Oilfield Projects Research Articles

Formalization of organizational structure of the superviscous oil field project management

Formalization of organizational structure of the superviscous oil field project management

Effect of Nanoclay on Heavy Oil Recovery During Polymer Flooding

Polymer flooding for improving sweep efficiency has been studied extensively in laboratory and tested in fields for conventional oils. A novel nanofluid based on polyacrylamide clay has been developed and its properties have been experimentally tested as a suitable candidate in polymer flooding for oil field projects. This authors review the polymer flood fundamentals as they are applied to heavy oil recovery. In this study, they focus on roles of clay nanoparticles on polymer viscosity and improve recovery in heavy oil recovery. The theory is supported with coreflood and physical model results for several oils ranging in viscosity from 200 to 4200 mPa.sec. For some of these coreflood tests the nanopolymer flood was able to increase the oil recovery in comparison to a baseline polymer flood. These laboratory results will be helpful for the planning of nanoclay polymer flooding for heavy oil reservoirs. Also flooding test showed a 5% increase in oil recovery for nanoclay polymer solution in comparison with polymer solution after one pore volume fluid injection.

Joint venture formation and partner selection in upstream crude oil section: goal programming application

In the past three decades, the magnitude of business dynamics has increased rapidly due to increased complexity, uncertainty and risk of international projects. This fact made it increasingly tough to ‘go alone’ into the international projects. As a consequence, companies with diverse strengths and weaknesses cooperatively bid for joint ventures (JV) formation. Joint venture is also a well-established aspect of the crude oil industry, specifically in the upstream segment. Making decision on the optimal form of JVs is still a challenging problem. In addition, the success of a JV is intertwined with the accuracy of the partner selection phase. Therefore, this paper formulates a multi-criteria mathematical model to select the best partners and form an optimal JV for undertaking oilfield projects. The lexicographic goal programming technique is employed to minimise undesirable deviations from diverse goals such as resources needs (technological and expertise), budgetary requirements, time, etc. The model is validated with a real-life-based example and provides insightful views on alternative formats of cooperation.

Optimization of piping expansion loops using ASME B31.3

Piping is the main transportation method for fluids from one location to another within an industrial plant. Design and routing of piping is heavily influenced by the stresses generated due to thermal effects and high pressure of the operating fluid. In particular, pressurized fluids create critical loads on the supports and elbows of the pipe which increases the overall stresses in the piping. Moreover, long pipes operating under high temperature gradients tend to expand significantly. Therefore, designers and engineers usually provide an expansion loop in order to relieve the pipe from the critical stresses. However, expansion loops require extra space, supports, elbows, bends, additional steel structure that could adversely affect the operating cost. It is therefore necessary to optimize the geometry, the number of expansion loops, and the supports. Reducing the number of loops in one single system or reducing the length of the loop itself is always favored as long as stresses are within safe limits. Usually, the commercial software (PipeData) is used in the industry to get the dimensions of the expansion loop. However, this software is mostly based on empirical models that rely on past experience rather than engineering fundamentals. Accordingly, this paper conducts an optimization analysis concerning the expansion loop dimensions and the number of supports without compromising on the safety of piping. The design approach is conducted as per the guidelines of ASME B31.3 (Process Piping) code and uses the commercial software (CAESAR II) for stress calculations. A full comparison for the expansion loop dimension is conducted between the empirical approach and the optimization analysis using ASME B31.3 for one of the existing oilfield projects. Results indicate that optimization reduces the dimensions and the number of expansion loops as well as the total number of supports. This results in significant savings in the piping cost without any compromise on the safety.

Method for Consistent Valuation of Assets With Multiple Sources of Uncertainty

Summary A simplified version of the Smith and Nau (1995) integrated solution scheme is applied to the valuation of an oilfield project possessing salvage options and both private and public uncertainties. It is shown that the computed valuation is consistent with the definition of the real option price as the maximum value that could be obtained, without market risk, from an ensemble of projects that sample the private uncertainty. The attainment of this value requires an optimal decision strategy and a hedging strategy, both of which are obtained as a byproduct of the valuation. The interpretation of the obtained value is validated by forward simulation over an ensemble of projects, by use of a fully reproducible worked example.

Promotion of Sustainable Oil and Gas Operations in Africa

Many countries in sub-Saharan Africa are aggressively developing infrastructure, analytical support systems, and human capital to support economic growth objectives and interregional competition in key economic sectors. Energy is the lifeblood of economic development activities. In the case of some sub-Saharan African countries such as Nigeria, Angola, Gabon, Equatorial Guinea, and Cameroon, oil and gas dominate the national economy. This is the case despite the acknowledged global climate change impacts of an increasingly carbon-dominated global economy. Still, the production of more gas for development of gas-powered electric power plants as replacements for the coalfired plants, which emit more pollution, is at least a desirable intermediate step toward more sustainable power systems. Estimates of the crude oil reserves for Nigeria, the most populous African country with a population of 150 million , range from 24.0 billion barrels to 31.5 billion barrels. Nigeria’s proven natural gas reserves are about 124 trillion cubic feet Tcf , which ranks ninth in the world. Many large projects, such as the construction of the $7 billion, 4,000-kilometer Trans-Saharan Gas Pipeline to convey gas from the Niger Delta of Nigeria to the export terminal at Beni Saf in Algeria; the $620 million West African Gas Pipeline that will traverse Nigeria, Benin, Togo, and Ghana; the Nigerian Liquefied Natural Gas Project, which is projected to generate about $1 billion per year over a 22.5-year operational period; and Ghana’s $750 million Jubilee Oil Field Project, underscore the growing role of the oil and gas sector in the African economy. Currently, the scarcity of trained personnel for support of oil and gas industry operations is limiting growth in this economic

Probabilistic Aggregation of Oil and Gas Field Resource Estimates and Project Portfolio Analysis

Summary Probabilistic aggregation and dependency estimation are essential in portfolio methods, production forecasting, and resource estimation. The use of arithmetic addition understates the true value of the resource estimates within a portfolio of fields. Potentially, this could result in deferral of a project, or loss of lucrative business and commercial opportunities, such as project investment, facilitysizing decisions, or incremental gas-supply commitments. A statistically robust method for aggregation of resource estimates that appropriately uses expert opinion is presented in this paper. Using two integrated-project examples, this paper introduces new methods for (1) probabilistic aggregation of the resource estimates for multiple fields and (2) estimating a measure of dependency between the resource estimates of individual fields. The new analytical method for probabilistic aggregation is based on multivariate skew-normal (MSN) distributions, which can model a wide range of skewness through a shape parameter and are used heavily in financial and actuarial applications. In studies of the fields in which the multiple-realizations approach is used as a basis for the uncertainty framework, tornado diagrams are generated routinely to describe the dependence of the field resources on reservoir parameters. The improved method for evaluating measures of dependency between the resource estimates within a portfolio of fields uses these tornado diagrams as a basis. Incorporating the expertise and knowledge of geologists and petroleum engineers is a critical element of the method. These methods for probabilistic aggregation and estimating dependencies were developed within the context of the oil industry, but their use is not limited to the oil industry. They are general and can be used in other probabilistic-aggregation problems. Application of these techniques requires limited time and effort, compared to individual-field studies, and can have a profound impact on the uncertainty range of the total resources for the portfolio of fields.

Filling the gap: integrating nodes and streamer data for geophysical monitoring

E. Ceragioli, A. Kabbej, and A. Gonzalez Carballo of Total, and D. Marin of CGG, discuss how sparse distribution of seabed node receivers can complement conventional marine seismic streamer technology in the surveying of sensitive or obstructed targets with an example from an ultra deep water oil and gas field project.

The Impact of Tax Shocks and Oil Price Volatility on Risk - A Study of North Sea Oilfield Projects

We examine the impact of market volatility and increased fiscal take on risk in strategic natural resource projects. An increase in 2006 UK oilfield taxation is used as a natural experiment for assessing the impact of a fiscal increase on oilfield projects comprising 73% of UK reserves. Stochastic cash flow at risk models combine market volatility and tax-take at the oilfield level to extend earlier North Sea studies. We demonstrate that a 10% Secondary tax increase in a composite UKCS fiscal system with a-priori nonlinearity directly increases overall cost structures, resulting in a 14% decrease in project values, and significantly, a 67% risk increase for UK Oilfields. Risk effects are asymmetrical across the size varying sample, marginal prospects are most affected.

Cost Estimation Overruns in the North Sea

Recently, a Norwegian government report on the cost overruns North Sea projects was presented (NOU 1999:11). It concluded that there was a 25% increase in development costs from project sanction (POD, Plan for Operation and Development) to last CCE (Capital Cost Estimate) for the 11 oil field projects investigated. Many reasons like unclear project assumptions in early phase, optimistic interpolation of previous project assumptions, optimistic estimates, and underestimation of uncertainty were given as reasons for overruns. In this paper we highlight the possibility that the cost overruns are not necessarily all due to the reasons given, but also to an error in the estimation and reporting of the capital expenditure cost (CAPEX). Usually the CAPEX is given by a single cost figure, with some indication of its probability distribution. The oil companies report, and are required to do so by government authorities, the estimated 50/50 (median) cost estimate instead of the estimated expected value cost estimate. We demonstrate how the practice of using a 50/50 (median) CAPEX estimate for the 11 projects, when the cost uncertainty distributions are asymmetric, may explain at least part of the “overruns.” Hence, we advocate changing the practice of using 50/50 cost estimates instead of expected value cost estimates for project management and decision purposes.

Horizontal and Multi-Lateral Wells: Performance Analysis-An Art or a Science?

Abstract Several thousand horizontal wells have been drilled around the globe in the last ten years. In Canada alone, horizontal wells have been used in a variety of applications in almost all oil producing provinces. Several hundred multi-lateral wells have also been drilled. There are over 700 multi-lateral wells in Saskatchewan alone. Similarly, underbalanced drilling and coiled tubing drilling are also commonly used. This drilling driven oilfield revolution has made a significant impact on oilfield development. In any oilfield project one is interested in four questions, namely expected well rates, well reserves, well cost, and probability of commercial success or risk factors. Although there are horizontal well projects where commercial success rates are very high, overall commercial success of the technology in North America is about 65%. This is especially of concern since most of the horizontal wells are infill wells. Understanding these successes and failures requires an analysis of well performance. In this article, practical difficulties and solutions for well performance analysis are discussed. Introduction Figure 1 shows schematic diagrams of different horizontal and multi-lateral well configurations. FIGURE 1: Typical horizontal well and multi-lateral well profiles. (Available in full paper) The figure shows that due to advances in drilling technology, it is possible to drill wells with different geometric configurations. Most of the Canadian wells to-date is single lateral horizontal wells. It is becoming common to drill 1,000 to 1,500 m long horizontal wells. Moreover, most of the wells drilled have medium radius build-rates and are completed either with a slotted liner or an open-hole completion. Multi-laterals have been used effectively to improve production as well as injection rate. The majority of the multi-laterals in North America are either open hole or one of the laterals is completed with a slotted liner. With such a completion, it is difficult to measure production from each lateral. Moreover, it is not easy to stimulate each lateral effectively. A coiled tubing may be necessary to enter each lateral independently, which of course adds to the stimulation cost. In some cases, even with coiled tubing it may not be possible to access each leg of the well. In Canada, the major success of horizontal wells has been in producing gas zones, thin heavy oil columns, water-floods, and miscible floods in carbonates. Although many papers are written on SAGD, the field projects are limited to a dozen or so. Only a few have declared that they are commercially successful. One ofthem is the Celtic field in Saskatchewan where a horizontal well produces at 100 m3 /d with oil-stream ratio of about two. Flow Behaviour A horizontal well, similar to a vertical well, when put on production will initially go through a transient flow followed by a well stabilization or a stabilized flow(1). On a log-log plot of rate vs. time, this is observed as two different straight lines with two distinct slopes (Figure 2). Many times, this is also observed on the semi-log plot of rate vs. time.

Simulation System Provides Unique Training Method for the Oilfield

Summary Today's oilfield service environment has undergone significant change from that which existed 10 years ago. Integrated services and turnkey operations are becoming the norm for the industry, and oilfield service companies are finding themselves linked with operators and contractors in long-term service contracts that would never have been considered in the 1980's. While these new alliances may prove to be the catalysts for energizing economic growth in the oilfield, they bring with them their own set of operational problems. For example, the integrated solutions approach requires that all parties have a thorough understanding of overall economic and operational project parameters as well as a defined area for which each must take responsibility. Therefore, to meet the demands of the integrated solutions concept, "the partners" must be able to assess all project needs properly so that the solution provided accomplishes the economic and operational goals for all involved. Each must have a detailed technical understanding of a wide variety of equipment, systems, and available resources. This is the area in which a major drawback to the integrated solutions concept often occurs—it has been difficult to provide a fast, efficient method to keep users abreast of the continuing enhancements to a technology that already appears to be state of the art! Additionally, development of unique systems often results from the combined efforts of integrated teams, and to ensure that the systems will provide the expected results, it is equally as important to be able to provide training for the personnel that are responsible for the day- to-day use and maintenance of the new systems. In this paper, we will discuss a unique simulator that can resolve the training needs that have surfaced as a result of the rapidly changing operational concepts in the oilfield environment. We will present the concepts of the equipment simulator and capabilities of the global simulator methodology, and we will use an actual case history to describe in detail how the equipment simulator was used offshore on a recent well-test job in the Gulf Coast area to introduce a new well-test tool and to train a new design engineer. With this information, we conclude that the use of the simulator will provide unparalleled training support for oilfield equipment and system applications and facilitate efficient development of integrated solutions for oilfield projects.

Practice Abstracts

A short report “Determining Transportation Requirements for Development of a Major Oil Field” is given. McDermott Operations Research helped apply animated simulation to evaluate the transportation and material-movement requirements in a multibillion dollar oil field project situated in the Caspian Sea off Baku, Azerbaijan. The feasibility of developing this field was studied by a consortium led by Amoco. McDermott, which holds an interest in the consortium, assisted Amoco Eurasia in the feasibility study through its Hudson Engineering unit in Houston by building a simulation model.

The Planning of a Large-Scale Miscible Flood at Prudhoe Bay

Summary This paper describes the technical considerations that set the major design parameters for the Prudhoe Bay Miscible Gas (PBMGP). This project was planned as a large hydrocarbon miscible flood. The basic project concept is to manufacture a miscible injectant from the field separator off-gas. This injectant is compressed and delivered to the EOR project area for injection in a water-alternating-gas (WAG) mode. The miscible gas supply will vary, generally increasing with time. Over the first 10 years of the project, an average supply of 200 MMscf/D [5.66×106 m3/d] is anticipated. The gas processing plant and the factors affecting miscible gas supply are described. The EOR project area was selected by a screening process. This led to a project area definition encompassing 4.9×109 RB [779×106 m3] PV containing 2.2×109 STB [350×106 m3] original oil in place (OOIP). The planned cumulative volume of miscible gas injected will be 10% PV. Reservoir studies indicate an incremental oil recovery by miscible flooding of some 5.2% OOIP or 115×106 STB [18.3×106 m3]. Aspects of these reservoir studies are described. The Sadlerochit reservoir is both the ultimate source of the miscible solvent and the target reservoir. This introduces several reservoir/facility interaction effects. The planning of a major EOR project in the Arctic has also involved technical considerations not routinely encountered in conventional oilfield projects. Both aspects are discussed in the paper. Introduction and Background The ultimate recovery from the Sadlerochit reservoir of Prudhoe Bay is currently estimated at some 9×109 to 10×109 STB [1.4×109 to 1.6×109 m3], leaving more than 10×109 STB [1.6×109 m3] oil in place. At this projected abandonment, the Sadlerochit reservoir will still contain more oil than the original reserves for any other conventional oil reservoir (i.e., gravity greater than approximately 15°API [0.966 g/cm3]) in North America. Thus there is strong incentive to develop methods for increasing the recovery from the Prudhoe Bay field. Severe economic and operational problems face any north Alaska EOR project. Ref. 1 highlights the relatively short window of opportunity for north Alaska EOR projects before operating economics and transportation costs curtail options. Early Prudhoe EOR screening studies were started shortly after the start of field production to investigate the applicability of the principal enhanced recovery methods. The possible recovery processes considered fell into four categories:surfactant flooding,enhanced waterflood techniques,thermal processes, andmiscible gas displacement processes. Surfactant flooding is recognized as a potential EOR process. Recent reviews did not find a surfactant currently available that would be effective over the range of temperatures and salinities anticipated in the reservoir; however, laboratory studies of surfactants continue. Enhanced waterflood techniques - such as carbonated, caustic, or polymer flooding - were found to offer limited potential for improving waterflood performance. Investigations indicated, however, that the techniques are not cost-effective because of the logistics of supplying large quantities of chemicals to the remote Arctic field location. Thermal processes were eliminated because the depth and pressures of the Sadlerochhit formation make these processes economically unattractive for the light oil reservoir. Two main types of miscible gas displacement processes were considered: vaporizing, or high-pressure lean-gas drive, and condensing, or rich-gas drive. The vaporizing process is not applicable at Prudhoe Bay because Sadlerochit crude is relatively low in intermediate components and because the critical pressure at which methane, or CO2, and Sadlerochit oil become miscible is well above reservoir pressure levels. On the other hand, the condensing process is viable. With the addition of intermediate hydrocarbons, principally ethane and propane, to separator off-gas, an injectant that is miscible with Sadlerochit oil at typical reservoir conditions can be obtained.2,3 The required intermediate hydrocarbon components can be obtained from produced fluids at Prudhoe.