Egyptian Deepwater Development, a Case Study

Technology Focus The oil- and gas-production industry has experienced dramatic price swings over the past year. Crude-oil (spot) prices have varied from more than USD 120/bbl to less than USD 40/bbl since the third quarter of 2014. In high-price environments, technology can be developed economically to exploit additional resources. In low-price environments, technology must be deployed selectively to optimize production. New technology may still be developed and applied, but it is likely to be very focused on reducing operating costs; on the other hand, existing technologies may be revisited, to be applied more effectively. At all times, industry seeks to improve well productivity. Well productivity is critical during low-price cycles; it is directly related to cash flow and to reserves calculations. Major advances in inflow-control-device (ICD) design and installation have occurred over the past few years. These devices generally are used to manage water breakthrough or to improve the production profile across a large interval. The goal is to minimize workover requirements while optimizing hydrocarbon production costs. Paper SPE 171836 discussed results of an extensive study to compare actual well performance to design with ICDs. The study includes results of failure analyses, which showed that material selection is important for a device to reach its design life. System operation affects field productivity. Slugging flow in subsea flowlines and risers, leading to pressure surges and excessive liquid levels in the first stage separator, is a major contributor to downtime and suboptimal performance in offshore production facilities. Production facilities operate most efficiently when flows are fairly stable. Slug-suppression technology has been applied historically in shallow water and onshore facilities. Paper SPE 170731 described the successful use of active slug-suppression technology in a deepwater facility. This is an example of integrating existing technologies— slug suppression and process-simulation/ process-control theory. The number of subsea wells is continuing to increase. These wells typically are designed to higher standards than onshore or platform wells because interventions are difficult and costly. However, lower-cost options are needed in the event that an intervention is required. Paper SPE 173647 described a case study in which a contingency riserless (light) intervention plan was implemented. Although this technology may not be applicable to all subsea well- intervention needs, it demonstrates that lighter (lower-cost) options should be considered on the basis of an engineering assessment. The oil and gas industry is a cyclical business. Technology progress can be made during the high- or the low-price phase. As engineers, we have the responsibility to identify and apply appropriate technologies throughout all phases of the business cycle. Let us rise to the challenge. JPT Recommended additional reading at OnePetro: www.onepetro.org. SPE 170780 Autonomous Inflow-Control Valves—Their Modeling and Added Value by Eltazy Eltaher, Heriot-Watt University, et al. SPE 172776 Integrated Approach to Liquid Management for Deepwater Gasfield Developments by S. Ahmed, BG Group, et al. OTC 25656 Pipeline Repair Using Epoxy Technology by Kenneth Bryson, Subsea 7, et al.

Reliability of completion equipment and rig time are becoming more and more critical for subsea completions because of continually increasing water depths in which operators are being required to complete wells. In addition, completion designs must reflect the more stringent economic requirements of today's oil and gas industry. This paper will describe the use of a single-trip completion system that has been successfully and economically installed in the offshore Marimba and Bonito fields of South America. This new completion system has the capability to land the tubing hanger and install it in the wellhead before setting the packer and compensating for subsequent tubing movement.1 The new system also can employ pre-job calculations-based on initial well conditions and anticipated conditions during production-that help determine appropriate completion configurations and bottomhole equipment compatibility. Many failures in offshore wells, whether platform or subsea, can be attributed to inappropriate application of downhole completion tools or methods.2 Use of pre-job calculations during the equipment design stage can facilitate proper selection of design criteria and can help ensure operational safety and cost efficiency. The development of this new completion system will be discussed in detail. Three case histories that document successful test completions will be reviewed along with the economic gains and advantages that the reduction in rig time generated. Introduction Subsea completions were introduced to offshore operations in Brazil in 1977. Early "wet" installations were run in the Enchova field in water depths of approximately 400 feet [120 m] with production back to a floating production system. To date, 448 completions have been installed offshore and account for almost 60 percent of the country's production. Of these, 198 subsea completions have been installed in increased water depths. In 1985, discoveries were made in the giant deep-water Albacora, Marimba and Marlim fields at water depths ranging from 650 feet [200 m] to 6,500 feet [2,000 m].3 There are indications that a new field exists south of Marlim at even greater water depths (Figure 1). History Subsea completions that were run in increased water depths during the late '70's and early '80's identified several problems. The traditional completion design called for a standard hydraulically-set retrievable packer, and movement compensation was accomplished through use of a tubing seal divider (TSD). A traditional subsea completion design is shown in Figure 2. Since gas lift is the only artificial lift method available for subsea wells in this area, the design criteria for most of these completions reflect future gas lift operations.4 In these completions, the bottomhole assembly (packer and TSD pinned in the fully-closed position) would be run into the wellbore to the desired setting depth. Once the packer was anchored, the TSD was shear released. Completion times for these conventional subsea well completions averaged approximately four days from the time the tubing and bottomhole assembly were started into the wellbore until the tubing hanger was set and tested.

After several downhole sand control failures in subsea wells,1 the Okwori field development underwent a significant change of direction both topside and sub-surface. Numerous constraints were taken into account and successfully managed: tight rig schedule, complex logistics, contractual issues, etc…. Downhole, the original multi-zone, fully selective sand control completion system hat included sand screen expanded inside casing was abandoned. A new system was designed that allowed similar selectivity but with open-hole sand control. The new completion system implied a change in drilling practices, reservoir drill-in fluid and cake cleanup techniques that required simultaneous engineering. These in-depth modifications were designed and implemented in a matter of months. Topside, the FPSO had not been equipped to deal with sand production since downhole sand exclusion was assumed to be reliable enough. A sand management study recommended a series of modifications that minimized production shut-down while safely handling the produced sand and oil. Test de-sanding using a temporary sand trap determined that sand produced from weak formations could be stabilized. Severe service chokes were installed allowing production at a constant liquid rate. Experience accumulated to date highlights the importance of appropriate planning and application of reliable technical solutions in subsea completions. Introduction Due to the high associated costs, subsea well development concepts are usually "interventionless". The initial costs of these wells are mainly due to the mobilization and day rates of sophisticated drilling rigs. To re-enter subsea wells, similar rigs are required, hence the prohibitive cost of well intervention1. This is the driver behind declaring these wells "interventionless". Once the "interventionless" nature of these wells has been stated, it is presented as a challenge to well engineering. To provide a reliable solution, the most robust techniques for construction and completion are required. As subsea wells are expensive, each completion must give access to sufficient reserves for economical justification. in sacked and compartmentalized structures, sufficient reserve per completion means complex wellpaths penetrating multiple targets as beads threaded into a necklace. When co-mingling is not an option and sand exclusion is required, these wells also become host of expensive jewelry. We know since 1948 2 that more equipment is run in a hole, the more can and will go wrong. Hence the interventionless concept becomes the "Quest for the Holy Grail" of engineering. This pursuit translates into a risk based search for the best engineering practices and proven technologies that are compatible with the project economics, combined with best practice implementation. Risks that could adversely affect the project must be mitigated and required measures must be implemented so that the project remains economical throughout its life. In the Okwori project offshore Nigeria, the Addax Petroleum and service provider personnel tackled all of these issues in record time. A Complex Subsurface Okwori subsurface is far from the traditional image of a big oil anticline into which wells are positioned to maximize recovery. Okwori field is a chaotic ensemble of superimposed hydrocarbon and water bearing pools that are separated by faults3. Today, more than 250 fault-dip closures have been identified, 59 of them with proved hydrocarbon content. For additional information, please refer to references 3 and 4. Figures 1 and 2 illustrate the highly compartmentalized nature of the field both laterally and in depth. To access these scattered reserves the development plan called for dispersed well-head locations, hence a subsea development with each well being individually tied back to a central floating production separation and offloading vessel (FPSO).

Sand production poses a significant problem for marine natural gas hydrate efficient production. However, the bottom hole gas–water–sand inflow pattern remains unclear, hindering the design of standalone screen and gravel packing sand control completions. Therefore, gas–water–sand inflow patterns were studied in horizontal and vertical wells with the two completions. The experimental results showed that gas–water stratification occurred in horizontal and vertical standalone screen wells. The gas–water interface changed dynamically, leading to an uneven screen plugging, with severe plugging at the bottom and high permeability at the top. The high sand production rate and low well deviation angle exacerbated screen plugging, resulting in a faster rising rate of the gas–water interface. The screen plugging degree initially decreased and then increased as the gas–water ratio increased, resulting in the corresponding variation in the gas–water interface rising rate. Conversely, gas–water stratification did not occur in the gravel packing well because of the pore throat formed between the packing gravels. However, the impact of gas and water led to gravel rearrangement and the formation of erosion holes, causing sand control failure. A higher gas–water ratio and lower packing degree could result in more severe destabilization. Therefore, for the standalone screen completion, sand control accuracy should be designed at different levels according to the uneven plugging degree of the screen. For the gravel packing completion, increase the gravel density without destabilizing the hydrate reservoir, and use the coated gravel with a cementing effect to improve the gravel layer stability. In addition, the screen sand control accuracy inside the gravel packing layer should be designed according to the sand size to keep long-term stable hydrate production.

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 132909, ’Sand Settling and Locations of High Erosion in Subsea Production System,’ by S.A. Shirazi, SPE, and B.S. McLaury, University of Tulsa; E. Sow, SPE, BG Group; and M. Butter, SPE, A. Folefac, SPE, and S.A. Hassaballa, Rashpetco, originally prepared for the 2010 Trinidad and Tobago Energy Resources Conference, Port-of-Spain, Trinidad, 27-30 June. The paper has not been peer reviewed. When higher-than-expected sand volumes were produced from Gas Field 1 after a second well group was brought on line, it was believed initially that the sand production came from these new wells. Sand-transport studies demonstrated that the sand was produced by the first well group, rather than the second, but that the sand was not being transported through the main export lines until after the second well group came on line and gas velocities through the flowlines increased. Introduction The subsea wells in Gas Field 1 are completed with downhole sand control because of the unconsolidated nature of the reservoir sands. The gravel-pack completions are designed to stop sand but allow some fines production to prevent plugging of the gravel packs and screens and, hence, loss of productivity. Some solids production was expected over the life of Gas Field 1. However, after a second well group was brought on line in 2005, higher-than-expected sand production was observed. The first effect of sand production was the erosion of a valve downstream of a 36-in. slug catcher 6 months after the first well of the second group came on line. Because the produced solids may cause further erosion damage at locations of high production velocities, it was essential that the sand production be investigated and acceptable erosion rates be determined. A fines-management program was put into place following the first detection of solids production. Sand-Settling Calculations Studies were conducted to determine if there is a potential for sand to settle inside flowlines and transport pipelines. Calculations were performed for producing wells in the first group and second group and for the transport and export lines. Initial calculations were conducted in the production system for the second group of wells because sand production was observed first soon after these wells came on line. Earlier calculations showed that sand was not settling anywhere in the wells or in the subsea infrastructure from the wells in the second group to onshore. Therefore, the calculations focused on wells from the first group that had been produced since 2003. The first step in the sand-settling calculations was to gather historical production information and determine gas- and liquid-flow rates and the appropriate flow regimes in various pipe sections. The findings indicated that there are primarily two possible flow regimes in horizontal sections—stratified flow and slug flow. Experience with flow loops has indicated that sand settling is more prominent in stratified flow than in the slug-flow regime. Therefore, calculations assumed a stratified-flow regime. To make sure that sand can be transported even if a liquid film does not exist in the pipe, calculations also were performed for a mist/gas-flow regime.

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper IPTC 12388, "Single Trip Multi-Zone Gravel Packing - Case Study at Handil, Bekapai and Sisi-Nubi Fields," by Mark Banman, Eric Delattre, Mohammad Sofyan, and Siswara Suryadana, Total E&P Indonesia. It was originally prepared for the 2008 International Petroleum Technology Conference, Kuala Lumpur, 3–5 December. The paper has not been peer reviewed. Stacked gravel packs involve limited technical risk, but require considerable rig time when completing deep multizone, sand-control wells. Four field developments are challenging the conventional approach to completing long sand-control zones by using newer technologies. Nineteen wells have been completed with single-trip multizone (STMZ) technology comprising 77 frac packs/gravel packs. Introduction For many years, simple stacked gravel packs have been used in Indonesia as the primary cased-hole sand-control method. This kind of completion involves limited technical risk, but requires considerable rig time and cost when completing multizone wells with sand-control completions. Because of escalating prices, operators completing wells with multizone gravel packs are striving to cost-effectively produce as many unconsolidated reservoirs within a single wellbore as possible. The development of the Handil, Bekapai, Sisi, and Nubi fields illustrates the challenge of maximizing the recoverable reserves from such wells while minimizing the incremental cost of completing additional zones. These four fields are part of the giant Mahakham delta complex on the east side of Borneo Island (East Kalimantan, Indonesia). Two of these fields, Handil and Bekapai, are redevelopment projects, while Sisi and Nubi fields are new developments. All the fields are in relatively shallow waters. In each of the fields, production comes from two major sand/shale sequences. There is a series of deeper gas sands that produce without sand control and a series of shallower, oil-/gas-bearing sands that require sand control for efficient production. The shallow hydrocarbon reserves are distributed over a large vertical interval. This leads to wells with long multizone gravel-pack completions. Conventional gravel-pack techniques for multiple zones consist of a series of individual gravel packs, each one placed on top of the one below ("stack pack"). This generally uses at least two service-string trips per zone, one for perforating and the other for gravel packing. Use of a packer plug to isolate lower zones when perforating adds one additional trip per zone. A typical well in the Mahakham delta has five zones and would need 14 service-string trips and consume 20 to 30 rig days to install the stack pack together with the upper completion depending on the depth, perforating time, and use of packer plugs. This represents a significant capital cost.

Marlim Field is located in the northeastern portion of Campos Basin, offshore Brazil, in water depths ranging from 600 m(1,968 ft) to 1,100 m (3,608 ft). The field was discovered in September 1984 by the wildcat 1-RJS-219 A, in 853 m (2,800 ft) water depth. The areal extent of Marlim Field is 152 Km2(52 mi2). The main objective of this paper is to give a general outlook of the drilling, completion and workover operations in Marlim Field. It reviews well design development, drilling progress and the associated costs from the field earlier appraisal wells till the most recent development wells drilled in the area. The paper also describes the evolution of completion with emphasis in the work done in improving well design, minimizing problems and optimizing operations. The main causes of intervention are listed and described. Finally, the future plan for Marlim Field that includes the utilization of technologies such as extended reach, slender and multilateral wells is also depicted. Introduction Since the drilling of the wildcat well 1-RJS-219A in 1984, many developments related to drilling technique were obtained in Marlim Field. Improvements in well design, drill bits, drilling fluids and the use of new technologies helped to increase well safety, cut cost and raise oil production. The evolution of Completion on Marlim Field occurred basically on subsea tree installation systems and its connections to flowlines, methods of sand control, horizontal well completion and reservoir pressure monitoring with permanent downhole gauge. Installation of subsea tree and its connections has undergone three different techniques. It started with the Lay Away method, passed by the Vertical Connection method and nowadays it is being done with the Direct Vertical Connection method. Like in most very deepwater field, Marlim unconsolidated sandstone reservoir is a sand producer. Due to its peculiar characteristics, tools, procedures and technologies were customized to achieve good performance on sand control in vertical, directional and horizontal wells. To obtain regular pressure and temperature data from subsea wells with wire line gauges from a completion rig is economically unfeasible. The alternative is the permanent downhole gauge (PDG). At first the mean time before failure (MTBF) of the PDG systems installed in Marlim was very low. After changes on management and equipment the performance of this system improved a lot. The goal is to equalize the MTBF of PDG to the mean time before workover. Drilling Well Design and Operational Procedures - In the earlier stage of the drilling in Marlin, when few data were available, one of the main causes of preoccupation was related to the shallow and unconsolidated sediments. Initial designs used the common practice of jetting 48 or 46" pipes. The difficulty of handling and controlling the passage of these heavy pipes through the rotary table soon made the engineers look for other options. In 1992, the designers substituted the 46" pipes for a 42" housing and conductor pipe of 13 meters length resulting in reduction of time and consequently cost. In 1993, the designers decided to jet a 30" casing having a floating shoe at the end. This procedure not only proved to be better and more acceptable solution, but also reduced remarkably the time of the first phase as shown in Fig. 1.

Recent trends in offshore field development have been toward subsea completions, especially in the North Sea. It is estimated that the number of subsea wells in the North Sea will double by 1994. Since subsea wells are often completed in the same formations as conventional offshore wells and completion designs are the same, downhole service requirements for subsea wells are generally the same. Semi-submersible rigs using tensioned risers have offered the only practical means of performing vertical intervention services such as wireline and reeled (coil) tubing. A subsea reeled tubing system (SRTS) has been designed and manufactured that offers a more economical means of performing a range of reeled tubing services on subsea wells. The SRTS is operated from a diver support vessel (DSV) or other relatively small vessels in lieu of a rig which effects a considerable savings in cost and time. A tensioned riser is not required with the SRTS. This paper describes the SRTS in detail and discusses the reeled tubing services offered by the unit. Safety features and operational procedures are also discussed.

Amoco Sharjah Oil Company (ASOC) is conducting a horizontal/multi-lateral drilling program in the lower Cretaceous carbonate formation of its Sajaa retrograde/condensate field which lies at a true vertical depth of approximately -12,000 ft subsea. This program has included two single laterals and three dual lateral wells (two herringbone and a stacked-style). Three wells (one single and two dual laterals) were re-entries into original vertical development wells. Production rates from these wells are three to five times the calculated rate from vertical wells. Coil tubing production logging and stimulation operations were conducted in two of the wells of measured depth >15,600 ft (horizontal lateral length of 3,500 ft). Selective re-entry in the dual lateral with coil tubing was not successful. An acid wash stimulation improved the production rate by 30% in the single lateral well that was treated. The production log was capable of providing gross production rates of each lateral. A multilateral re-entry system has been installed in the current stacked-style dual lateral for future selective re-entry by coil tubing. Introduction Amoco Sharjah Oil Company discovered the Sajaa retrograde condensate field in December, 1980 and production began in 1982. The onshore Sajaa field is located in Sharjah, United Arab Emirates. The majority of the reserves have been developed from the Shuaiba and Kharaib carbonate formations in the lower Cretaceous Thamama group. The Shuaiba formation's top is at approximately -12,000 ft subsea and the Kharaib's top is 250 ft below the Shuaiba top. The Shuaiba is capped by the Nahr Umr shale formation. By November 1995 the field had been developed with 28 vertical development wells. A study concluded that a horizontal well in the Shuaiba should be significantly more productive than a vertical well because of wellbore contact increase. This led to the recommendation of the Sajaa field's first horizontal well. This paper reviews the drilling, completion and stimulation of the Sajaa horizontal wells; two single laterals and three dual laterals. The major drilling problem is geosteering in the Shuaiba formation because it has minimal logging characteristics, changing dip angles and unpredictable faults. The operations are complicated by the vertical depth of - 12,000 ft tvd and bottom hole temperatures of 295 F. The laterals are not lined, but the desire to selectively re-enter the dual laterals has led to several alterations in the completion philosophy. Completion designs have to be adapted to new wells and dual laterals which are initiated from original vertical wells. Coil tubing was used to run a production log in one of the dual laterals which allowed gross production measurement of each lateral. Selective re-entry into each lateral was not successful and the failed coil tubing acid stimulation required a work-over. The laterals were successfully re-entered with tubing and stimulated. Coil tubing was used to perform a 15% HCl acid wash of a single lateral increasing production by 30%. Horizontal Well No. 1 - Single Lateral The location of the first horizontal well was selected because the area had marginal productivity, but contained minimal reservoir uncertainties and dominant Shuaiba productivity. The well was drilled vertically to 10,490 ft then built to 390 at 11,478 ft (11,380 ft tvd) where the 9-5/8" casing was set in the Nahr Umr formation. An 8–1/2" pilot hole was drilled through the target formation to define its characteristics. The porosity zone identified for the lateral was between 11,975 ft and 12,020 ft md (Fig. 1). It was bounded by the Nahr Umr shale (top) and Shuaiba low porosity (bottom). There was concern that the Nahr Umr shale below the 9-–5/8" casing would be less stable at the higher inclinations so it was protected with a 7", 35 ppf liner. P. 349^

The Gulf of Mexico (GOM) is one of the world’s most prolific hydrocarbon basins, with more than 80 years of development since the first offshore drilling began. GOM is the primary source of the United States (U.S.) offshore oil and natural gas production. According to data published by the United States EIA, approximately 15% of the U.S. domestic oil production came from offshore oil and natural gas fields in federal waters, with over 99% of that production coming from the Gulf of Mexico over the most recent year of data available at the time of this paper’s publishing (Q4 2022-Q3 2023) [1]. Nonetheless, GOM reservoirs have complex depositional settings. Reservoir heterogeneity, stacked pay system, reservoir compartmentalization, high-temp and pressure are some of the common challenges seen in these fields. The use of conventional completion design in vertical wells with commingled production form multiple zones has led to multiple operational challenges. In this paper, we explore the use of intelligent completions in the deepwater GOM as a solution to this problem. Specifically, we will show how intelligent completions have allowed for increased production, reduction in operating expenses, enhanced overall reservoir recovery and improved safety and environmental performance. A case study of intelligent completions in GOM is with sliding sleeves that are hydraulically controlled from the production facility. In this paper we will be focusing on one of these deepwater oil fields located in the northern GOM. The field is comprised of a subsalt reservoir with best-in-class Pliocene age sands (main target reservoir). These conventional sands have good porosities and permeabilities up to 1 Darcy. The target producing reservoir sands are comprised of multiple, stacked, turbidite sands. This has led to the standard field development in this area to be vertical wells with commingled production from multiple zones. The field has been producing back to a deepwater facility for more than 5 years through multiple subsea wells. Initial production was over 10,000 barrels of oil per day (bopd) per well. The producing reservoirs are supported with strong aquifer drive and leads to rapidly increasing water rates in wells post water breakthrough. Riser base gas lift is utilized in all producing risers to help optimize production.

In the last few years the oil and gas industry has been turned around with respect to gas production and availability. Clean burning and abundant natural gas resources have caused high demand, and because of the tax incentives, coalbed methane is a popular gas source. Coalbed reservoirs are much different from conventional natural gas reservoirs because drilling and completion considerations are not the same due to the rock properties. Horizontal wellbores are considered to be very effective in reservoirs that are relatively thin, naturally fractured, and anisotropic with regard to permeability. Coalbed reservoirs have all of these features. The concern today is how to get the gas out of the coalbeds in an economic manner. Coalbed cleat systems are made up of natural fractures, hence vertical wells drilled in the reservoir must be fractured. Horizontal well drilling and completion is an alternative technique to overcome low production as well as reservoir heterogeneities in coalbed reservoirs. Some authors have shown that a properly drilled and completed horizontal well can increase production by about seventy-five percent over that of a fractured vertical well. This paper discusses coalbed properties essential to the application of horizontal drilling and completion. Several techniques used to drill and complete horizontal wells in coalbed reservoirs are discussed and compared with each other to distinguish their application. Introduction The US Bureau of Mines has demonstrated that methane drainage by horizontal and directional boreholes is a safe and effective method of removing methane in advance of mining and of controlling methane emissions during mining. Horizontal holes were found to have the advantages of relatively low drilling costs and the ability to intersect the coalbed cleat or fracture system, thus increasing permeability to gas flow. Hydraulically stimulated vertical holes on the other hand had the disadvantages of requiring large numbers of surface sites, higher costs, and production and maintenance problems. The concept of directionally drilled degasification holes was originally considered by the Bureau of Mines as a means of combining the best elements of the surface vertical borehole and underground horizontal drilling techniques. In the past few years the oil and gas industry has been turned around to be called the gas and oil industry. The clean burning, easily accessible, and overly abundant natural gas resource has created a high demand. For many years, coal mines were degasified and most operators thought little of the value of the gas. But recent demand and tax incentives have made coalbed methane gas a popular item. It is believed there is a large amount of gas stored in coalbeds throughout the United States with current estimates of 400 trillion cubic feet of gas being stored in coalbeds (Fig. 1, Table 1). Today's concern is how to get the gas out of the coalbeds in an economical manner. Recovery of gas from coalbeds occurs in the presence of the low porosity and very low permeability inherent to these beds. The permeability is made up of natural fractures which are arranged in a cleat system. There are two cleat systems: the face cleat and the butt cleat. The face cleat is continuous throughout the reservoir and provides the largest permeability. Vertical wells drilled in the reservoir must be fractured to be in contact with the cleat system and maximize recovery. Coalbeds are much different than conventional natural gas reservoirs in that drilling and completion considerations are not the same due to the unique coalbed properties.

This paper deals with the Gullfaks A Subsea Production Systems: Philosophy, development plan, technical and functional descriptions and Statoil's experience to date in the various phases, including start up. The wells are connected to the Gullfaks A platform, which is a PDQ (processing, Drilling and Living Quarters) Platform. Subsea operation were accomplished. THE GULLFAKS FIELD The Gullfaks field is situated 140 km from Norwegian mainland (Figure No. 1). The field appraisal drilling showed that the reservoirs are heavily faulted with a main north-south fault through the whole field. Recoverable reserves of the Gullfaks field are assumed to be 210xI0 6 Sm3 (1,320x106 Bbls) of oil and 23X109 Sm3 (812x109 SCF) of gas. The water depth at the field varies from 13(to 220 meters. GULLFAKS A SUBSEA DEVELOPMENT PLAN – Develop reservoirs outside the efficient reach of the platform wells. Figure No. 2. – Accelerate production and improve economic returns. – Gain information and experience for future field developments. The scope of the subsea part of the GullfakS A Project has changed from: (Information available in full paper) These changes are due to increased knowledge from the drilling of the subsea wells and new reservoir simulations. The subsea wells are of a wet satellite type non-TFL (non-thru-flowline); However, wireline serviceable. The same Christmas tree is used both for production and water injection. Each well is connected to the platform with a separate Flexible flowline, a hydraulic umbilical and an electrical umbilical. The system is designed to be diverless, i.e. a11 tools required for installation and workover are non-diver assisted. The design life of the subsea production system is 10 years. The plan for the development, installation at start-up of the Gullfaks A subsea systems are shown in Figure No. 3. SATELLITE SYSTEM The main components of the satellite system as shown in Figure No. 4. They consist of:protective structureChristmas tree Systemsatellite control moduleworkover systemtools allowing for diverless installation and workover. The Gullfaks A satellite system is a new development Protective Structure The protective structure is an open frame type structure allowing ROV access. It has been designed to deflect fishing gear, with a high probability, and is piled to absorb 100 tons anchor dragging loads. A removable roof is fitted to the structure to provide overhead protection. The structure is shown in Figure No. 5. Additional protection is installed in the pull in areas after pull in and connection. Wellhead & Tubing Hanger Prior to start of drilling operations, the protective roof is removed by a guideline establishment tool. In a single run, the tool establishes guidelines to the four main guideposts and retrieves the protective roof. An 18 3/4", 10,000 psi CAMERON WS-11 weight set wellhead system is used in the subsea wells. A 5-string casing programme is used, comprising 30", 20", 16", 13 3/8" and 10 3/4" casing strings. The tubing hanger system allows the tubing hanger to be run, orientated, tested and locked in one trip.

Offshore platforms and subsea wells often are designed to enable interventions to be performed during the completion phase of the well construction. An example of the above is the deployment of a deep-set plug (as a temporary barrier) to set the production packer and test integrity of the production tubing. Each intervention has a direct cost due to rig time and the risks mitigation associated with the manual rig-up and testing of the pressure-control equipment addressing health, safety, and environmental challenges becomes a high priority that will consume time during the planning of operations. Operational risk is present due to the mechanical methods used for deployment and retrieval of the plug, and in deviated well designs, this risk will be even more severe due to the implied impact. Using a case study in Equatorial Guinea, West Africa, this paper demonstrates how barrier provisions with remote open/close technology capabilities enables interventions to be removed from a completion design. The technology described was used in a horizontal subsea producer well drilled to 3,460m, and will illustrate how combining downhole electronic control with a full-bore hydraulically operated barrier valve removes any need for running control lines to surface. Surface applied pressure and time combinations were used to command remote actuation of the valve. The factors that must be considered when determining these commands are also discussed. The successful field deployment discussed in this case history illustrates how applying remote open/close technology provided the opportunity to challenge conventional completion methodology and was capable of providing significant cost savings as well as simplifying operational strategies.

The sand production problem is plaguing the petroleum industry by its adverse effects on thousands of oil and gas fields throughout the world. A tremendous amount of money is spent each year on attempts to predict and control sand influx and/or repair wells and equipment damaged by sand. Sand inflow into the well during production leads to casing abrasion and failure, formation damage and distortion, and frequent sand removal and cleaning. The sand control process has a major influence on the type of the well completion design and it influences the guidelines for the completion process. In addition, many wells are currently being produced below their potential in order to restrict sand influx or erosion, and/or as a result of poorly designed or installed sand control methods. Evidently, the sand prediction and control problem is exceedingly complex and suggests the use of heuristics and the appropriateness of the expert systems technology. An automated sand control consultant and expert system has been developed. The system is aimed at assisting users in predicting sand occurrence during production and in selecting and designing the proper sand-exclusion treatments. The knowledge base of the system is based on an easy upgrade, easy expand format and involves four primary modules, thus giving the end-user greater flexibility to tentatively access and evaluate different scenarios of knowledge processing. Input data can range from “not known” formation characteristics and/or well stimulation requirements, for which the system gives conservative recommendations based on the remaining known facts, completion characteristics of the hole, well history, and geological probability; to cases with detailed information available, in which case very elaborate and precise recommendations are prescribed. This paper describes the knowledge involved in various modules of the sanding system, as well as future plans and further developments.

Semisubmersibie based Floating Production systems (FPS) have been extensively used in offshore field developments worldwide. Most have been converted from existing drilling semisubmersibies. Faced with a rapidly dwindling inventory of existing platforms to convert, the industry near cost competitive new build units. this paper presents the principles and development of just such a platform. It will be demonstrated that this new build platform is cost and schedule competitive with a conversion for a deepwater Gulf of Mexico development. INTRODUCTION Monohull or semisubmersible based FPSS converted from existing vessels, featuring low capital mat and cycle times to first oil, permit operators to economically develop small to medium sized fields in deepwater or remote regions [1,2]. Historically, field developments employing floating production systems were focused mainly in Brazil, West Africa the Far East and Australia. More recently, Operators in the U.K. and Norwegian sectors of the North Sea and Atlantic Frontier have accelerated the use of floating production systems to exploit their more remote, deepwater or marginal fields. This increase has been fueled by the growing confident and coat reductions in subsea and riser systems [3]. A case point is the development of the Njord field in the Norwegian North Sea by Norsk Hydro in about 1000 ft. of water by subsea tiebacks to a 45,000 tonne newbuild floating drilling production unit the Aker P45[4]. Semisubmersible based production or drilling and production units, in combination with subsea wells, have been used worldwide to commercially develop small to medium fields (50 to 100 million barrel reserves) in a wide range of water depth and environments [5]. With the exception of 3 newbuild units, most have been converted from second or third generation semisubmersible Mobile Offshore Drilling Units (MODUS) The availability of suitable candidates for conversion was never a problem, until recently. The soaring demand for deepwater exploratory and appraisal drilling has depleted the pool of candidate rigs for conversion and also raised acquisition prices. There is a perception that a newbuild unit will cost a lot more and will have a significantly greater cycle time to first oil than a conversion. It is the intent of this paper to clearly demonstrate that a newbuild production semisubmersible, adapted from and employing the principles embodied in the Aker P-45 floating production unit can be eonunereially competitive with a converted semisubmersible FPS for a deepwater GOM application. DESIGN APPROACH Figure 1 illustrates the fimdarnental departure from the traditional approach to building semisubmersibles, that will achieve the design objectives of low cost and accelerated schedule for a newbuild FPS.