Africa (Sub-Sahara) Cairn Energy has flowed oil from its SNE-2 well offshore Senegal. Drillstem testing of a 39-ft interval achieved a maximum stabilized but constrained flow rate of 8,000 B/D of high-quality pay. A flow rate of 1,000 B/D of relatively low-quality pay was achieved from another zone. Drilled to appraise a 2014 discovery, the well lies in the Sangomar Offshore block in 3,937 ft of water 62 miles from shore. Drilling reached the planned total depth of 9,186 ft below sea level. Cairn has a 40% interest in the block with the other interests held by ConocoPhillips (35%), FAR (15%), and Petrosen (10%).
Africa (Sub-Sahara) Kosmos Energy has made a significant deepwater gas discovery off Senegal. The Guembeul-1 well in the northern part of the St. Louis Offshore Profond license in 8,858 ft of water encountered 331 net ft of gas pay in two excellent-quality reservoirs, the company reported. The results demonstrate reservoir continuity and static pressure communication with the Tortue-1 well, which suggests a single gas accumulation. The mean gross resource estimate for the Greater Tortue complex has risen to 17 Tcf from 14 Tcf as a result of the Guembeul discovery, the company said. Kosmos, the operator, has a 60% interest in the well. Timis (30%) and Petrosen (10%) hold the remaining interest. In Salah Gas has started production from its Southern fields in Algeria.
Acid stimulation in sandstone reservoirs containing significant amount of clays can end up with undesired results due to unexpected reactions between stimulation fluids and formation clays. This paper demonstrates how heavily damaged clay-rich sandstone reservoir completed with cased hole gravel pack (CHGP) in offshore Myanmar can be successfully established for commercial production with organic clay acid stimulation treatment. The formation is laminated dirty sand with very high clay content (up to 30%) and large gross height (>100m MD). Production logging results showed only a small portion of perforated intervals contributing to production. Thus, an appropriate stimulation treatment is required to unlock well potential and prevent screen failures from concentrated flow through a small interval.
Given high clay content as well as presence of acid sensitive clays, conventional treatments using HCl as preflush and hydrofluoric (HF) acids as main fluids would result in potential damages from secondary and tertiary reactions. Furthermore, undissolved clays in the critical matrix left over from the treatment would potentially migrate and plug the pore throat. The new acid system was designed to generate small amount of HF in-situ (~0.1%) at any given time with total strength of 1% HF, which would greatly minimize second and tertiary reactions and also permits acids travel deeper into the formation. Furthermore, the reaction products would react with the clays and physically "welding" the undissolved clays to the surface of the pore spaces permanently and prevent them from migration.
The treatment was designed in three stages: 1) screen and gravel pack cleanup using coiled tubing (CT) jetting; 2) injectivity test; 3) main treatment consisting of acetic acids as preflush, and new acid system as main fluids followed by overflush. A newly designed linear gel containing relative permeability modifier was used for diversions. Two underperforming CHGP wells were treated, and both wells yielded 100% increase in productivity with no fine production observed at the surface.
The success of the campaign owes to the sophisticated engineering workflow which starts from diagnostic of the damage zone and root-cause of the formation damage, followed by detailed analysis of various skin components using radial numerical reservoir modeling for all the reservoir layers that led to a proper treatment strategy and fluid design based on the damage and formation mineralogy as well as comprehensive laboratory tests. This has helped to minimize the risk of the treatment and eventually unlocked the production from the heavily damaged sandstone reservoir.
Park, D. (Posco Daewoo Corp.) | Song, I. (Posco Daewoo Corp.) | Bae, Y. (Posco Daewoo Corp.) | Kikuchi, M. (Schlumberger) | Ling, J. P. (Schlumberger) | West, S. (Schlumberger) | Yap, J. (Schlumberger) | Ridho, M. (Schlumberger)
This paper covers the strategies implemented when completing the Shwe gas field in Myanmar. The field, operated by Posco-Daewoo, has been in production since 2013. We present our study and evaluation of the reservoir, integrated completion design, operational challenges, and production performance of the wells.
The project began when Myanmar was subjected to economic sanctions and Myanmar is considered a remote location with quite limited infrastructure, so there were many challenges on the logistics front. The goal of our completion design was to complete the unconsolidated reservoir with either openhole gravel pack (OHGP) or cased hole gravel pack (CHGP), depending on the tendency for water production. The upper completion was designed to optimize gas production. Permanent downhole gauges (PDHG) were installed to monitor the reservoir pressure and temperature.
As part of the development program, eight gas wells and one condensate disposal well were drilled and completed from 2013 to 2015. Logistics and preparation, key contributors to the success of these installations, were supported from Singapore with a limited transit time to the platform, which meant that turnaround time was closely monitored to meet delivery each time. The lower completion project in the 9 5/8-in casing consisted of four OHGP wells and four CHGP wells. Screen type and size, and gravel type and size were determined using particle size distribution studies with core samples and software simulation. Findings were then further verified with extensive lab testing. To achieve minimal skin and damage for the gravel pack (GP) carrier fluid, a nonpolymer fluid was used for CHGP and OHGP. Although a breaker was incorporated into the carrier fluid for OHGP, a filtercake breaker was pumped afterward for maximum cleanup. As for CHGP, the wells were acidized prior to gravel packing. Breakers for the carrier fluid were displaced pre- and post-GP. For the upper completion, five wells with 7-in production string and three wells with 5.5-in production string were completed. After landing the completion string, a formation isolation valve (FIV) was cycled open, followed by well testing. The subsequent pressure matching we performed confirmed that minimal skin and damage were achieved. We achieved and exceeded all the objectives set for the campaign in terms of HSE performance, operational efficiency, production rate, and sand-free production.
Logistics and preparation, key contributors to the success of these installations, were supported from Singapore with a limited transit time to the platform, which meant that turnaround time was closely monitored to meet delivery each time.
The lower completion project in the 9 5/8-in casing consisted of four OHGP wells and four CHGP wells. Screen type and size, and gravel type and size were determined using particle size distribution studies with core samples and software simulation. Findings were then further verified with extensive lab testing.
To achieve minimal skin and damage for the gravel pack (GP) carrier fluid, a nonpolymer fluid was used for CHGP and OHGP. Although a breaker was incorporated into the carrier fluid for OHGP, a filtercake breaker was pumped afterward for maximum cleanup. As for CHGP, the wells were acidized prior to gravel packing. Breakers for the carrier fluid were displaced pre- and post-GP.
For the upper completion, five wells with 7-in production string and three wells with 5.5-in production string were completed. After landing the completion string, a formation isolation valve (FIV) was cycled open, followed by well testing. The subsequent pressure matching we performed confirmed that minimal skin and damage were achieved.
We achieved and exceeded all the objectives set for the campaign in terms of HSE performance, operational efficiency, production rate, and sand-free production.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 25002, “Deepwater Growth in Asia Pacific and Growing Regional Installation and Pipelay Vessel Capability To Meet the Challenges,” by Biren Kumar Dash, SapuraKencana Petroleum, prepared for the 2014 Offshore Technology Conference Asia, Kuala Lumpur, 25–28 March. The paper has not been peer reviewed.
The Asia Pacific region is expected to be the fastest-growing region in deepwater development in the next 5 years. Malaysia, Indonesia, China, India, and Australia together are expected to drive 85% of deepwater spending in the region. This paper presents various deepwater developments in the region, with a focus on deepwater pipelay involving steep S-lay/J-lay requirements and the availability of regional offshore deepwater installations and pipelay vessels to meet the challenges posed by future deepwater development.
Deepwater Growth in Asia Pacific
The Asia Pacific region is traditionally a shallow-water-development region, with most of the fields operating in water depth of less than 100 m. Currently, only a few fields operate in water more than 500 m deep, and most of these came on stream in the last 5 years. With the energy demand growing in the region, international oil companies and national oil companies are partnering to exploit more-remote deepwater fields.
Key Asia Pacific Deepwater Developments
Malaysia. Currently, 19 deepwater blocks are active with a water depth from 520 to 1735 m, where the average depth of deepwater development is 1224. m. Murphy Kikeh is the first deepwater development, in water depth of 1340 m, and has been producing oil since 2007. Deepwater capital expenditure offshore Malaysia over the next 5 years is expected to place Malaysia eighth globally over the period, with USD 6.5 billion directed toward 19 separate deepwater-field developments. The two key developments for the period are the Shell-operated Gumusut-Kakap and the Murphy- operated Rotan, with a new-built floating liquefied-natural-gas (LNG) facility expected to enter production by 2017. Eleven deepwater fields are expected to enter production over the next 5 years.
Indonesia. Currently, Chevron’s West Seno is the only deepwater development in Indonesia, producing in water depth of 975 m and using tension-leg-platform and floating-production-unit concepts since 2003. Nineteen deepwater developments are expected in the next 5 years in Indonesia, with the most-capital-intensive one being Chevron’s ultradeepwater Gendalo Gehem development.
The Ganges Brahmaputra Delta and the associated Bengal Fan is the world’s largest delta/submarine fan complex. The deepwater areas of the Bengal and Rakhine Basins are relatively underexplored frontier areas. In 2003 the large Shwe gas field was discovered in Lower Pliocene turbidite fan sediments with reserve estimates of 6-9 tcf. As additional blocks are licensed, new data will be acquired to evaluate the area including 3D CSEM which is being considered as a complementary exploration method to seismic data.
The controlled-source electromagnetic (CSEM) method has been applied to oil and gas exploration and production for more than 10 years. EM data are used to indicate the presence of hydrocarbons, since hydrocarbon saturated rocks display higher electric resistivity compared to water-filled reservoirs. CSEM is an excellent technique to define the lateral extent of hydrocarbon accumulations and is particularly useful in determining the existence and extent of stratigraphic accumulations.
3D modelling indicates CSEM is sensitive to the Shwe Field reservoirs and can define the lateral extent of the pay zones. 3D CSEM forward modelling has been performed over a range of target sizes within the economic limitations of deepwater drilling, and the modelling shows that CSEM would be sensitive to those targets.
Based on these results, it is concluded that CSEM 3D data will detect the presence of hydrocarbon accumulations and thus, high-grade exploration areas in the greater Bengal Basin.
In this paper we describe how the deepwater reservoir sediments in the Bay of Bengal, dominated by a deepwater turbidite depositional process, is the ideal geologic setting for detecting resistive anomalies related to hydrocarbon accumulations. Turbidites, by nature, are anomalous deposits of sand encased in shale. When saturated with hydrocarbons, they are more resistive than the surrounding shales, allowing them to be detected using the marine controlled source electromagnetic (CSEM) method. CSEM is sensitive to the large Shwe field accumulation on the shelf, offshore Myanmar and is used in this study to illustrate the ranges of detectability in the adjacent deepwater areas (Fig. 1).
This paper presents the unique challenge and technical solutions for the transportation and installation (T&I) of the fully-integrated SHWE topside. The SHWE topside, one of the heaviest topside in Asia, has a weight of about 26000 MT and is transported to the installation site in the Bay of Bengal, Myanmar by the bottle shaped barge HYSY229. The emphasis of this paper is on describing the most challenging part of the T&I design, the barge strength under topside transport and floatover mating analysis with the long swell condition.
Li, Huailiang (Offshore Oil Engineering Company, Limited) | Yang, Yun (Offshore Oil Engineering Company, Limited) | Yuan, Ruhua (Offshore Oil Engineering Company, Limited) | Xie, Weiwei (Offshore Oil Engineering Company, Limited) | Wang, Alan (Offshore Oil Engineering Company, Limited) | Jin, Xiaojian (China National Offshore Oil Corporation)
This paper describes the design functionality and structural integrity of the T-Shaped barge hull modification of launch barge HYSY229 in depth. The T-Shaped hull has to be reinforced to comply with both regulation and project strength requirements by adding internal longitudinal bulkheads and increasing thickness of deck and bottom plating. The challenge of the hull modification is to ensure a floatover installation capacity of 30,000Te integrated topsides while maintaining its original launch capacity of 30,000Te jackets.