Lacaze, Sébastien (Eliis SAS. Parc Mermoz, Immeuble l’Onyx, 187 rue Hélène Boucher, 34170 Castelnau-Le-Lez, France) | Philit, Sven (Eliis SAS. Parc Mermoz, Immeuble l’Onyx, 187 rue Hélène Boucher, 34170 Castelnau-Le-Lez, France) | Pauget, Fabien (Eliis SAS. Parc Mermoz, Immeuble l’Onyx, 187 rue Hélène Boucher, 34170 Castelnau-Le-Lez, France) | Wilson, Thomas (Eliis Pty Ltd, 191 St Georges Terrace, Perth WA 6000, Australia)
Summary Structural interpretation from 2D seismic line sets is common in the hydrocarbon exploration process. Generally, this process consists in the interpretation of several key horizons on the several seismic lines available, which is time-demanding. Furthermore, as the seismic lines are often processed differently, misties are frequently observed between the lines, which may lead to cumbersome interpretation. In this paper, we introduce a method aiming at providing an efficient 2D line seismic interpretation answering the need of obtaining early 3D geological model during reservoir exploration. Introduction Traditional 2D seismic interpretation is generally a complex and time-consuming task which relies on 2D autotracking and the manual picking of a few stratigraphic events on every line.
Haghighi, M (The University of Adelaide) | O'Reilly, DI (Chevron Australia Pty Ltd, The University of Adelaide) | Hunt, AJ (Chevron Australia Pty Ltd) | Sze, ES (Chevron Australia Pty Ltd) | Hopcroft, BS (Chevron Australia Pty Ltd) | Goff, BH (Chevron Australia Pty Ltd)
This paper demonstrates how good technical evaluations and focused operational application can enhance the value of a mature asset. The Windalia reservoir underlies Barrow Island (BWI), situated 56 km from the coast of Western Australia, and has produced oil since 1965. Waterflooding commenced shortly after initial production, in 1967, and remains the main drive mechanism in the field today. Throughout the life of this onshore field, water injection and oil production have varied according to asset strategy and economic conditions. In this case study, we share how recent improvements made in the areas of Reservoir Surveillance and Operations activities have increased water injection efficiency and total oil recovery.
Through the use of new methods and workflows, the BWI Sub-Surface team was able to target specific areas of the field to distribute water to in order to increase injection and maximise oil production. For example, new workflows were built with the real-time PI monitoring system to analyse Pressure Fall Off (PFO) tests from each of the 147 waterflood patterns in detail. Capacitance-Resistance-Modeling was also leveraged to guide individual well target injection-rates. Operationally, several projects were also initiated to increase water injection into the right areas of the field.
The new Reservoir Management approach has significantly increased the volume of water being injected into the areas of need, supporting improved levels of oil production. For the first time in almost 10 years, the stream-day water injection rate has exceeded 90,000 bwipd. The results from PFO transient interpretation and pattern balancing proved effective in directing water to low-pressure, high-GOR areas of the field. They also provided valuable information about formation perm-thickness and skin. The phenomenon of water-cycling was also largely avoided, owing to close monitoring of production well tests and water injector transient surveys.
The present work addresses reservoir and operational aspects of Australia's largest active waterflood. The lessons shared are highly applicable to a low oil price environment, as they show how fit-for-purpose and low-cost acquisition of reservoir data can lead to improved field performance.
DI, O'Reilly (Chevron Australia Pty Ltd, The University of Adelaide) | BS, Hopcroft (Chevron Australia Pty Ltd) | KA, Nelligan (Chevron Australia Pty Ltd) | GK, Ng (Chevron Australia Pty Ltd) | BH, Goff (Chevron Australia Pty Ltd) | M, Haghighi (The University of Adelaide)
Barrow Island (BWI), 56 km from the coast of Western Australia, is home to several mature reservoirs that have produced oil since 1965. The main reservoir is the Windalia sandstone, and it has been waterflooded since 1967, while all the other reservoirs are under primary depletion. Due to the maturity of the asset, it is economically critical to continue to maximise oil production rates from the 430 online, artificially lifted wells. It is not an easy task to rank well stimulation opportunities and streamline their execution. To this end, the BWI Subsurface Team applied Lean Six Sigma processes to identify opportunities, increase efficiency and reduce waste relating to well stimulation and well performance improvement.
The Lean Sigma methodology is a combination of "Lean Production" and "Six Sigma" these are methods used to minimise waste and reduce variability respectively. The methods are used globally in many industries, especially those involved in manufacturing. In this asset, we applied the processes specifically to well performance improvement through stimulation and other means. The team broadly focused on categorising opportunities in both production and injection wells and ranking them, specifically: descaling wells, matrix acidising, sucker rod optimisation, reperforating and proactive workovers. The process for performing each type of job was mapped and bottlenecks in each process isolated.
Upon entering "Control" phase, several opportunities had been identified and put in place. Substantial improvements were made to the procurement, logistics and storage of hydrochloric acid (HCl) and associated additives, enabling quicker execution of stimulation work. A new programme was also developed to stimulate wells that had recently failed and were already awaiting workover, which reduced costs. A database containing the stimulation opportunities available at each individual well assisted with this process. The project resulted in the stimulation of several wells in the asset with sizable oil rate increases in each.
This case study will extend the information available within the oil-industry literature regarding the application of Lean Sigma to producing assets. It will assist other Operators when evaluating well stimulation opportunities in their fields. Technical information will be shared regarding feasibility studies (laboratory compatibility work and well transient testing results) for acid stimulation and steps that can be taken to streamline the execution of such work. Some insights will also be shared regarding the most efficient manner to plan rig-work regarding stimulation workovers.
Towler, Brian F. (School of Chemical Engineering, The University of Queensland) | Firouzi, Mahshid (School of Chemical Engineering, The University of Queensland) | Holl, Heinz-Gerd (Centre for Coal Seam Gas, The University of Queensland) | Gandhi, Randeep (QGC Pty. Ltd) | Thomas, Anthony (QGC Pty. Ltd)
Many field trials have been conducted to explore the effectiveness of using hydrated bentonite as a sealing material for plugging and abandoning (P&A) operations of oil and gas wells. Many of those trials are reviewed here, including trials in Texas, New Mexico, Oklahoma, Wyoming and Queensland, most of which have not been previously reported. All of these trials have been successful, even though a few wells have been eliminated from the programs because they were found to be unsuitable. In most jurisdictions regulation changes are necessary to allow bentonite to be used in order to plug wells. This has been done in California, Texas and Oklahoma. In Wyoming it is currently permitted as the bottom plug in coal-bed methane wells. In Queensland a field trial has been allowed under the experimental materials clause in the regulations.
The Barrow Island Oil Field lies 56 kilometres off the northwest coast of Western Australia and has produced oil since 1965. The field is located on Barrow Island in a Class A Nature Reserve and currently produces around 5,000 barrels of oil per day from 468 oil producers and injects 80,000 barrels of water per day from 268 water injectors, which in the 2016 oil price environment creates some significant business challenges. A change in the Operator's asset leadership team coupled with a falling oil price environment through 2014 and 2015 provided an opportunity to change the way the asset was being managed. Change was facilitated by two key factors: the new asset personnel brought new perspectives, experiences and skills to the asset and the falling oil price provided a case for urgency. These two factors resulted in an enhanced focus on business purpose, minimum business needs/work scope and execution focus.
Copyright 2013, Offshore Technology Conference This paper was prepared for presentation at the Offshore Technology Conference Brasil held in Rio de Janeiro, Brazil, 29-31 October 2013. This paper was selected for presentation by an OTC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material does not necessarily reflect any position of the Offshore Technology Conference, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of OTC copyright. Abstract Subsea processing and boosting can be key enablers or optimization alternatives for challenging field developments and their benefits increase with water depth, flowrates and step-out. Petrobras has invested a lot on the development of such technologies, supported, among other pillars, on an aggressive R&D policy through its technological programs like PROCAP, and several subsea processing and boosting systems have successfully operated in Petrobras fields. This paper aims to give an overview of the systems developed and applied in Petrobras prospects during the last twenty years, such as the Vertical Annular Separation and Pumping System (VASPS), Boosting Systems with Electrical Submersible Pumps (Mudline ESP and MOBO), Subsea Multiphase Pumps, Subsea Raw Water Injection and Subsea Oil-Water Separation (SSAO).
Oil and Gas Facilities' "Global Market Trends" in April reported that FPSO account for USD 18 billion of the USD 20 billion in FPS spending expected over the next 5 years. The converted tanker FPSO Cidade de Paraty sails away from the Brasfels shipyard in Brazil. October 2013 - Oil and Gas Facilities 17 Although there has been a shift toward newbuild FPSO, especially for developments in harsh environments, very large crude carrier (VLCC) tanker conversions remain the basis for projects in areas where benign environmental conditions (mild sea waves and swells) are predominant, such as off west Africa, southeast Asia, Australia, and Brazil. Providing flexibility and mobility, tanker conversions in some cases offer quicker production of first oil. In March, Maersk Tankers sold the Maersk Eli, built in 2000, to SBM Offshore for approximately USD 32 million.
The converted tanker FPSO Cidade de Paraty sails away from the Brasfels shipyard in Brazil. As deepwater exploration and production grows globally, floating production, storage, and offloading (FPSO) vessels continue to dominate expenditure on floating production systems (FPS). Oil and Gas Facilities’ “Global Market Trends” in April reported that FPSO account for USD 18 billion of the USD 20 billion in FPS spending expected over the next 5 years. Although there has been a shift toward newbuild FPSO, especially for developments in harsh environments, very large crude carrier (VLCC) tanker conversions remain the basis for projects in areas where benign environmental conditions (mild sea waves and swells) are predominant, such as off west Africa, southeast Asia, Australia, and Brazil. Providing flexibility and mobility, tanker conversions in some cases offer quicker production of first oil.
This paper is based on work performed during design, implementation and operation of the Cascade and Chinook fields in ultra-deep waters of the U.S. Gulf of Mexico. It describes how Regulatory compliance was accomplished for this the first Floating Production Storage and Offloading System in the Gulf of Mexico and the decision making towards selecting a disconnectable Floating Production Storage and Offloading System and critical activities from award to operation of this innovative disconnectable Ultra Deep Water FPSO in over 8,200 feet of water, making it the deepest moored FPSO. It is an Early Production System (EPS) that will establish production potential prior to installing the full production facility for the production potential anticipated. Crude is offloaded by tandem offloading to Jones Act shuttle tankers.
The path Petrobras took, from applying for approval from the U.S. Regulatory Agencies for the use of a Floating Production Storage and Offloading system (FPSO) with tandem offloading to purchase of the Cascade and Chinook (C&C) fields and to produce both fields with a FPSO, was challenging in many ways.
Petrobras accepted the challenges of having to incorporate new technology, breaking records in the process to achieve production in these ultra deep water fields, complying with Regulatory Agencies requirements that did not necessarily have language in the regulations that were specifically applicable for an FPSO in U.S. waters and to install an EPS FPSO to produce in gulf of Mexico where no FPSO had ever produced before.
FPSO technology for use as a production facility was considered state-of-the-art worldwide but was not yet accepted in the U.S. Gulf of Mexico (USGoM), when Petrobras embarked on the project to install the first FPSO in USGoM, realizing it would be a challenge. Petrobras development strategy was to produce C&C fields from a common facility. Petrobras successfully achieve their goal of producing the C&C fields with the first FPSO in the USGoM. The EPS FPSO, BW Pioneer, is currently producing from both these fields.
This paper will provide insights into the path taken to successfully complete this challenging project that included; close cooperation with US Regulatory Agencies to accept FPSO production facilities, changes in ownership of the fields, submission for approval of concept to the MMS and USCG, steps in the project to get the leased EPS FPSO to the field and tools to assist operations and production.
Subsequent to completion of the C&C project, the US Regulatory Agencies preference has shifted from a permanently moored FPSO (as evaluated in the EIS) to a disconnectable FPSO (as approved for C&C fields).