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Results
Abstract The decision to carry out a water or gas shut-off treatment in an oil well, is of concern to the petroleum engineer. The engineer must choose an explicit course of action with the information at his disposal. This decision however, has consequences that cannot be predicted with certainty. Water or gas shut-off treatments don't turn out the way we plan, because the outcome could be a success or a failure. Traditional economic method of evaluating water and gas shut-off decisions typically involved cash flow considerations, such as net present value, which combine single point estimates to predict a single output. This method is deterministic, ignores the quantitative consideration of risk and uncertainty as one could be conservative with some estimates while being optimistic with others. The combined errors in this approach frequently lead to results that are significantly different from reality. Thus, a technique that will overtly include uncertainty in our estimates to generate results with all probable outcomes will aid the engineer in making an informed choice. In this paper, the expected value economic concept is used for the mutually exclusive events of water and gas shut-off treatments. Through expected value and standard deviation of a random variable, Monte Carlo simulation and decision tree analysis, incorporating uncertainty in oil price, production forecast and operating expenses are used to evaluate the expected return and risk associated water and gas shut-off opportunities. This approach minimizes the chances of failure and provides useful insights for water and gas shut-off economic decision making.
- Africa > Nigeria (0.70)
- North America > United States (0.68)
Abstract The impact of water, gas or a combination of both in oil production is an important aspect of petroleum engineering operations. Some water or gas production could contribute to oil production increase while in some cases such production could be less beneficial. Analytical techniques to quantify the impact are still lacking because the solution to multiphase flow problems in heterogeneous reservoirs is complex. Material balance procedures are deterministic and do not take into account the heterogeneity in reservoir behavior. Simulation techniques could be used but these are very expensive and require, a lot of time and information, which may not be handy. Using time series data analytics techniques, a method has been developed that is used to quantify the impact water, gas or a combination of both will have on oil production, in the short run and in the long run. This technique is also used to determine whether water, gas or a combination of both is a significant causal factor in oil recovery or not. The approach is innovative as it will help to isolate desirable and undesirable water or gas production before applying expensive diagnostics. This new Method has been tested with field data and could be a useful tool for reservoir and production engineers.
- Asia (0.93)
- North America > United States > Texas (0.46)
- North America > United States > California (0.46)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
Abstract Controlling excessive gas and water production from oil wells is still a major problem in the global E & P industry. Various strategies have been advised in the petroleum literature by industry experts and vendors. Different service companies continue to lay claim of innovative Water and Gas Shut-Off (WGSO) products that will offer better results. No doubt, there are noteworthy improvements in unwanted water and gas control technology, the problem however, has continued unabated. Polymers have been developed to help in the reduction of the water-oil-ratio (WOR) while at the same time not limiting the flow of hydrocarbon. Polymer-foam for gas shut off also reduces the GOR, but not the oil flow rate. Though, some successes have been reported in polymer water and gas shut off in oil wells, a survey of field cases however shows, that most treatments have been unsuccessful. Our findings suggest that different diagnostic methods, treatment design and applications vary from vendor to vendor even with the same diagnostics. Companies also use different economic yardsticks to measure the success of WGSO operation. This has led to tremendous failures in polymeric WGSO application. Relying on a data base of WGSO field cases, some treatments could guarantee substantial increase in oil production while in others the production was relatively small, zero and sometimes negative. Several factors could be responsible for these; Wrong diagnosis and poor candidate selection, improper treatment design and application. There is also lack of an economic model to evaluate the success of a polymer water and gas shut off treatment. This paper therefore evaluates the causes of success or failure of the polymer water and gas shutoff treatment in the Niger Delta
- Europe (1.00)
- Asia (1.00)
- North America > United States > Texas (0.28)
- Africa > Nigeria > Niger Delta (0.25)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Abstract It is estimated that on the average, three barrels of water are produced for every barrel of oil. Billions of Dollars are spent each year in treating unwanted water and gas production in oil wells. Water and Gas Shut-Off (WGSO) treatment has helped to reduce cost and improve oil recovery in some cases, while in others, this method has failed to economically recover the remaining oil in the reservoir. Economics drives the oil and gas business because the objective is to take decision that will reduce cost and maximize profit. Any decision that is made without this consideration, may be an exercise in futility. Therefore, detailed economic evaluation as a diagnostic tool for WGSO treatment has become imperative. Despite the technical appeal, WGSO schemes can also be related to games of chance. Company has to decide whether to risk the money or not since it is not certain whether there will be a simultaneous increase oil and decrease in water/gas production. There is absolutely no 100% guarantee of success because the justification for the selection of any WGSO treatment method will be based on the probable incremental hydrocarbon production. Some water and gas control treatment can guarantee substantial production increase while others could be less successful. This introduces some degree of uncertainty, making WGSO treatment a risky venture. So, the quantification of risk and uncertainty is necessary. Though the optimal decisions in water and gas shut off application differ from company to company, the objective however is to obtain a condition under which the marginal and total revenue from water shut off will be equal to the marginal and total cost of the operation. To Optimize WGSO application in oil wells, we must determine the production rate that maximizes its total profits. Against this backdrop therefore, an economic model is developed that is used to evaluate water and gas shut-off candidates. This model incorporates Monte Carlo simulation and risk analysis on different reservoir parameters, incremental recovery and oil price to optimize WGSO applications. It allows for the determination of the probability distribution function for the different economic indicators that will help in ranking WGSO opportunities.
Comparative Analysis of Drilling Cost Used for Petroleum Economics in the North Sea, Gulf of Mexico and Niger Delta Regions
Ikwan, Ukauku (Emerald Energy Institute) | Egba, Amba Ndoma (Department of Petroleum Resources) | Dosunmu, Adewale (University of Port Harcourt) | Iledare, Wumi (Emerald Energy Institute, University of Port Harcourt)
Abstract The primary objective of an E & P company is to drill and produce hydrocarbon at minimum cost with high level of safety without compromising environmental standards. With the current global downward slide in oil prices most E & P firms are slashing costs to shore up profitability. Drilling operations are high capital-intensive projects that drive unit production cost northwards. This paper presents a comparative analysis of drilling costs in three geographical locations of the world petroleum provinces viz; North Sea, Gulf of Mexico and Niger Delta with sensitivities of the various elements that affect drilling cost with a view to assisting operators and rig owners on optimizing activities in a lean environment. Relying on panel data sourced from databases of a global energy consultant and industry operators, historical absolute average cost and footage trends were compared during the period of 10 years (2005-2014). A randomly selected well cost data was used to carry out the sensitivity analysis to deduce key determinants. It was found that although there are regional differences that reflect the local geology and some economic factors, drilling times and all costs rise sharply with increasing depth. Also drilling cost for the Niger delta province is highest compared to the other two regions. The sensitivity study showed that the highest contributor to high drilling cost is the intangible element in which the rig rate, hole problems and security issues should be the focus in drilling cost reduction and economics. Contract renegotiation strategy to drive down rig rates and establish new market equilibrium is recommended in this lean environment. Also tangible costs from tubulars can be reduced with favourable policy on reviving Nigerian steel industries to enable local sourcing of these tubulars, improve employment rate hence reduce insecurity in the Niger Delta area.
- North America > United States (1.00)
- Europe > United Kingdom (1.00)
- Africa > Nigeria > Niger Delta (1.00)
- Research Report (0.66)
- Financial News (0.66)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (12 more...)
- Well Drilling > Drilling Operations > Drilling operation management (1.00)
- Management (1.00)
Abstract Hydrocarbon accumulations more often than not straddle two or more license areas or concessions and sometimes, international boundaries. Unitisation is a process whereby petroleum reservoirs (fields) straddling concession boundaries are developed and exploited as a unit using a single operator (the Unit Operator) and common production facilities under a signed agreement (Unitisation Agreement), by the holders of the respective concessions. The objective is to maximise economic recovery of producible hydrocarbon. In Nigeria, the enabling law that gives legal backing for unitisation is the Petroleum (Drilling & Production) Regulation 1969, Section 47, as amended and the 2008 Unitization Guidelines by the Department of Petroleum Resources (DPR). These laws are made pursuant to the powers conferred on the Minister of Petroleum Resources under Section 9 of the Petroleum Act (CAP 350) laws of the Federation of Nigeria 1990. One of the major milestones in the unitization process is the signing of the unitization and unit operating agreement (UUOA). The UUOA specifies how the straddle field is to be operated and defines tract participation (the equity interest, assigned to each Concession in the Unit). As at today, over seventy (70) straddle fields have been identified in Nigeria but not up to five (5) UUOA agreements have been executed. Issues ranging from correct interpretation of Regulation 47,recognizing unitization of straddling and non-straddling reservoirs, to single and combined provisional tract participation (PTP) for oil and gas, economic consideration & contractual disputes, fiscal terms, Redetermination, Reference dates, appointment of unit operator, funding, divestment, political and personal interest etcetera, have made unitization of straddle fields elusive for many years thereby locking down billions of barrels of reserves. This undoubtedly, is not in the national Interest, especially when the Country is striving to increase the Nation's reserves base from the current 36.24 barrels of oil to about 40 billion barrels and the daily production output of 2.5 million bopd to 4.0 Million bopd by year 2020. This paper therefore examines the synopsis of unitisation and joint development of straddle fields in Nigeria, the concerns and pitfalls arising thereof. The evaluation of some selected cases is also made to ascertain the effect of delay from Government objectives of reserves addition and production along with suggestions for future policy formulations.
- Africa > Nigeria > Gulf of Guinea > Niger Delta (0.47)
- Africa > Nigeria > Gulf of Guinea > Bight of Bonny > Niger Delta (0.28)
- Africa > Nigeria > Gulf of Guinea > Rivers > Niger Delta > Niger Delta Basin > OML 55 > Belema North Field (0.99)
- Africa > Nigeria > Gulf of Guinea > Niger Delta > Niger Delta Basin > OPL 217 > Agbami-Ekoli Field > Agbami Field (0.98)
- Africa > Nigeria > Gulf of Guinea > Niger Delta > Niger Delta Basin > OPL 216 > Agbami-Ekoli Field > Agbami Field (0.98)
- Africa > Nigeria > Gulf of Guinea > Bight of Bonny > Niger Delta > Niger Delta Basin > OML 99 > Amenam-Kpono Field (0.98)