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Collaborating Authors
SPE Hydrocarbon Economics and Evaluation Symposium
Abstract Facilities decisions are often disconnected from anticipated reservoir performance. A frequent result of this disconnect is operating reservoirs in a sub-optimum manner to protect surface facilities that have inadequate strength. This paper will review the facilities decisions that have been made in several Coalbed Methane (CBM) and Coal Seam Gas (CSG) fields around the world and discuss the reasons for and the impact of those decisions on the performance of the reservoirs. The source of the disconnect is that "everyone knows" that CBM and CSG fields "require very low pressures". With that assumption you then apply safety and procurement principles to come to a design. There is a stage in the production life of these fields where very low pressures are required for reasonable recovery levels, but that stage is typically reached 10-15 years after first production. Setting late-life surface facilities at first-production results in choking the reservoir for over a decade, setting compression many years before it is actually required, and less ultimate recovery as a percentage of original gas in place than would otherwise be achieved. These problems can be overcome by understanding the life cycle performance and risks of an unconventional reservoir and accepting that any tradeoff between facilities performance and reservoir performance must be biased in favor of optimizing reservoir performance in order to have acceptable economic results.
- North America > United States > Colorado (0.28)
- North America > United States > Texas (0.28)
- North America > United States > New Mexico > San Juan Basin (0.99)
- North America > United States > Colorado > San Juan Basin (0.99)
- North America > United States > Arizona > San Juan Basin (0.99)
- (2 more...)
Abstract Argentina and Mexico have been long-term natural gas producers, supplying most of their domestic gas demand. However, due to a decline in the production of their associated and non-associated gas fields in recent years, the gap between the production and domestic consumption of natural gas has widened. An updated EIA 2013 assessment of shale gas resources per country ranks Argentina and Mexico as the second and sixth largest in terms of technically recoverable shale gas resources with risked most likely estimates of 802 Tcf and 545 Tcf respectively. The impact of these newly identified gas resources on future supply is a key question, of particular importance is whether shale gascould bring about a reversal in the current decline in gas production over the next few decades. In view of the large resources identified, renewing the energy policies in Argentina and Mexico could serve as the main driving force for unlocking shale gas production. In order to analyse both countries, natural gas market data available for the period 2011 to present, were reviewed. To examine the current situation of both countries, the following were analysed: the hydrocarbon law (related to gas production), the structure of the both markets, price incentives and fiscal regimes. This paper concluded that the main criterion which is likely to control shale gas development in either Mexico or Argentina, is the trend of the natural gas prices at which both countries trade. Model results demonstrate how the development of shale gas is relatively unattractive in Mexico due to it adopting Henry Hub gas prices. In contrast, a model for Argentina shows how the uplift in gas prices at wellhead has spurred shale gas exploration investment in Argentina.
- North America > Mexico (1.00)
- North America > United States > Texas (0.95)
- South America > Argentina > Patagonia (0.68)
- (2 more...)
- Phanerozoic > Mesozoic > Cretaceous (0.70)
- Phanerozoic > Mesozoic > Jurassic (0.47)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > Mexico Government (0.72)
- Government > Regional Government > North America Government > United States Government (0.59)
- South America > Argentina > Tierra del Fuego > Magallanes Basin (0.99)
- South America > Argentina > Tierra del Fuego > Austral Basin (0.99)
- South America > Argentina > Patagonia > Golfo San Jorge Basin (0.99)
- (17 more...)
Abstract In the oil and gas industry, the term "business planning" brings visions of late nights, additional meetings, and countless hours spent collecting and reconciling large amounts of data. This negative connotation has been reinforced over the years as companies struggle to pull together the information they need to create realistic and achievable plans and to forecast future development to guide the growth of their business. It is unfortunate that business planning has such a bad reputation as it is critical to the success of any company in any industry. In business planning, the goals are simply to select the best projects from a portfolio of opportunities to maximize the return on investment, while being able to effectively communicate the details of how the different scenarios were created to provide confidence in the decision to invest. This paper describes a case study in which one of Occidental Oil and Gas Corporation (Oxy BU) business units improved a few key elements in their business planning process which helped them create a more realistic, higher return plan, faster. The Oxy BU saw the potential rewards that improvements to their planning process could generate by improving their planning efficiency, reducing errors, and breaking out of the same painful cycle they had experienced in previous years. In this paper, we present the results of the improved workflow, focusing on those which were seen to have the largest impact on results including: Using this new approach, the Oxy BU planning team was able to turn around three different investment scenarios, numerous development strategies, and create a five-year, long-range plan that the entire management team could present and stand behind.
Abstract It has been shown in the literature that the oil and gas industry deals with a substantial number of biases that impact project evaluation and portfolio performance. Previous studies concluded that properly estimating uncertainties will significantly impact the success of risk takers and their profits. Although a considerable number of publications investigated the impact of cognitive biases, few of these publications tackled the problem from a quantitative point of view. The objective of this study is to demonstrate the value of quantifying uncertainty and evaluate its impact on the optimization of oil and gas portfolios, taking into consideration the risk of each project. A model has been developed to perform portfolio optimization using Markowitz's theory. In this study, portfolio optimization has been performed in the presence of different levels of overconfidence and directional bias to determine the impact of these biases on portfolio performance. The results show that disappointment in performance occurs not only because the net present value (NPV) of the realized portfolio is lower than estimated, but also because the risk of the realized portfolio is higher than estimated. This disappointment is due to both incorrect estimation of value and risk (estimation error) and incorrect project selection (decision error). The results of the cases analyzed show that, for investors with high-risk-tolerance, moderate overconfidence and moderate optimism result in an expected disappointment of about 50% of the estimated portfolio. For investors with low-risk-tolerance, the same amounts of moderate overconfidence and optimism result in an expected disappointment up to 78% of the estimated portfolio. The value of reliably quantifying uncertainty is reducing the expected disappointment and the expected decision error. This can be achieved by eliminating overconfidence in project evaluation and portfolio optimization; optimism is reduced in the process. Consequently, overall industry performance can be improved because reliable uncertainty assessment enables identification of superior portfolios, with optimum reward and risk levels, and increases the probability of meeting expectations.
Abstract Suppose we plan to develop a field by drilling up to N wells. Each well i (= 1 to N) will produce an uncertain quantity of reserves Xi. We assume that the Xi are identically distributed with common mean m and variance s This is often reasonable, as companies view the development of unconventional reservoirs as a statistical plays; some wells will be profitable and others will not. Lacking an ability to identify the wells that fall into each category, a package of wells is drilled with the hope that the average reserves m will exceed some minimum threshold t. We further assume that given m and s are known, the wells are probabilistically independent. Therefore, we assume the wells are independent and identically distributed (iid). In practice, the iid assumption means that (1) we do not have any reason to believe one location is likely to be more profitable than any other and (2) the drilling results at one location do not change our beliefs about the potential profitability of another location, given that m and s are known. If either m or s are uncertain then prior drilling results at one or more locations will tell us something about the future prospects for the field.
Abstract Current water management strategies require recycling and reuse of oil sand process affected water (OSPW) to as much as 80%. Continuous recycling and reuse of OSPW degrades water quality as the concentrations of total dissolved solids (TDS) and dissolved organic materials (DOM) accumulate. This results in a net increase in operating and maintenance costs and an impact on the extraction process and bitumen recovery. Remaining water containing fines and suspended clays adds to the mature fine tailings and associated problems for tailings pond treatment and management. Presence of residual bitumen and other organics is known to create difficulties in common practices for flocculation and dewatering of tailings. With the problems stated above, one may consider a pre-treatment approach rather than the common post-treatment remedies. The ore grade profoundly affects the efficiency of bitumen recovery in the hot water extraction of bitumen, the principal step in the bitumen extraction process. Sodium hydroxide is commonly added to the conditioning step to improve bitumen recovery. As the sodium ions build in concentration, they disperse clays in the ore and create tailings that resist dewatering. This is especially true for low-grade and oxidized ores, which present the greatest challenges in bitumen recovery and produce the major portion of tailings due to high fines content. With current trends for increasing production from mining operations to almost double by 2020, industry has to adopt new technologies to manage tradeoffs between water and energy. We present a new approach toward total water management by introducing environmentally friendly process aids that can improve bitumen recovery from low-grade oil sands ores. Lab-scale experimental data from a Denver flotation cell and hydrotransport loop were analyzed to evaluate the efficiency on the processability of high and low grade oil sands, water chemistry and tailings management. The results demonstrate that using new process aids during the conditioning stage improves bitumen recovery from low-grade oil sands and can accelerate tailings settling. This pretreatment approach can be incorporated into current oil sands mining processing facilities and delivers environmental and economical benefits. A critical evaluation for use of new process aids versus sodium hydroxide is given in detail.
- Overview > Innovation (0.54)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.48)
Abstract Since the early days of the petroleum industry, prediction of oil prices has been a real challenge. The puzzling question we need to answer when evaluating project's NCF is: how much is the price of a barrel during the life-span of the project? Accordingly, oil price modeling became a vital tool to predict both short- term and long-term prices. Unfortunately, there are many uncertainties associated with the available models and none of them can predict oil prices with acceptable accuracy. Only limited controlling parameters are captured by these models. These parameters are basic and derived from simple assumptions of supply and demand dependency. Nowadays, the need for a reliable oil price model became more critical as a change of oil price is experiencing dramatic fluctuations that affect economic decision parameters a great deal. This paper presents an oil-price model to project the price behavior in the next 20 years. Different scenarios were examined out of which "Economic-Scenario" was found to be the best suitable predictor. This model takes into account multiple effects of fourteen parameters that are believed to have the highest impacts on oil price. These factors have been further classified into key categories such as supply, demand, reserve and externalities (political/environmental/social) which is regionally based. Other parameters such as population growth and technology are embedded within these key factors. According to this model, oil price has been found to have strong reliance on the US Dollar and inflation, which has been incorporate into the model to ensure a more reliable outcome. Market behavior modeling is a continuous process which is planned to be integrated into the proposed model in the near future once consistent data become available. The major obstacle in modeling market behavior is the lack of futuristic behavior that is primarily dependent on accurate historical data. This data should reflect the performance of short-term effects such as lifestyle, human behavior, politics, conflicts, wars, natural disasters, environmental issues and other economies’ behaviors. The ultimate goal of this modeling effort is to assist in economic and risk analysis evaluation of petroleum projects.
- Asia (0.94)
- North America > United States > Texas (0.30)
- North America > United States > California (0.28)
- Oceania > Australia > Victoria > Bass Strait > Gippsland Basin (0.89)
- North America (0.89)
Abstract Currently, most reserves estimates in horizontal wells drilled in unconventional environments are done using modified hyperbolic decline. However, most of the observed production data is recorded when the well is in linear flow, and as such b factors larger than one are frequently observed and terminal decline rates are based on estimations. Attempts at correct for this behavior such as modified power law decline tend to require just as many variables to match curves. In this paper we will propose a method for decline curve analysis of wells that can be generalized to any well that has linear flow behavior. This equation can be integrated and shown to match curves as well as other methods of decline curve analysis and reserve estimation currently available. Lastly, the method will be shown to be highly robust and effective in a number of difficult to forecast environments.
- North America > Canada > Alberta (0.30)
- North America > United States > North Dakota (0.29)
Abstract Growth in reserves from existing reservoirs has been the primary contributor to reserve additions in most mature basins. Historically, infill drilling has been the main driver for reserves growth for the Western Canadian Sedimentary Basin (WCSB) and other parts of the world. This study examines the other why's of reserve growth in WCSB. Examination of historical trends in fields shows that injection processes (Enhanced Oil Recovery, waterflooding) dominate reserves growth in WCSB, and have been the reason for an increasing oil rate in the region. This paper will examine performance of both legacy production and infill well drilling programs and relate it to drive mechanism. Production trends in Canada will be presented as well as the incremental production and contribution to WCSB seen from the infill programs. Next, EOR development will be analyzed. Again, production trends in Canada will be presented and incremental oil contribution due to each individual EOR method will be shown. A brief look at USA EOR experience will also be analyzed. The influence of technology growth and oil price will be reviewed for both infill and EOR oil pools.
- North America > Canada > Saskatchewan (1.00)
- North America > Canada > Northwest Territories (1.00)
- North America > Canada > Manitoba (1.00)
- (2 more...)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Manitoba > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Management > Asset and Portfolio Management > Reserves replacement, booking and auditing (1.00)
- Management > Asset and Portfolio Management > Field development optimization and planning (1.00)
Abstract This paper tells the story of the steps that an E&P company took in implementing a methodology to plan, deliver and execute capital projects predictably. It addresses the challenges that any organization faces in effecting change, as well as the actions taken to ensure success for the initiative. This story can serve as a blueprint for any organization that wishes to improve capital performance. The focus of the paper is not so much the solution implemented, but rather the steps the organization took to ensure a successful implementation. In this paper, the terms "project delivery system" and "asset development system" will be used interchangeably. The company wanted to improve the predictability of its delivery of major capital projects. The company felt that to meet its business objectives, one of many things it needed to do was improve its capital execution or asset development performance. E&P companies have many paths to growth while achieving sustainability. A traditional approach is to grow via exploration while producing efficiently. Exploration and production are recognized critical competencies for E&P firms. What is often not appreciated is that the path from exploration to production must go through asset development or capital project execution. The figure below illustrates the three major competencies that an E&P company needs to grow. Often, firms choose the acquisition path in lieu of exploration. Nonetheless, short of acquiring fully mature assets, there is always some exploration work necessary