Field Development Costs Research Articles

Simulations of Field-Development Planning Help Improve Economics of Heavy-Oil Project

Summary When Shell began an ultraheavy-oil development in Alberta, Canada, the field plan was based on manual pad positioning without consideration for surface hazards, trajectory constraints, or injector/producer slot requirements arising from the prefabricated-pad configuration. Shell teams were challenged to investigate alternative field-development plans to reduce the initial investment. The volume of wells, surface hazards, trajectory constraints, and pad slot configuration requirements for injector/producer ratios made this a formidable task. Shell leveraged the expertise of third-party consultants and powerful software to generate numerous development scenarios, which enabled the Shell staff to focus on the economics of each plan. An aerial image that delineated surface hazards, an elevation grid, and injector/producer targets were loaded into the 3D subsurface-visualization environment of the software to generate pad-placement simulations, including trajectory designs. The software followed the Shell planning constraints and avoided all surface hazards. The analyses were conducted for the highest, lowest, and median number of pads. From these three scenarios, a value analysis was plotted. This value analysis enabled the planning team to identify the optimal surface-to-reservoir configuration and to maximize the value of the field by delivering all of the reservoir targets, while minimizing the number of pads needed to drill. The output also yielded field cumulative values, including total and nominal well length, to support future economic analyses. The analysis determined that 87 pads maximized the value of the field when 42-slot configured pads were considered. Additional studies determined that when 50-slot configured pads were considered, more than 99% of the planned reservoir targets could be drilled from 72 major and four or fewer minor pads. In either case, a significant reduction from the original 98 pads was realized. Through the combined efforts of Shell engineers and third-party consultants, as well as the use of state-of-the-art software, this optimization was completed in only 8 worker-weeks. This paper describes the software and processes used to reduce Shell's estimated field-development costs and to minimize the environmental effect of the field by reducing the number of pads required.

3498: Ultrasound echo processing optimized algorithms for software implementation with commercial DSPSs

Objectives: Software implementation of major functional blocks of a medical ultrasound imaging system is advantageous in field upgradeability and development cost. We present efficient methods for real time implementation of echo processing block for medical ultrasound imaging with minimum number of commercial DSPs.

Continued Evolution of the One-Trip-Expansion, Single-Diameter Wellbore

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 17437, "Continued Evolution of the One-Trip-Expansion, Single-Diameter Wellbore," by A. Filippov, SPE, and D. Zijsling, SPE, M. Akhideno, SPE, Shell, and K. Waddell, S. Costa, B. Watson, and B. Bell, Enventure Global Technology LLC, prepared for the 2005 SPE Offshore Technology Conference, Houston, 2–5 May. Copyright 2005 Offshore Technology Conference. Reproduced by permission. With more than 300 commercial installations in place, solid-expandable-tubular technology has proved to be a viable and economically feasible alternative to conventional drilling technology. The need for lower lifting costs and to maximize recovery has provided the impetus for the latest step change toward the one-trip section, single-diameter wellbore. In addition to the unique equipment needed to expedite this game-changing technology, new implementations essential to realize the tool components and contingencies had to be developed and tested. The full-length paper explains the overall design and testing approach necessary for the construction of a single-diameter well. Introduction Installation of successive single-diameter expandable liners will revolutionize the way many wells are designed and executed. The potential cost savings of an ultraslim wellbore and maximized reservoir potential have been well documented. Single-diameter technology offers the following benefits.Significant increases in potential lateral reach.Significant increases in potential lateral and trouble time.Improvements in capital efficiency on drilled wells and overall field development. This technology allows enhanced field-development flexibility and cost reductions in many worldwide field developments. For example, increasing lateral reach and thus reservoir contact and drainage creates the potential for reduced well count and greater production per well. More production from fewer wells can lower the number of wells required and result in reduced drilling costs. Reduced trouble time and risk lowers drilling costs. This drilling optimization can result in lower facility and project capital requirements. Field Applications Use of single-diameter expandable-casing technology has the field-proven potential to reduce drilling and completion costs significantly. These savings are realized by reducing drilling risk and resultant trouble time by successively isolating problem lithology and/or underpressured zones while preserving a single-diameter wellbore. Gulf of Mexico (GOM) operators, who often encounter severe lost-circulation zones at shallow depths, are watching this technology development in hopes of expanding long drilling liners to isolate these underpressured zones and later case off the expanded liner and problem zones. Successive installation of expandable, single-diameter wellbores can reduce the friction/drag forces that can limit lateral reach while preserving a single-diameter wellbore as deep as required. This application can provide higher weight on bit than conventional drilling technology at comparable depths.

Optimized Reservoir Development With High-Angle Wells, El Furrial Field, Venezuela

Summary The El Furrial field is one of Venezuela's major field assets and is operated by PDVSA (Petroleos de Venezuela, S.A.), the national oil company. Its current production of more than 450,000 BOPD makes it a giant oil field. Development of the field, which has an average reservoir depth of approximately 15,000 ft, is in its mature stages owing to implementation of high-pressure gas injection. PDVSA has consistently followed a forward planning approach related to reservoir management. Using high-angle deviation drilling techniques allows development wells to be strategically located by penetrating the reservoir at high angles to optimize production rate, extend well life, increase reserves per well, reduce operating expenses, and reduce total field development costs. A reservoir model was constructed and simulated with detailed reservoir stratigraphy to determine realistic potential of high-angle wells (HAW's). Five wells had been drilled as of June 2000, and the first four wells have proved the effectiveness of the design. The philosophy, modeling technique, well design considerations, problems encountered, well results, and economic criteria provide a clear understanding of the risk of this technology not previously used at this depth in Venezuela. The result was the first HAW in the deep, challenging environment of eastern Venezuela. Results show that optimization objectives can be attained with HAW's, mainly increasing per-well production rate, maximizing per-well recovery, and extending the breakthrough time of gas or water from pressure maintenance and enhanced oil recovery projects. Well results indicate that the geological and simulation modeling technique is reliable and accurate. A pilot program shows that HAW technology provides major advantages to increase production rate and reduce the overall number of wells needed to reach production objectives. However, the project also has experienced a number of unexpected drilling problems.1 The costs associated with the total project are significant, but more importantly, this program becomes very attractive because of the long-term benefits of decreased water-cut related to current water injection; decreased gas breakthrough owing to high-pressure gas injection, and fewer wells required to meet production goals. Technical contributions include the following: The modeling technique of applying detailed stratigraphy to a full-scale reservoir model is accurate if performed with the appropriate objectives in mind. The application of state-of-the-art drilling techniques to attain high angles at deep drilling depth is possible; however, drilling problems caused by formation instability require more study and experience. This method can be applied to other fields in the eastern Venezuelan basin currently under, or planned to be under, enhanced recovery programs and development programs.

GEOTHERMAL ENERGY FROM THE EARTH: Its Potential Impact as an Environmentally Sustainable Resource

▪ Abstract Geothermal energy technology is reviewed in terms of its current impact and future potential as an energy source. In general, the geothermal energy resource base is large and well distributed globally. Geothermal systems have a number of positive social characteristics (they are simple, safe, and adaptable systems with modular 1–50 MW [thermal (t) or electric (e)] plants capable of providing continuous baseload, load following, or peaking capacity) and benign environmental attributes (negligible emissions of CO2, SOx, NOx, and particulates, and modest land and water use). Because these features are compatible with sustainable growth of global energy supplies in both developed and developing countries, geothermal energy is an attractive option to replace fossil and fissile fuels. In 1997, about 7,000 MWe of base-load generating capacity and over 15,000 MWt of heating capacity from high-grade geothermal resources are in commercial use worldwide. A key question is whether these levels can grow to a point where geothermal energy is more universally available and thus have a significant impact on global energy supplies in the twenty-first century. Such an achievement will require the economic development of low-grade resources.The current status of commercial and emerging technologies for electric power production and direct heat use is reviewed for the major geothermal resources including hydrothermal, geopressured, hot dry rock, and magma. Typically, high-temperature resources (>150°C) provide base-load generating capacity while lower-temperature resources provide energy for geothermally assisted heat pumps and for direct use in domestic, agricultural, and aquacultural heating applications. Critical development issues relating to resource quality and distribution, drilling costs, and reservoir productivity are discussed in the context of their economic impact on production costs. Advanced drilling and improved heat mining methods are suggested as approaches to increase the worldwide use of geothermal energy by reducing field development costs. With these improvements, lower-grade resources can compete in growing global energy markets that are currently controlled by abundant and low-cost fossil fuels.

Hydrate-free zone for synthetic and real reservoir fluids in the presence of saline water

The application of extended-reach subsea gathering networks and transportation of unprocessed wellstreams are serious considerations for reducing field development costs. These lines will convey a mixture of gaseous and/or liquid hydrocarbons, condensed or saline water. A good knowledge of the hydrate phase boundary for the above systems is essential in the confident and economical design and operation of associated fields, pipelines and processing facilities. In this paper, experimental data for the hydrate-free zone of several pure and multicomponent systems in the presence of single and mixed electrolyte solutions are presented. The paper, which is a continuation of three previous communications, presents data on C 2, C 3, CO 2, two synthetic multicomponent gas mixtures, and a black oil sample. The comparison of results with recent literature data shows some discrepancy at high salt concentrations, where a possible source of error is identified. An in-house numerical model has been used for predicting the experimental data with good results.

Maximizing Probable Oil Field Profit: Uncertainties on Well Spacing

The influence of uncertainties in field development costs, well costs, lifting costs, selling price, discount factor, and oil field reserves are evaluated for their impact on assessing probable ranges of uncertainty on present day worth PDW, oilfield lifetime τ2/3, optimum number of wells OWI, and the minimum (n-) and maximum (n+) number of wells to produce a PDW ≥ 0. The relative importance of different factors in contributing to the uncertainties in PDW, τ2/3, OWI, n- and n+ is also analyzed. Numerical illustrations indicate how the maximum PDW depends on the ranges of parameter values, drawn from probability distributions using Monte Carlo simulations. In addition, the procedure illustrates the relative importance of contributions of individual factors to the total uncertainty, so that one can assess where to place effort to improve ranges of uncertainty; while the volatility of each estimate allows one to determine when such effort is needful.

Obtaining Reliable Laboratory Measurements

E&P Exchange Laboratory measurements on reservoir rock and fluid samples are required for many applications, including reserves determination, reservoir simulation, stimulation design, formation-damage assessment, and recovery monitoring. The costs of acquiring and testing samples are significant. Every attempt must be made to maximize the value added in making measurements. While the costs of laboratory measurements are small compared with the overall cost of field development, the financial impact is not. Decisions based on interpretation of the laboratory tests can make or break a project. Before samples are acquired, define the goals of the measurement program. . What are the business objectives in making these measurements? . What are the consequences of not making these measurements? . What business decisions will the measurements affect? . What alternatives exist for obtaining these measurements? . What are the consequences of making these measurements incorrectly? The precision and robustness of commonly available measurements must be known to determine the nature of the data acquisition program. Balance the number of measurements and their accuracy. Unnecessarily narrow tolerances increase the costs of every step of the data-acquisition program. The objective may be reached more cost-effectively with a large number of qualitative measurements than with a few highly accurate ones. If measurement tolerances are broad, rule-of-thumb values may be adequate and new test data a luxury rather than a necessity. At the other extreme, small differences in measurements may critically affect decisions. Then, it may be necessary to customize existing testing procedures and develop new methods. Know the difference between the value of data and the cost. Accuracy may not be constant over the entire measurement range. For example, measurements of permeabilities < 1 and 1,000 md are significantly less accurate than measurements of permeabilities in between. Consider the anticipated values for properties when designing an experimental program. Tests that may be accurate on a rock with a permeability of several hundred millidarcies and 20% porosity may be highly erroneous on a sample with <1-md permeability and 5% porosity. Variances between different laboratories' measurements of basic properties are often larger than commonly assumed. If check samples are not used to ascertain measurement precision, unrealistically narrow limits may be cited. Laboratories fear that they will lose business if the competition claims greater accuracy.

High-resolution sequence stratigraphy of Cretaceous shallow marine sandstones, Book Cliffs outcrop, Utah, USA - application to reservoir modelling

In recent years the financial cost of offshore oil and gas field development has promoted intense interest in the quantitative 3D description of hydrocarbon reservoirs, utilizing workstation technology. The main aims of this procedure are to produce volumetric models for the spatial distribution of reservoir/non-reservoir elements, using both deterministic and probabilistic geostatistical techniques to interpolate weIl data into the inter-weIl volume.

Heave-Restrained Platform Reduces Costs and Eases Operations

Heave-Restrained Platform Reduces Costs and Eases Operations

Commercial Application of Steamflooding in an Oilfield Comprising Multiples Thin Sand Reservoirs

Summary Steamfloods conducted in thin reservoirs generally provide marginal profits because of relatively high field provide marginal profits because of relatively high field development costs per barrel of oil in place (OIP) and excessive heat losses from the productive zone. New techniques are being used to solve these problems, such as use of induced horizontal fractures to circumvent the detriments attributable to thin zones and to solve the problems of steam distribution and confinement inherent problems of steam distribution and confinement inherent in any steamflood. This paper documents the successful application of steamflooding in the multiple thin-sand reservoirs of the Loco Unit, Stephens County, OK. These reservoirs occur at depths from 50 to 1,200 ft [15 to 366 m] and range in thickness to 40 ft [12 m]. Porosities of the productive zones vary from 20 to more than 30%, and permeabilities range from 100 to more than 4,000 md. Oil gravities of the various zones range from 16 to 24API [0.96 to 0.91 g/cm3]. Table 1 presents average reservoir properties of the three most important zones in the area of principal interest. Reservoirs that occur at depths above approximately 700 ft [213 m] have little or no natural reservoir energy and generally contain viscous oils, ranging up to 10,000 cp [10 Pa.s]. Consequently, there was no primary production from these reservoirs, and potential for waterflooding was marginal. Steamflooding has been the only recovery process applied successfully to these zones, except for one isolated instance. Reservoirs at depths greater than 700 ft [213 m] normally contain lower-viscosity oils. Six of these zones were produced by solution gas drive and were later waterflooded successfully. After 23 years of water-flooding, two of these six zones have been tested and have proved to support commercial steamflooding operations. Introduction The Loco field is situated on a northwest-southeast trending anticline that underlies a major portion of Township T3S-R5W, Stephens County, OK, at approximately the location indicated in Fig. 1. The field was discovered in 1913, and sporadic development occurred from that time until the 2,300-acre [931-ha] unit was formed in 1961 for the pursuit of secondary recovery operations. From 1961 through 1964, the field was developed on 10-acre [4.05-ha] spacing, and water-flooding of the six deepest zones was initiated, using 20-acre [8.09-ha], five-spot patterns. Geology and Reservoir Description. Twenty-four identified zones have been proved to have, or are suspected of having, significant oil saturation in at least some areas of the unit. The most significant of these are illustrated in the log section of Well 511 presented in Fig. 2. The various oil sands have been named alphabetically ascending (As, Bs, Cs, etc.) and descending (Ad, Bd, Cd, etc.) from the Loco lime (LL), which occurs at a depth of 800 to 900 ft [244 to 274 m]. Three zones (X, Y, and Z) of minor areal extent are located between the LL and the A-shallow (As) sand. The LL and the five deep sands are of Hoxbar-Pennsylvanian age. A fault trending northeast-southwest displaced this interval approximately 100 ft [30 m]. The original OIP in the six deep zones is estimated to be 73.4 × 10(6) bbl [11.7 × 10(6) m3]. These zones have had primary recoveries of approximately 3 % of the original OIP, and waterflooding, which was initiated in 1961, will ultimately recover an additional 11 %. The shallow sands, which lie above the LL, are of Pontotoc-Permian age and are not affected by the Pontotoc-Permian age and are not affected by the faulting. Minimal natural reservoir energy has precluded significant primary recovery, and the adverse mobility ratios inherent to the native oil viscosities make waterflooding generally impractical. A notable exception to this rule was a 20-acre [8.09-ha] waterflood of the As and Cs zones, which was conducted in the southeast quarter of Sec. 9 from 1956 to 1963; this was a marginally profitable operation. No response was observed in a profitable operation. No response was observed in a 10-acre [4.05-ha] X-zone waterflood, which was operated during this time interval in the southwest quarter of Sec. 9. From 1969 through 1972, pilot waterfloods were conducted in the As, Bs, Ds, and Js sands, none of which were successful. JPT P. 1707

Lognormal field size distributions as a consequence of economic truncation

The assumption of lognormal (parent) field size distributions has for a long time been applied to resource appraisal and evaluation of exploration strategy by the petroleum industry. However, frequency distributions estimated with observed data and used to justify this hypotheses are conditional. Examination of various observed field size distributions across basins and over time shows that such distributions should be regarded as the end result of an economic filtering process. Commercial discoveries depend on oil and gas prices and field development costs. Some new fields are eliminated due to location, depths, or water depths. This filtering process is called economic truncation. Economic truncation may occur when predictions of a discovery process are passed through an economic appraisal model. We demonstrate that (1) economic resource appraisals, (2) forecasts of levels of petroleum industry activity, and (3) expected benefits of developing and implementing cost reducing technology are sensitive to assumptions made about the nature of that portion of (parent) field size distribution subject to economic truncation.

An Analysis of Tanker-Based Floating Production Systems for Small Offshore Fields

Summary A historical review of floating production storage and offloading (FPSO) systems for marginal fields is presented. The areas in which such systems are presented. The areas in which such systems are operating, ranges of model tests, and current applicability of mooring systems are reviewed to present capabilities of these concepts. Limitations are reviewed to assess the applicability of these concepts to similar sites.Consideration of processing operations on floating vessels are identified. Particularly, the effects of vessel motion on the processing equipment, gas disposal, and crude offloading are addressed. It will be shown that operations are becoming well understood and routine. Future problem areas and solutions under development are identified. Specific examples are cited and design refinements are noted.While various floating production systems have been in operation for only a few years, their potential for solving the problems of producing small offshore fields and for achieving early production is impressive. Introduction Oil discoveries have been made in offshore areas the world over, which, even at today's crude prices, are considered uneconomical to develop with the conventional fixed platform approach. The type of discovery considered marginal varies according to location, water depth, and recoverable reserves. Several innovations to produce such marginal fields economically have been produce such marginal fields economically have been implemented. Among these are tankers moored on site, taking production through risers from seafloor wells and with processing equipment located on board the tanker. This paper discusses the applicability of such tanker-based floating production systems in two diverse areas-offshore Southeast Asia and the North Sea. The discussion makes use of the results of studies conducted by Marathon Oil Co. over the past 5 years. Historical Development of FPSO Systems Early floating production systems used converted semisubmersible drilling units. Argyll gained prominence as the first floating production system using prominence as the first floating production system using the Transworld 58. ENIEPSA, Spain's national oil company, moored a SEDCO 135 class semisubmersible over a three-well cluster as a production platform in 305 ft (93 m) of water in the Dorado field in the Spanish Mediterranean. Development of several Petrobras fields offshore Brazil, Chevron's Casablanca field offshore Spain, and BP's Buchan in the North Sea also used semisubmersibles.In some cases, the semisubmersibles were selected primarily because they were immediately available. But primarily because they were immediately available. But high day rates, conversion time and costs, and low availability of semisubmersibles have made tankers a more attractive component of floating production systems. A tanker surplus in recent years has made it possible for operators to purchase them at a relatively possible for operators to purchase them at a relatively low cost, thus reducing field development costs significantly by unifying the tanker with subsea production systems. production systems. The use of moored tankers as permanent floating storage at offshore oil fields started in the mid-1960's. However, the first FPSO system went into service in 1977, in Shell Oil Co.'s Castellon field. The development began with production from a single well, with provisions for an increase to three wells. The time from provisions for an increase to three wells. The time from go-ahead to production was only 11 months, primarily because the production system was a variation of several relatively simple systems already in use in the offshore industry. Even though the mooring system was new, design and fabrication were carried out within this limited time. The basic simplicity, combined with relatively low capital and operating costs, permits economical development of offshore fields with small recoverable reserves such as Castellon. The production equipment aboard the Castellon tanker is designed to handle 20,000 B/D (130 m3/h) oil. The associated gas is used as fuel in the ship's boilers, and the excess is disposed of in a pair of incinerators. JPT p. 1871