Is Surfactant Environmentally Safe for Offshore Use and Discharge? The current presentation date and time shown is a TENTATIVE schedule. The final/confirm presentation schedule will be notified/available in February 2019. Designing Cement Jobs for Success - Get It Right the First Time! Connected Reservoir Regions Map Created From Time-Lapse Pressure Data Shows Similarity to Other Reservoir Quality Maps in a Heterogeneous Carbonate Reservoir. X. Du, Y. Jin, X. Wu, U. of Houston; Y. Liu, X. Wu, O. Awan, J. Roth, K.C. See, N. Tognini, Shell Intl.
By International Petroleum Technology Conference (IPTC) Monday, 25 March 0900-1600 hours Instructors: Olivier Dubrule and Lukas Mosser, Imperial College London Deep Learning (DL) is already bringing game-changing applications to the petroleum industry, and this is certainly the beginning of an enduring trend. Many petroleum engineers and geoscientists are interested to know more about DL but are not sure where to start. This one-day course aims to provide this introduction. The first half of the course presents the formalism of Logistic Regression, Neural Networks and Convolutional Neural Networks and some of their applications. Much of the standard terminology used in DL applications is also presented. In the afternoon, the online environment associated with DL is discussed, from Python libraries to software repositories, including useful websites and big datasets. The last part of the course is spent discussing the most promising subsurface applications of DL.
New technologies that contribute to enhanced production in ultralong tiebacks have recently been developed. These new developments include higher differential pressure in multiphase pumps and compressors, mechanical designs for high pressures and temperatures, and power systems suited for ultralong tiebacks.
When developing new, cost-efficient boosting technology for long subsea tiebacks and deep water, a system approach is important. This includes power systems, installation methods, maintenance, reliability, and condition monitoring. The new technologies described have been developed based on operational experience and physical theory combined with practical experiments and validation, both scaled and full size. The importance of developing simple and reliable solutions in facilities that enables comprehensive experimenting and testing is also explained. Today’s oil and gas price level also requires cost-efficient solutions, and the paper explains how this can be obtained through standardization and modularization.
The first pump systems that are able to provide a more-than 200-bar differential pressure are already developed, qualified, and put in operation. A game-changing multiphase gas compressor technology that provides differential pressure up to 55 bar has also been built, tested, and verified. In parallel with these developments, subsea power systems have been further developed so that they can be used for step-outs longer than 200 km. Recently, a multiphase pumping station designed for 2,500-m water depth and 15,000-psi design pressure was installed and set in operation in the Gulf of Mexico. All of this contributes to enhanced production and lower field developments costs in subsea environments and provides a platform for further technology developments that can potentially make extremely remote subsea field developments economically attractive.
This paper presents new technology related to multiphase pumping and compression and a system approach that can make production from remote and deepwater subsea fields more capital efficient.
Woodside awarded a front-end engineering and design contract to OneSubsea for the Greater Enfield Area Development offshore northwest Australia. The contract includes the design of a full subsea production system architecture solution, including subsea multiphase boosting for the field that will be tied back to the existing Ngujima-Yin FPSO.
This paper reviews the issues associated with mooring a ship shaped Floating Production Unit (FPU) in arctic conditions, and presents the development of a novel disconnection and reconnection system for such conditions. The mooring systems of FPUs operating in arctic conditions must be disconnectable to allow the FPU to leave the station to avoid collision with icebergs, or to avoid overloading the mooring legs due to sea ice acting on the FPU hull. In the case of sea ice, the FPU may be required to disconnect under much higher loads than the non-arctic disconnectable systems in operation today. A recent study for the design of an arctic mooring system identified a number of key developments that are required before such systems could be deployed. The disconnection system is a safety critical element, and requires high reliability and redundancy to ensure the FPU can always rapidly disconnect from its mooring when required. In addition, the large number of risers that may be installed for these large field developments, combined with the significant suspended weight resulting from the high capacity mooring system, leads to large buoyancy requirement for the buoy which must support the risers and mooring system when disconnected from the vessel. As a consequence the analysis of the reconnection process must account for the coupled behaviour of the large buoy body, the mooring system, and the risers and umbilicals. Such analysis has shown that using conventional disconnectable turret technology, the large buoy size coupled with the requirement to reconnect in heavy sea states, can readily generate snatch loads that would break the pull-in winch wire.
The Stybarrow Field is a moderately sized biodegraded 22° API oil accumulation reservoired in Early Cretaceous sandstones of the Macedon Formation in the Exmouth Sub-Basin, offshore Western Australia. The reservoir is comprised of excellent quality, poorly consolidated turbidite sandstones up to 20m thick. The field lies in approximately 800m of water and has been developed with five near-horizontal producers and three water injection wells. The Stybarrow development came online at an initial rate of 80,000BOPD in November 2007.
Due to the lack of significant aquifer support, water injection was planned from start-up for pressure maintenance. Acquisition of a variety of data types have enabled key subsurface challenges to be addressed both before and during production. Structural and stratigraphic complexities influence connectivity and therefore must be fully evaluated in order to achieve optimal sweep. A feasibility study concluded that Stybarrow would be a good candidate for 4D seismic monitoring. Two monitor surveys were acquired and, along with other reservoir surveillance techniques, have been used to refine the geological model.
The first monitor survey at Stybarrow was recorded in November 2008. The results of this survey were in agreement with prior 4D modelling and supported the drilling of a successful development well in the north of the field. A second monitor survey was recorded in May 2011, three and a half years after first oil and at 70% of expected ultimate recovery. This survey is currently being analysed to determine if sweep patterns have changed.
The 4D surveys have proven to be an important tool for understanding subsurface architecture and dynamic fluid-flow behaviour. The results of both 4D seismic surveys have provided significant contributions to understanding the dynamic behaviour within the reservoir to facilitate optimal reservoir management.
The Enfield oil field, on Australia's Greater North-West Shelf, has now produced over 50 million barrels of oil. The field is a water flood development with both downdip and updip water injection wells. Faults and baffles within the reservoir create a complex dynamic system that can only be understood with the integration of 4D seismic data. Monitor surveys in 2007 and 2008 have made major contributions to reservoir management and identification of infill drilling opportunities.
This paper highlights the value of fully integrating 4D seismic into reservoir management, and the rationale for sidetracking a water injector well at short notice to provide pressure support to the field's largest producing oil well. Oil production from this well was dropping rapidly and the need to improve pressure support was clearly evident. It only became clear how best to achieve this upon delivery of new 4D results.
The reservoir model directed attention towards insufficient water injection downdip and the opportunity to sidetrack these injection wells closer to the production wells was under consideration. However, results of the December 2008 4D monitor survey became available at this time, and indicated a reservoir baffle between the oil producer and the downdip injectors, which diverts water away from the producer. Thus improving injectivity at these downdip water injector wells would have had little impact on the failing producer.
The 4D seismic data also indicated that water from a key updip injector was being deflected away from the producer. The difference here was that the baffle was close to the water injector and not the oil producer. The opportunity to sidetrack this water injector across the baffle was rapidly progressed, with the injector sidetrack drilled and completed in mid 2009.
Pressure support at the oil producer was seen within days of commencing injection in the sidetracked well. Revenue from increased oil production paid back the cost of the injector sidetrack and the 4D monitor survey within two months of startup. The involvement of all subsurface disciplines was a key success factor in the outcome.
The Enfield development was the first oil field to be put into production in the Greater Enfield Area. These fields lie in deep water off the North West Cape area of Western Australia. Operated by Woodside on behalf of the Enfield Joint Venture, this was the first oil field development for Woodside requiring horizontal open hole completions with sand control. The challenge for this project was to deliver early oil production from a low well count with wells producing from an unconsolidated and faulted formation containing shale. The remote location posed an additional challenge for the development.
The initial development consisted of 5 producers, 6 water injectors and 2 gas disposal wells, with subsequent campaigns adding 3 production well sidetracks, a new producer and a water injector to the total reservoir penetrations. Both low angle deviated and horizontal wells have been completed. A number of different sand face completion types have been used over the initial phases of the Enfield development. Both water and oil based reservoir drilling fluids were used for this field development. This paper will review the evolution of the design used for the production wells.
Initial horizontal gravel packs were done with a circulating gravel placement technique using brine as the carrier fluid. Subsequently a single barrier sand control technique using expandable screens alone to control sand production was installed. Due to difficulties encountered with these approaches, completion designs reverted to gravel packing. However at this second attempt at gravel packing, a gel slurry packing technique using screen fitted with alternative paths for gravel placement was successfully used.
Whilst deep water open hole gravel packing was a new challenge for Woodside; due to the high productions rates achievable, only a limited number of wells were required for the field development. This implied both a very short learning curve, and a need to react rapidly to any difficulties encountered. This paper reviews the performance of these completions and the drivers for the evolution of the completion technology during the field development. This has provided a pathway for future completions in the development of similar reservoirs in the portfolio.
Enfield lies in approximately 550 m water depth some 35 km north-west of the North West Cape of Western Australia (Figure 1). Operated by Woodside (60% share) on behalf of the Enfield Joint Venture, the field extends some 4 km. from the gas-oil contact to the oil-water contact. The reservoir has a thickness between 14 and 50 m and an oil column of 180 m.
The Enfield reservoir is characterised by high NTG sandstone (Macedon) with excellent porosity (21-25%) and permeability (500-2500 m). Enfield contains biodegraded crude with an API gravity of 22° and no H2S has been measured. Enfield-5 confirmed the presence of a gas cap, and an aquifer was penetrated in the north of the field by Enfield-2. Bottom hole temperature is 70 ºC and the initial formation pressure was 3,069 psi at the reservoir datum depth of 2070 mTVD.
Integration of key information in the early life of the Enfield water-flood development project led to improved understanding of the reservoir's architecture and dynamic behavior. This paper provides an overview of the field and a review of the first two years of production from the Enfield reservoir including start up of the field, water injection optimisation, acquisition and interpretation of Australia's first time lapse ‘4D' seismic survey, key well and reservoir performance learnings, use of chemical tracer technology to monitor fluid movement, and the benefits of comprehensive real time field data transmission to shore.
The Enfield field, discovered in April 1999, is located offshore North West Cape, Western Australia in license WA-28-L. Water depths range from 325m to 550m across the field. Following appraisal drilling and development studies the field was sanctioned for water-flood development in March 2004. The Upper Jurassic Macedon reservoir comprise generally clean, high permeability, unconsolidated sandstone containing a 22° API, moderate viscosity, relatively low GOR oil which is overlain by a significant gas cap. The field has been developed to date via a total of fourteen sub-sea production, water injection and gas re-injection wells producing to a new-build, double hulled FPSO (the ‘Nganhurra'). All five production wells, including three high rate horizontal wells, are completed with open-hole gravel packs for sand control. Key challenges during the development execution phase were operating in an extremely environmentally sensitive, cyclone prone deepwater area, in which there was no existing infrastructure or production operations experience.
Production commenced on 24th July 2006 with oil rates peaking at 74,000 bbl/day in September of that year. Initial production rates were constrained by the slower than expected establishment of pressure support from water injectors and then fell to about 43,000 bbl/day in October when a key production well was shut-in due to high levels of sand production. Significantly different water breakthrough and water cut development in two of the production wells coupled with dynamic pressure data and insights from 4D seismic across the field have started to reveal reservoir complexity greater than previously expected, although overall reservoir connectivity appears to be good.
During the first two years of production operations the reservoir and facility performance has generally been good and in line with pre-development reservoir models, with the exception of sand control in all three key horizontal production wells, each of which were eventually sidetracked in order to install effective open-hole gravel packs in ~600m horizontal sections.
The Enfield oil field was the first offshore hydrocarbon field to be developed within the Exmouth Sub-Basin, offshore North West Cape, Western Australia (Fig. 1). As such, the project had to face a number of additional uncertainties and challenges during start up and early field life compared to greenfield projects in established producing areas offshore Australia. The field itself, which takes its name from the classic British Royal Enfield ‘Bullet' motorbike, is located in production permit WA-28-L, some 38km north of North West Cape and 50km north of Exmouth, offshore Western Australia. The field is jointly owned by Woodside Energy Ltd (60%, Operator) and Mitsui E&P Australia Pty. Ltd. (40%). Water depth across the field varies from approximately 325m in the east, where the production facility is located, to 550m in the west, with the area being subject to strong and variable marine currents.