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While the first subsea production system was installed in a shallow water environment (West Cameron field in Gulf of Mexico, by Shell in 55ft water depth, 1961), subsea development concept has been more synonymous with deepwater development. It has not been a development concept of choice for shallow water development in Middle East and Asia mainly due to the perception that it has higher life cycle cost and difficult to intervene. Subsea production concept can be a competitive option vis-à-vis topsides production concept in certain circumstances. More often than not, project economics dictates that development capital expenditure (CAPEX) requires to be as low as practicable; and pre-investment in the initial phase of the project development needs to be carefully managed to minimize its impact on CAPEX and net present value (NPV). Subsea production system are inherently fit-for-purpose and provide an ideal opportunity for project owners to assess the potential of the particular field before deciding to proceed with full-scale development in the subsequent phase. The fact that there is a large number of shallow-water subsea production systems installed and operated worldwide in the last 30 years provide sufficient track record, lifecycle cost and reliability data that could be used by field development and front end engineers in coming up with a feasible development concept with attractive NPV. Subsea production system in a shallow water environment is a proven concept predominantly due to the following factors: 1. Provide alternative development option where fixed structures are not cost-effective: a) Where development costs may not justify the CAPEX for a platform b) Where brownfield expansion requires low well counts 2. Optimize drilling program: a) If field reservoir areas are not reachable by deviated drilling from surface wells, producing hydrocarbon from multiple fixed structures might not be economically feasible b) Subsea completion and production system offer better flexibility in term of field layout and well top-hole positioning 2 SPE-197604-MS
Development of human civilization and the growing demand for energy, as oil reserves around the world continue to deplete, have driven us to start producing from unconventional resources. Gas hydrates is one of the unconventional sources that has excited researchers and energy producers alike due to its immense potential. Numerous studies have shown the presence of gas hydrates in sea beds around the world including Gulf of Mexico. The study of hydrate formation in the Gulf of Mexico is an important step towards recognizing the potential of gas production from these reserves. However, such studies have been limited to seismic mapping and laboratory scale studies, and numerical modeling of hydrate formation has not been studied to quantify these reserves. This study intends to understand the geological and thermodynamic setting in which gas hydrates form in the subsurface and the associated reservoir quality changes (porosity/permeability) as hydrates form.
A geological model, representative of the Gulf of Mexico subsurface, with sand and shale layers with a fault running through them is generated. Thermogenic methane gas flow up the fault is simulated using TOUGH+HYDRATE, a numerical code developed at the Lawrence Berkeley National Laboratory. The code uses integral finite difference method for space and time discretization for modeling multiphase flow. The flow geometry is generated using a MATLAB code developed specifically for this study. Sensitivities on fault angle, flow rate and reservoir properties are simulated to study the hydrate formation process.
Results from the simulation predict that initiation of gas hydrates in the reservoirs appear to directly correlate to increased pressures in the pore spaces as the fluids move up through faults and invade the adjacent formations. Permeability and porosity of the hydrate formation zone decrease as solid hydrates form in the pores. Numerical simulation of gas hydrate formation and the study of rock and fluid flow properties during hydrate formation thus can be used as an important reservoir characterization tool, which can be used for estimation of the hydrate reserves as well as determination of well placement and production strategies.
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.
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.
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 Gorgon project represents a tremendous vote of confidence in the hydrocarbon potential of the Carnarvon Basin, with foundation field resources underpinning a lifecycle of future gas supply projects developing the wider deepwater resource base. With the foundation development costs mostly sunk and production ramping up, investment exposure is at its lifecycle peak and there is intense focus on safe and reliable operations.
However, there is also a need to continue to mature upstream gas supply opportunities. Projects to continue developing the foundation fields are already moving through the planning and development process. Looking beyond those, activities are in progress for selecting the first wave of future gas supply projects and beginning their first steps of development planning.
Distant, deepwater developments carry multiple risks with complex geology, costly and therefore limited data acquisition and record-breaking flow assurance requirements. Long development schedules result in limited ability to respond to uncertainty in foundation subsurface outcomes. Opportunities to maximise lifecycle value include standardisation of "subsea building blocks" and careful planning of new infrastructure to capture geographical and execution synergies.
Chevron and its joint venture participants have invested in an extensive deepwater exploration and appraisal program and are well-positioned to plan for the future. Building a gas supply plan involves a complex combination of portfolio and project principles and processes, drawing upon multiple disciplines and functions in the value chain including exploration and appraisal, early concept project planning, major capital project execution and base business operations.
At this early stage in the Gorgon lifecycle, a pragmatic approach has been taken to deliver effective portfolio planning, providing both the long term view and driving the near term selection decisions for the next wave of supply projects. This paper describes some of the insights and trade-offs being learned and applied in developing the gas supply plan.
Drilling and testing of the East Barrow Gas Field (EBGF) began in 1974. Over the next sixteen years, eight vertical production wells were drilled. In 1988, initial gas reserves were estimated to be 6.2 BCF OGIP with 5.7 BCF recoverable. Despite these early predictions, the field has produced approximately 9.1 BCF of natural gas and the reservoir has maintained pressure at ~ 935 psia, which suggests there are still untapped gas resources within the EBGF.
It was initially believed that continual re-pressurization of the reservoir was caused by an active water drive. However, no significant water has been produced, even from down dip producers. Reservoir modeling was performed to better understand reservoir drive mechanisms and to predict future reservoir behavior. Recent modeling and reservoir simulation strongly suggest that gas hydrate dissociation and negligible water influx is responsible for the constant re-pressurization within the EBGF. Recent drilling and production shows that gas production from the EBGF depressurizes the reservoir and raises the base of the gas hydrate stability zone, unlocking free gas from the hydrate bearing reservoir rock. This is a significant finding, and validates the presumption of commercial gas production from a hydrate resource. This paper summarizes the technical studies conducted to understand the reservoir behavior and the evidence supporting ongoing dissociation and production of methane hydrates from the EBGF.
The natural decline in oil production in Alaskan reservoirs is challenging producers to find methods to extend production. The current stage of reservoir development has reached the point where consideration of enhanced oil recovery methods is appropriate. Such methods could include CO2, chemical, microbial or thermal recovery. However, these methods require significant capital and/or operational investment. This paper evaluates the application of wettability alteration for Alaskan reservoirs by changing injection water chemistry also known as advanced water flooding. We use empirically-based screening and scoping methodologies to evaluate the suitability, cost and benefits of advanced water flooding for Alaskan reservoirs using public domain data.
First, laboratory and field examples of successes and failures are considered. Using this basis, a theory is developed that directly links water chemistry and reservoir wettability. The theory also illuminates the key characteristics of the reservoir that control wettability. We use empirically-based screening and scoping methodologies to evaluate the suitability, cost and benefits of advanced water flooding for Alaskan reservoirs with sufficient public domain data. The screening tool is built on empirical data from laboratory and field tests that identify the critical factors contributing to incremental production. The scoping tool uses a modified Kinder Morgan approach (dimensionless recovery curve) to evaluate the economic case for each reservoir.
The first field-scale tests of this technique were conducted by BP in the Endicott reservoir on the North Slope and produced good results by lowering the salinity of injection water. Those tests showed that alteration to injection water chemistry can increase recovery significantly. These results have been duplicated in laboratory and field tests in other locations. The tests were conducted without an understanding of the fundamental mechanisms nor optimization of the injected water chemistry, and thus represent minimum recovery. We find the increased recovery is profitable for several fields depending on assumptions about water sources, water treatment costs and rates of injection.
The successful approach to advanced waterflooding requires several key steps: screening the formation to evaluate the applicability of the technique, simple laboratory tests to determine the optimal water chemistry and quantify the increased recovery, economic evaluations to estimate costs and benefits, and finally, comprehensive geochemical models to design the wettability-modifying fluids. The technique has several advantages compared to current methodologies for wettability alteration including substantially lower costs, no environmental impacts and ease of application.
Multiple development options are currently available for the production of LNG with the gas extracted from ultra-deepwater gas reservoirs. The main are (a) Subsea-to-Beach coupled with onshore LNG - with or without late-field-life gas compression; (b) Dry-tree/ Wet-tree Host coupled with onshore LNG; and (c) Floating LNG. Subsea-to-Beach and Dry-tree/ Wet-tree Hosts are field-proven options, within their own respective technological limits and financial applicability boundaries, and are being used for major capital projects. FLNG is now in the commercial phase with several worldwide projects under execution, and is becoming a more and more popular alternative development ‘building block’ to be adopted in some specific cases. Several factors affect the decision on the ‘best’ development option for ultra-deepwater gas reservoirs. The readiness status of subsea technologies is one of these factors due to the fact that a subsea production system is required in all the development options discussed here, as well as location and features of the reservoir(s) to be produced, the recoverable reserves, and the size of the LNG train(s) and of the entire offshore and onshore facilities. In the light of the increasingly wider interest of the industry in FLNG developments for offshore gas fields, it is worth creating simplified, yet reliable and robust, work methods to confidently discuss the Subsea-to-Beach and FLNG alternatives for a given project. The present paper is a contribution to this discussion on Subsea-to-Beach versus FLNG, especially to the identification of the applicability limits for these development options. Relevant Subsea-to-Beach and FLNG projects are selected and reviewed; the technological limits of the enabling subsea technologies are investigated; the key technical and decision factors in the Concept Selection are assessed and then discussed with respect to non-technical factors such as HSE, risks, economic viability and technology readiness status.