Marginal Field Development Research Articles

Hydrocarbons in the Netherlands: Exploration and Development in Historic and Future Perspective

Triggered by the discovery of the giant Groningen gas field (2700 bcm) in 1959, the hydrocarbon exploration in the Netherlands was strongly boosted. Over the last decades, the country has proved to be a very prolific hydrocarbon province, particularly for natural gas. Supported by the favorable exploration climate, exploration effects have been at a high and sustained level. Well over 250 gas reservoirs have been discovered throughout the stratigraphic column in various plays. Field sizes range from medium (about 50 bcm) down to very small (2 bcm or less). Total initial reserves in these fields are approximately 1100 bcm. A mature stage of exploration has been reached in many areas. However, within a few years, virtually all production acreage and large parts of the exploration acreage in the Netherlands will have been covered with three-dimensional (3-D) seismic. Improvement of exploration drilling efficiency has already been shown in terms of increased technical success rates. Moreover, the use of 3-D seismics has proven cases of additional prospectivity undetected before. Here, a major possibility, and challenge, for finding future incremental reserves is present. On the development side, nearly all large- and medium-size gas fields have, or shortly will, come on stream. However, themore » majority of the relatively large population of small and marginal fields is still undeveloped. Here, the challenge is to reduce economic limits by a.o. further expansion of infrastructure and the application of modern marginal field development technology. Actual examples illustrate the possibilities to increase the developed reserves.« less

Overview of the GASP Project-Field Applications and Economics

Summary The aim of the Good-fellow Assocs. subsea production (GASP) project was todevelop a sub-sea production system for use in the development of marginalfields. The project was divided into three phases that culminated in testing aprototype system in a dry dock. The GASP system enables manifolding ofproducts, separation of gas from produced liquids, and transportation of gasand liquids through separate lines. The produced liquids are pumped with asingle-phase pumping system that is highly modularized for ease of installationand retrieval of key components. GASP is suitable for deep-water applicationand development of marginal fields far from the host platform. The economicswere assessed with probabilistic methods to weigh the uncertainties. Developingmarginal fields with the GASP system looks attractive, offering a developmentcost of $2.50 to $5.50 per barrel in many typical instances. Introduction GASP was a joint industry project supported by the European Community andeight major oil companies: Agip (U.K.), Chevron (U.K.), Conoco (U.K.), Elf(U.K.), Norsk Hydro, Phillips Petroleum (U.K.), Statoil, and Texaco (U.K.). The project was developed under three phases. Phase 1. Nov. 1986-Nov. 1987:conceptual development of the subsea production/process system. Phase 2. Nov.1987-Feb. 1989: detailed design of prototype system and material procurement.procurement. Phase 3. Jan. 1989-May 1990: installation and testing of theprototype system in a dry dock. Objectives The main objectives of the project were (1) to develop a subseaproduction/processing system suitable for development of marginal fields; (2)to identify the key components of the system, their requirements, and the stateof the an for their application; (3) to address all major operational aspectsto establish the viability, applications, and limitations of the system; (4) touse the GASP system to prepare a cost estimate for the development of a fieldand to establish the economic viability of the system; and (5) to demonstratethe operation and control of a prototype system to confirm system viabilityprototype system to confirm system viability and to identify areas requiringfurther development or modifications for future field applications. Why Subsea Production and Processing? Production and Processing? Developmentof marginal fields with conventional bottom-supported jackets and floatingproduction systems, in most cases, is uneconomical because of their highcapital cost. The economics are affected further by the development of fieldsthat are located in deep waters and have one or more of the followingcharacteristics:reservoir conditions demanding several satellite wells forthe recovery of field reserves;low production rates associated with lowPI;production rates associated with low PI;limited total recoverablereserves, typically ranging from 10 to 100 million bbl oil;low productionpressure and rapid pressure decline, requiring water injection and gas lift asan additional aid to enhance recovery; andhigh water cut, reaching 70% to80% oftheproductionneartheendofthe field life. These conditions can beaggravated further by uncertainties in reservoir behavior, the presence of H2Sand CO2, waxy crude oil, and production of sand. An economic solution is tominimize the capital cost and to use the existing nearby facilities as much aspossible. This approach entails transporting the products for processing andexport to the host platform. processing and export to the host platform. Ainmost cases where production from several wells is involved, manifolding theproducts subsea becomes necessary to save the cost of pipelines over longdistances. Transporting well products in a multiphase (gas and liquids) stateover long distances poses a number of problems, including severe poses a numberof problems, including severe slugging and pressure fluctuations. Theseconditions also have an affect on the design and capacity of the topsideprocess facilities that need to cope with the expected slug and plug flowconditions. plug flow conditions. Loss of pressure along the pipelines as aresult of friction and head losses often limits the production life and subseaboosting of the products becomes necessary. Near the end of the field life, ahigh water cut means that head losses dominate. For deepwater production, wherea significant difference production, where a significant difference exists inseabed elevation between the sub-seaproduction system and the host platformhead losses may form more than 90% of the total losses along the line. Notethat for deepwater fields, even if conventional production platforms are used, head losses along the riser will restrict the production rate through theentire life of the production rate through the entire life of the field unlesssome form of downhole or sub sea boosting is included. In most cases, theproduced hydrocarbons are well below their produced hydrocarbons are well belowtheir bubblepoint when they reach the wellhead, and gas/liquid ratios can rangefrom 3% to greater than 90% during the production life of the field.

Subsea Processing and Control System in the GASP Project: Testing of the Prototype System

Summary The subsea production and processing system developed under the Goodfellow Assocs. Subsea Production (GASP) project involved two stages of separation thatled to the production of exportable-quality crude oil production ofexportable-quality crude oil by pipeline. The produced gas is transported alonga separate line. This paper describes key elements of the subsea processsystem. A prototype system was developed during the second phase of theproject. The system was tested under dry and submerged conditions in a drydock. Key features of the proto type system and the tests carried out aredescribed. Prototype testing proved the viability of the GASP system and helpedidentify areas requiring particular attention and improvement for futureapplications. Introduction The main objective of the GASP project was to develop a subsea productionsystem suitable for the development of satellite marginal fields. This was ajoint industry project supported by the European Community project supported bythe European Community and eight major oil companies. An overview of the systemand the economics are addressed in a separate paper. This paper highlights somekey features of the process and control system and the extensive testing of theprototype system. The base case was a satellite field 30 km from the motherplatform. The field consists of four production wells and four water-injectionwells. A general view of the field scenario is shown in Ref. 1. Design Parameters. Table 1 summarizes the main parameters for the design ofthe system. The sensitivity case shows the range of values of interest to theparticipating oil companies and does not reflect the limits for future fieldapplications. The quality requirements for the processed crude oil were notnecessarily the processed crude oil were not necessarily the minimum or optimumfor the system but were set to a relatively more demanding level to allowexport of produced oil directly through an existing trunkline. The high exportpressure specified for the crude oil was to meet the operating pressurespecified for the trunkline. Options for simplifying the process system arediscussed later. process system are discussed later. Process Flow Diagram. Fig.1 shows the Process Flow Diagram. Fig. 1 shows the simplified process flowdiagram (PFD). Two identical production trains were adopted. Each train servestwo wells with an option to divert flow from one train to another through thetest-meter loop. Production testing of individual wells is achieved through abypass valve leading to the test header. The multiphase test meter enablessubsea measurement of individual wells without the need for a test line or aseparate test separator. The separator comprises two stages of gas/liquidseparation to meet the specified true vapor pressure (TVP) requirements. Thisleads to production of gas at different pressures (first- and second-stageseparators). pressures (first- and second-stage separators). An ejector is usedto commingle the gas products from the two sources for export products from thetwo sources for export through a single line. Oil and water are transportedalong separate lines for the base case. Separate booster pumps are used foreach train. This helps to keep the pump duty requirements within the range ofexisting pump designs and improves the availability pump designs and improvesthe availability of the system. A fiscal flowmetering system shown in the PFD, measures the crude oil rate for fiscal PFD, measures the crude oil rate forfiscal metering purposes as the product enter a common subsea trunkline. If theproduced oil is transported directly to the mother platform, this meter is notnecessary. The platform, this meter is not necessary. The first phase of thestudy established that designing a reliable subsea meter that met the desiredaccuracy, proving, and availability targets needed for fiscal metering wouldnot be easy and would require a novel approach. Adapting the existinggeneration of fiscal meters was feasible but would result in a cumbersome andtedious system requiring a costly maintenance and proving program. Process System Design. At the outset of Process System Design. At the outsetof work, the aim was to simplify the system as much as possible. Separation ofgas, oil, and water is a well-developed technology. For subsea application, however, the following points affect the design of the separator and may changeits features from those of topside units.Modularization to reduce size andweight if the unit is to be retrieved for maintenance purposes.Capacity tocope with the expected slug and plug flow conditions.Minimum use ofinternals to minimize maintenance requirements.Generous capacity to copewith flow functions, any slowness in control-valve responses, and possiblefoaming.Generous capacity to cope with slackness in the level monitoringand control and to avoid unnecessary system shutdown for minor equipmentmalfunctions.Capability to withstand pressures well above the operatingpressure, although it is feasible to include a pressure-relief system on theseparator to minimize the rating.

The Effect of Inclination on Flow Regime Boundaries and Slug Flow Characteristics

Multiphase schemes for oil and gas production systems are becoming more common as the development of marginal fields necessitates a reduction in capital costs. Prediction of flow regime within these pipelines and the characteristics of the flow, especially within the slugging regime, is required in order to design the pipeline and the downstream separation and processing facilities. Test rig studies have been carried out at BP’s Sunbury Research Centre on the effect of small changes in pipeline inclination on both the flow regime and the characteristics of slug flow. Results from tests on a 2-in. rig are quoted.

Jack-up conversion for production

For the production development of marginal offshore oil fields or to achieve early production in offshore fields scheduled for full production facilities a jack-up drilling rig can be converted to operate as a mobile production unit. This paper presents a summary discussion of the main aspects to be considered in the design, conversion, installation and operation of a jack-up production unit.

North East Frigg Development and Experience

The North East Frigg (NEF) gas field is a small satellite of the Frigg field; in terms of recoverable reserves as estimated at the beginning of the project-282.51 cu ft x 10/sup 9/ (8 x 10/sup 9/ m/sup 3/) and daily production capacity of 211.9 x 10/sup 6/ cu ft (6 x 10/sup 6/ m/sup 3/)-NEF is a marginal field. When the NEF subsea multiple well gas field production system (SPS), came on stream Dec. 8, 1983, it was the first multiwell SPS to deliver commercial gas. The field has now produced for over a year with a remarkably high up-time and is operated in an unmanned production mode as originally designed. This demonstrates the suitability of such a concept for application to remote marginal gas fields. This paper describes and explains the concept and the rationale for the NEF subsea's selection, reviews the main phases of the development (design, manufacturing, offshore works, and production operations), and presents the field experience gained.

Technical And Economic Evaluation Of Ship-Shaped Floating Production And Storage Systems For The Canadian East Coast Offshore

Abstract This paper discusses the evaluation and technical feasibility of Ship-shaped oil production systems for the Nova Scotia, Grand Banks and Central Labrador areas. A general analysis of vessel dynamic response to wind wave action, current and ice is presented, on the basis of which two preferred designs are outlined: a fully dynamically-positioned ship, and a single point-moored vessel with a counterweight and a turret. The production downtimes due to the shuffle lanker oil export system are also studied using a wave hindcast computer model. An estimate of the economic threshold values for resources and well productivity is presented. The potential for early production systems and reservoir testing is highlighted. Introduction There are many systems available to the operator for development of offshore oilfields. These include floating production systems, fixed structures (concrete and steel), compliant structures, surface wellheads, subsea wellheads, subsea manifolds, glory holes to avoid iceberg scour, flowlines, pipelines, tankers, trenches, storage, offshore offloading systems and any combination of these. All have advantages and disadvantages. In shallow waters (less than 300 m water depth) and in ice-free environments, the fixed structure systems with export by pipelines appear the most popular and economic for elatively large fields. Where the size of the field is not large enough to support long pipelines and large production structures, floating production facilities with shuttle tanker export systems, together with subsea production systems, must be considered. A vast area of the Canadian east coast has ice-infestedaters. Large fixed structures, designed to withstand the impact of ice and icebergs are probably too expensive for the size of the majority of oil fields to be discovered. Floating facilities, on the other hand can be moved away if ice conditions are too severe. Consequently, based on existingworld-wide technology, this paper discusses ship-shaped floating production, storage and offloading systems (FPSO). The ship-shape system has a number of attractions compared with a semi-submersible floating production vessel; namely:The motion characteristics of a large ship are as good as a semi-submersible as shown in Figure 1.The ship can be more heavily ice-strengthened than a semi-submersible. Also, if a large bergy bit does puncture the ship (see Fig. 2), a ship can, in general, withstand a greater degree of structural damage and flooding.The ship can store up to 150 000 tonnes of oil which will reduce downtime for shuttle tanker loading during bad weather.The ship provides a large deck area for production equipment compared with the restrictions placed on semi-submersibles.For dynamically-positioned and internal-turret moored systems the ship will protect risers and moorings from pack ice and bergy bits. The turret area is large enough to install equipment to overcome problems of high-pressure swivels.Due to its relatively low costs, the FPSO could also be used as one step in the over-all development of a large oil field as well as for marginal field developments.

THE COBIA 2 SUBSEA COMPLETION

Subsea completions are recognised worldwide as a cost effective means of developing marginal reservoirs, accelerating production and draining reservoir extremities which cannot be reached from conventional platforms. To date, more than 280 subsea completions have been installed around the world. Cobia 2, the first subsea completion in Australian waters, commenced production in Bass Strait in June 1979. It continued to produce until April 1983, when it was shut-in following the commencement of production from the Cobia platform. In its four years of operation, the well produced over 280 megalitres (1.78 million barrels) of crude oil, with peak well rates reaching as high as 750 kilolitres per day in the latter stages of its producing life. Overall, Cobia 2 has been a technical and commercial success.The need for regular pumpdown or TFL ('through flowlines') wax-cutting operations in the flowlines to maintain high levels of production generated a great deal of confidence in the use of TFL techniques for routine and non-standard subsea well servicing. In an industry 'first', TFL methods were developed to lock open and seal a leaking subsurface safety valve and, within it, set a special insert subsurface safety valve. This work allowed the well to be returned to production in a situation where a conventional workover of the well was not feasible.Other well-servicing techniques developed during the Cobia 2 project involved the novel use of a coiled tubing unit to retrieve TFL tools which had become stuck in the flowlines during the wax-cutting operations.The highly successful operation of Cobia 2 has proved the viability of this type of completion for marginal field development in Australia.

Update of the Enchova Field 10-Well Subsea Production System

Summary The Enchova field template production system is now in the completion stages in the Campos basin offshore Brazil. This paper reviews Enchova development and summarizes the 10-well subsea production system. Design evolutions since the production system. Design evolutions since the concept first was disclosed are presented, as are the steps remaining to bring the template system on full production. production. Introduction The Enchova field development-about 120 miles (200 km) northeast of Rio de Janeiro in the Campos basinhas been one of the more important examples of marginal field development using early subsea production techniques. The second well drilled production techniques. The second well drilled surprised Brazil by showing the highest potential production rate known in the country. Eager to learn production rate known in the country. Eager to learn more about the newly discovered reservoir and at the same time increase the country's oil production, Petroleo Brasileiro S.A. (Petrobras) decided to Petroleo Brasileiro S.A. (Petrobras) decided to proceed in stages. Consequently, this first proceed in stages. Consequently, this first confirmation well was brought into production only 5 months after equipment was ordered (Fig. 1). Phase 1 Phase 1 The drilling semisubmersible Sedco 135D was converted to a floating production platform for this first phase. Production flowed to the surface through a test tree suspended inside the blowout-preventer (BOP) stack and riser. Oil and gas were separated, and the gas was flared. Processed crude then was transferred through a floating hose to a nearby moored tanker. During this time, two more confirmation wells were drilled. Commercial shows prompted Petrobras to proceed to the next phase, prompted Petrobras to proceed to the next phase, which brought these wells on production (Fig. 2). Phase 2 Phase 2 The second phase, more ambitious than the first, contracted another semisubmersible, Penrod 72, for conversion to a floating production platform. Like Sedco 135D, Penrod 72 was anchored over one well and brought crude oil to the surface through a BOP production tree. However, a second well was brought production tree. However, a second well was brought on production through a wet subsea tree at a record water depth of 610 ft (186 m). Crude oil flowed 1.7 miles (2.74 km) to Penrod 72 through a free-hanging flexible flow-line/riser system. The riser system included a control line umbilical for communication between the tree and Penrod 72. Processed crude from the two wells was transported through an 8-in. (203-mm) flexible flow-line/riser to a monobuoy tanker loading facility 2 miles (3.2 km) away. A second 8-in. (203-mm) flexible flow-line/riser was connected between Penrod 72 and Sedco 135D [a distance of 1.9 miles (3.1 km)] which permitted optional tanker loading facilities from both vessels.It is important to note that three new technologies - the subsea tree, the flexible production riser system, and the monobuoy tanker production riser system, and the monobuoy tanker facility-were introduced to offshore Brazil in this phase. Equally important is that Phase 2 production phase. Equally important is that Phase 2 production was brought on stream only 1 year after equipment was ordered (Fig. 3). JPT P. 1289

A Unique Approach to the Offshore Gas Disposal Problem: Castellon SALS Production Facilities

This paper outlines the problems, and their solutions, associated with the production, storage and gas disposal facilities of Shell Espana’s successful Single Anchor Leg Storage (SALS) development of the Castellon Field, situated in some 380-ft waterdepth, offshore Eastern Spain. An underwater completed well produces some 10,000 bbl/day, with Gas/Oil ratio of 125 sdf/bbl, via a single-anchor leg mooring system to a weather-vaning tanker, where separation, gas disposal and storage facilities are provided and whence the oil is exported via a shuttle tanker. The separation and storage systems are briefly described but the main interest centers on gas-associated problems since disposal of gas by conventional methods of flaring, venting or dilution was unacceptable if production was to continue uninterruptedly during transfer of oil to the export shuttle tanker. The alternative of closed incinerators adjacent to the funnel was considered and consultation with Holec Gas Generators/Smit Ovens Nijmegen B.V., manufacturers of inert-gas generators, led to modification and extension of Holec’s basic concepts, resulting in their design of closed, water-cooled units acceptable to the vessel’s classification society for mounting on the aft superstructure. The facilities described represent the likely minimum requirements for the production of a small offshore field. The short period between project initiation and first production — some 11 mo — imposed the necessity for using straightforward and reliable equipment and the success achieved underlines the suitability of a tanker-based system, of which the incinerators are seen as an almost integral feature, for the economic development of small or marginal fields for which more conventional methods are not viable.

Headings for an EEC Common Energy Policy

Although self-sufficiency in energy supplies during the 1980s may make a purely national UK energy policy look attractive, the author argues that it is in the long-term interest of all nine community members if policy is coordinated on an EEC scale. Any possible common energy policy would probably consist of separate policies for coal, oil, natural gas and nuclear power. It would follow the same general principles as the Common Agricultural Policy in maximising production of coal, natural gas and nuclear power but oil would be covered by negotiating with OPEC for current supplies and treating indigenous supplies as a strategic reserve, with Community finance available for development of marginal fields.

Geomechanical Properties Estimation for Marginal Oil Field Development at Onshore Niger Delta, Nigeria

Rock geomechanical properties were estimated for an onshore marginal field in Niger Delta with the aim of boosting hydrocarbon production in the field. Rock elastic properties and rock strength properties revealed bulk modulus ranged from 1.45 to 1.73 Mpsi, young’s modulus from 1.01 to 1.58 Mpsi, shear modulus from 0.37 to 0.59 Mpsi and Poisson’s ratio from 0.35 to 0.39. These results indicate that the shales are very stiff and harder to fracture, making them very good caprocks. Unconfined Compressive Strength ranged from 785.80 to 1357.65 psi, angle of internal friction ranged from 28.92 to 29.87 deg and cohesion ranged from 232.09 to 393.67 psi respectively. Results of shale geomechanics revealed overburden pressure (vertical stress) ranged from 1648.99 to 5652.36 psi, formation pore pressure from 2083.75 to 3277.22 psi, fracture pressure from 1648.99 to 4821.53 psi, hydrostatic pressure from 2025.10 to 3159.94 psi, maximum horizontal stress from 1648.99 to 11205.70 psi and minimum horizontal stress from 1648.99 to 4507.96 psi. Two under-pressure zones were identified across the entire field at depths ranging from 7000 to 8500 ft in UPX-01 well and 7000 to 9000 ft in UPX-05. Safe drilling mud pressures for maintaining a stable borehole in UPX field should not exceed fracture pressures of 1648.99 psi at shallow depths and 4821.53 psi at deeper depths to prevent loss in circulation. Similarly, drilling mud pressures should not be less than formation’s pore pressure of 2083.75 psi at shallow depths and 3277.22 psi at deeper depths to prevent a kick and blow-out from occurring in the field. This study recommends well break-outs be acquired in order to determine the directions of horizontal principal stresses for geosteering.