a success. Potential candidates for replication of this technology have also been identified within the Operator's company in the near future. The possible pilot test for this technology is the result of strong and good collaboration between the Operator and Service Company. If it is a proven success, this technology will become a game changer for downhole sand control in the petroleum industry which will be able to maximize production and save operational expenditures, while ensuring the highest reliability.
Field A, an oil field located in Peninsular Malaysia, was completed in 2007 with an initial production of 6,000 BOPD and managed to reach a peak production of 15,000 BOPD the same year, with a water cut of 15%. Toward the end of 2014, a decrease in production was observed with an increase in water cut to 85%. Coupled with high water cut, some of the wells experienced sand production issues. Most of the wells were completed with either standalone screens or without any sand control methods. After a few years in production, the sand-producing wells were shut-in to help prevent damage to surface facilities. Two idle oil wells, Wells 1 and 2, were identified and efforts were made to reactivate them. High costs can be associated with remedial mechanical sand control to work over a well, so a chemical consolidation treatment using solvent-based resin was identified as a less expensive solution for remedial sand control for these wells. Chemical sand consolidation using solvent-based epoxy resin was tested in a laboratory using produced sand samples from the selected wells and showed good results. The chemical consolidation treatments for Wells 1 and 2 were designed based on these results. Before treatment was performed for either well, Well 2 was replaced with Well 3 because of a gas supply shortage, which affected total field production. In October and November 2015, Wells 1 and 3 were intervened and chemical sand consolidation was executed on both wells. After the treatment, Wells 1 and 3 were brought back on production. Sand production for Well 1 was below the threshold limit of 15 pounds per thousand barrels (pptb). However, the performance of Well 3 did not meet expectations. This paper describes the process of treatment design and execution for the chemical sand consolidation of Wells 1 and 3 and explains the workflow used during the design stage. Coiled tubing isolation technique and bullhead treatment technique are discussed together with lessons learned from Wells 1 and 3 in terms of designing chemical sand consolidation treatments for future applications.
TX 75083-3e36, U.S.A., fax 01-972-952-943S. AbstractThe Brent field, developed as an oil producing field in the mid 7WS, is now approaching the end of its economic life. However, the large quantity of remaining oil, although only 40% of initial reserves, and the high Gas-Oil ratio of the oil allow extended production from the field by reducing the reservoir pressure. The de-pressurisation will add some 10-15 year of economic life to the field.The de-pressurisation project, unique in the world due to the size and complexity of the Brent field, brings many uncertainties. The well completion design is key in the management of these uncertainties.Cost-effective reservoir management (zonal solation) is a pre-requisite and the choosen completion design should accommodate sand, scale and even H2S management. Furthermore certain wells will require artificial (gas) lift, although the number and location of these wells will be largely unknown up front. The adopted monobore completion design combines maximum flexibility and cost-effectiveness with simplicity and is readily adaptable to gas lift installation. The Brent monobore completion design has reduced cost by 30% and installation time by 6590 as opposed to the Multi-Straddle Assembly completion run previously in Brent. Key features of the completion and retrofit gas lift installation are described in this paper.
In the current oil price environment, all new developments are pursued with minimum capital investment and lowest possible operating cost to improve project economics. Projects that do not meet the economic criteria have to be shelved or deferred to a later date. This was the case for a green gas field development in Peninsular Malaysia which was shelved in 2016, resulting in an added preservation requirement for the newly-fabricated topside facilities and pipelines. The increase in project cost due to the preservation requirements, eroded the project economics which necessitates all possible cost reductions in order to make the overall project economically viable. One possible area for cost reduction is the sand management. Sand production is expected from the shallower I-group reservoirs targeted in the gas development. This is based on well test results conducted in one of the appraisal wells which is further supported by a sand production prediction (SPP) study. Based on the available Particle Size Distribution (PSD) data from a Laser Particle Sieve Analysis (LPSA), the reservoir particle D50 is about 55µm and has more than 40% fines content. Due to the multilayer reservoir targets, cased hole development were designed for the well hence Internal Gravel pack (IGP) is selected as the downhole sand exclusion method. Over the life of the field, fines production is anticipated due to the high fines content of the reservoir. There is also risk of IGP failure which could result in eroded tubings, flowlines and headers. This would be catasthropic for the green field due to its unmanned operation philosophy. Moreover, during the facilities detailed design, the provision for surface desander was eliminated to make way for a compact platform design. This paper will describe the methodology used to assess the severity of sand production to the surface facilities using the well and reservoir parameters. The assessment results provide the basis for the field integrated sand management philosophy, which helps management to make an informed decision to eliminate the real time sand monitoring and control system requirements and also eliminate the need for platform deck extension for desander installation requirement.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
hi@scite.ai
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.