The objective of this paper is to share the experience, approach and strategy to the technical forum involved in developing mid-size offshore gas fields from exploration, appraisal to field development and production, accordingly monetizing the produced gas by exploring various options in the international market.
Subsequent to exploration and appraisal of two adjacent blocks A-1 and A-3, three prospects were delineated- Shwe and Shwe Phyu in Block A-1 and Mya in Block A-3, Myanmar. These blocks are operated by M/s POSCO INTERNATIONAL and other consortium members are OVL, GAIL, KOGAS and Myanma Oil and Gas Enterprise (MOGE).
Shwe and Shwe fields were discovered in January 2004 and January 2005 respectively in Block-A-1. Subsequently, Mya field was discovered in March 2006 in Block A-3. Mya field is divided into two parts, i.e, Mya-Norh and Mya-South.
To develop these fields, Consortium conducted Pre-Front End Engineering Design (FEED) and FEED studies from two international contractors and selected the best option to develop these fields. Consortium is jointly developing the fields in a phase which is called SHWE Project. Drilling of 10 wells in Shwe Prospect (8 production, 1 disposal well & 1 abandoned) from a platform drilling rig and 4 subsea wells in Mya-North Prospect from drillship (MODU) completed in Phase-1 development. Phase-2 development will involve drilling of 4 subsea wells each in Shwe and Shwe Phyu prospects which will be drilled by MODU. Phase-3 development will consider installation of LP compressor platform if delivery pressure falls below the contract requirements. Currently, produced gas from Shwe and Mya-North Prospects are being processed at Shwe Common Processing Platform (CPP) and then it is brought upto Onshore Gas Terminal (OGT) through 32" × 110 km pipeline (105 km – offshore and 5 km onshore).
The SHWE project can be economically produced for about 24 years. The buildup production period was for one year and plateau period estimated for 13 years. The unitization of the fields and production & sales of produced gas involved the following milestones and future development plans: Installation of Integrated Drilling cum Processing Platform (IDPP) at Shwe prospect for Phase-1 development drilling of Shwe and bringing produced gas from Mya-North to Shwe CPP. The processed gas from the Shwe platform is transported to Sales Point through offshore subsea pipeline from Shwe CPP till landfall point and onshore pipeline from landfall point to Sales Point at OGT. Evaluated options to sale, burn or dispose the condensate produced with gas from all the fields and finally decided to dispose the condensate by drilling a condensate disposal well at Shwe prospect. Evaluated various options and routes to sale the produced gas to potential buyers in international market. Phase-2 development wells at Shwe and Shwe Phyu would be drilled and produced gas would be processed at Shwe CPP and installation of LP compressor would be a part of Phase-3 development plan.
Installation of Integrated Drilling cum Processing Platform (IDPP) at Shwe prospect for Phase-1 development drilling of Shwe and bringing produced gas from Mya-North to Shwe CPP.
The processed gas from the Shwe platform is transported to Sales Point through offshore subsea pipeline from Shwe CPP till landfall point and onshore pipeline from landfall point to Sales Point at OGT.
Evaluated options to sale, burn or dispose the condensate produced with gas from all the fields and finally decided to dispose the condensate by drilling a condensate disposal well at Shwe prospect.
Evaluated various options and routes to sale the produced gas to potential buyers in international market.
Phase-2 development wells at Shwe and Shwe Phyu would be drilled and produced gas would be processed at Shwe CPP and installation of LP compressor would be a part of Phase-3 development plan.
Offshore gas field development though is not a new concept, but developing two independent Blocks A-1 and A-3 in Myanmar by Shwe Consortium is a typical case study from exploration till development and production. The Shwe development is a result of nine year effort of the Shwe Consortium from exploration stage till development and production. This paper provides an overview of development and execution of the project introduces key challenges, achievements and learning's. It also emphasise the importance and integration between all disciplines required to successfully deliver any project.
In 1993, Richard D’Souza (Fellow), the principal author and his co-authors presented a landmark paper reviewing the Semisubmersible Floating Production System (FPS) technology at the SNAME centennial meeting in New York. (D’Souza et al., 1993a). The paper captured the twenty year progression of the FPS beginning with the Argyll field in the UK Sector of the North Sea in 80 meters of water that was converted from a semisubmersible Mobile Offshore Drilling Unit (MODU) and began producing in 1975. During this period about twenty five FPSs were installed, primarily in the North Sea and Brazil. Most were converted from semisubmersible MODUs. The deepest was in 625 m, the largest displacing 45,000 mt and the maximum oil rate was 70,000 bopd.
Over forty FPSs have been installed since then, most of which are purpose built platforms. The technology has expanded to a maximum water depth of 2400 m, displacements exceeding 150,000 mt and production rates of 300,000 boepd. The inherent versatility and flexibility of the FPS to adapt to a wide range of water depths, payloads, metocean conditions and future expansion, has resulted in the FPS superseding the Tension Leg Platform (TLP) and the Spar platform as the most widely used floating production platform after the Floating Production Storage and Offloading (FPSO) platform. Its field development applications range from marginal reservoirs to giant deepwater oil and gas fields across the globe.
This paper, authored by Richard D’Souza with a new team of co-authors, is a sequel to the 1993 paper and is intended as a historical and technical archive of the evolution of the FPS technology in the ensuing twenty five years. It highlights the importance of the Naval Architect and Ocean Engineer whose role has evolved from a peripheral to a major player in the design, fabrication and installation of the FPS. This paper has two objectives. One is to inform Operators and Contractors engaged in developing deepwater fields by providing a historical overview of lessons learned and technology evolution of the FPS. The other is to inspire graduate and post graduate Naval Architects and Ocean Engineers to consider a career in the offshore industry where they will have an impactful role in shaping the future of deepwater floating production platforms.
Polymer enhanced oil recovery (EOR) has been successful in onshore and offshore reservoirs, and is especially promising for heavy oil or heterogeneous reservoirs. Polymer retention, mainly due to adsorption, results in the removal of polymer from the solution, leading to the formation of a polymer-free bank. Thus, determining the retention is a key factor in evaluating the feasibility of polymer flooding. This work investigates a method to reduce polymer adsorption and improve the economics of polymer EOR. This is done through laboratory experiments and reservoir simulation. The experimental investigations consisted of five dynamic retention core floodings in fresh and non-fresh high permeability sandstones. Five concentrations of a HPAM-AMPS in high salinity brine were tested. Two types of experiments were performed: fresh-adsorption, and re-adsorption. Injection of the polymer solution in porous media that had never been in contact with polymer composed the fresh-adsorption experiments. Differently, the re-adsorption experiments were performed in media that had been flushed with the same polymer previously. The experiments indicated a type IV isotherm for fresh-adsorption, while the re-adsorption isotherm was of type I. For a polymer concentration of 1250ppm, the fresh-adsorption was 166.7μg/g while the cumulative re-adsorption was 64.8μg/g. Therefore, reduction of ∼61% may be achieved by pre-flushing the medium with a low polymer concentration solution before the injection of the mobility control bank. Other properties of the polymeric system were measured in the core floodings to serve as inputs to the reservoir simulation model. The field-scale simulation studies evaluated the economic impact of the injection of a low concentration polymer slug to reduce polymer loss during EOR, such as observed in the re-adsorption experiments. The production strategy optimization was composed of eight steps, and targeted net present value (NPV) maximization. The case studied was a heavy oil offshore sandstone field, based on a benchmark. The strategy to reduce polymer retention represented a 4% increase in the final NPV over the conventional polymer flooding. Additionally, risk curve analysis demonstrated the advantage of this reduced-retention strategy over waterflooding and conventional polymer flooding. This work shows experimental evidence that polymer overall retention may be reduced through injection of a low polymer concentration bank prior to the mobility control one. Additionally, through numerical simulation and economic analysis, it indicates that the reduced retention allows for an economic advantage in polymer EOR, which may improve the feasibility of polymer flooding projects.
While many factors in the reservoir cannot be controlled, there are three controllable factors in field development that make a significant impact. More reservoir contact leads to more oil produced. Controlling sand and water means lower treatment costs, and in-situ reservoir management leads to higher cumulative production. While the underlying technologies have been around for up to 20 years, it is only recently that their synergies and true value are understood. This paper will demonstrate the effect each of these technologies has on increasing overall production rates, improving recovery, and reducing the cost per Barrel of Oil Equivalent (BOE).
The successful implementation of multilaterals in the North Sea will be analyzed. Since 1996, over 300 multilateral junctions have been installed on the Norwegian continental shelf fields with currently approximately 30 junctions completed each year.
Additionally, simulations will be used to demonstrate the incremental improvements in oil recovery that can be obtained by using properly designed advanced completions that include multilaterals, sensors, and passive/active flow control equipment.
The paper will evaluate production performance of a vertical well field development base case against scenarios using horizontal and multilateral wells. It will show how fields can be optimized, leading to increased oil and decreased water production.
Production rates can be significantly improved by combining multilaterals with other advanced completion techniques, such as intelligent completions and inflow control devices. The subject field simulation can be further optimized to manage gas and water production.
With a tailored multilateral field design, combined with properly designed advanced completions systems, the simulation succeeds in terms of achieving maximum contact with the oil reservoir and meeting improved ultimate recovery objectives.
It can be concluded that as reservoir contact is increased, a reduced decline in production rate is observed leading to both a higher Estimated Ultimate Recovery (EUR) and optimized drawdown profile distributions. Additionally, results will be presented that have considered oil production and a method to lower production of unwanted fluids or gas.
This paper also demonstrates the value of field development design from the perspective of reservoir simulation. It is through reservoir insight that a level of understanding is created that can help define the optimum well and completion design to meet field expectations.
Advanced multilaterals continue to grow in popularity with many operators, and it therefore becomes important to evaluate the value of different field development methods. This knowledge can aid operators in unlocking new reservoir targets and optimizing field development, and ultimately will improve recovery factors and overall field economics.
Electrical-submersible-pump (ESP) technology is a proven artificial-lift method for shallow, low-pressure reservoirs such as those found in the West Sak viscous oil field in Alaska. This study examines how subsea processing (SSP) can develop into an important enabling technology for future ultradeepwater-field developments and long-distance tiebacks. Unconventional production patterns in the Permian Basin are leading producers to replace electrical submersible pumps (ESPs) with gas lift, which had been little used there. The sharp downturn in the offshore oil business has sparked interest in using subsea pumps to add production. If those conversations turn into orders, it may convert this rarely used option into a commonly used tool for extending the life of offshore fields.
Devon Energy and its debt gets smaller, as Canadian Natural Resources adds to its huge, long-term bet on Canadian heavy and ultra-heavy crude. The recent production freefall could accelerate even further as US sanctions-related deadlines pass, the US Energy Information Administration said. The authors of this paper propose a novel work flow for the problem of building intelligent data analytics in heavy-oil fields. This paper presents the data collected by an ultrasound downhole scanner, demonstrating a novel method for diagnosing multilateral wells. Against the background of a low-oil-price environment, a redevelopment project was launched to give a second life to a shallow, depleted, mature offshore Congo oil field with viscous oil (22 °API) in a cost‑effective manner.
UK operator Trident Energy is entering Brazil while Australian firm Karoon Energy is expanding its position in the country. Both will try to boost output from already-producing assets. Petrobras says it can produce oil for a lower break-even price than onshore shale plays, including the Permian Basin. Brazil’s offshore sector has cut the cost of deepwater production but comparisons based on break-even prices are slippery. Take a quick look at some of the data points shaping upstream headlines and the movement of oil supplies around the world.
Africa (Sub-Sahara) Oil was discovered at the Ekales-1 wildcat well located in Block 13T in northern Kenya. The well has a potential net pay of between 197 and 322 ft in the Auwerwer and Upper Lokone sandstone formations. Tullow (50%) operates 13T with partner Africa Oil (50%). The Mzia-3 appraisal well in Block 1 off Tanzania encountered a combined total of 183 ft of net pay in the Lower and Middle sands and confirmed reservoir quality in line with that seen in the Mzia-1 and Mzia-2 wells. Asia Pacific The Luba-1 offshore well on Brunei Block L was spudded. The well will evaluate the hydrocarbon potential of the Triple Junction structure. Serinus has a 90% interest in Block L, through indirect wholly owned subsidiaries Kulczyk Oil Brunei (40%) and AED SEA (operator, 50%).
Africa (Sub-Sahara) An 816-mile 2D seismic acquisition program was completed on the Ampasindava block, located in the Majunga deepwater basin offshore northwest Madagascar. The data will provide improved subsurface imaging of the large Sifaka prospect and will potentially mature additional prospects in the Ampasindava block to drill-ready status. Sterling Energy (UK) holds a 30% interest in the Ampasindava production sharing contract, which is operated by ExxonMobil Exploration and Production (Northern Madagascar) (70%). Asia Pacific Production began on the Liuhua 19-5 gas field in the Pearl River Mouth basin in the South China Sea. The field is expected to hit peak production of 29 MMcf/D this year. China National Offshore Oil Corporation (100%) is the operator. Drilling began on the YNG 3264 and the CHK 1177 development wells onshore in Myanmar.