The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
- Data Science & Engineering Analytics
The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
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Orta, Cesar (Weatherford) | Al Faqih, Mohanad (ARA Petroleum) | Al Gharibi, Bader (ARA Petroleum) | Al Shabibi, Mohammed (ARA Petroleum) | El Khouly, Ali (ARA Petroleum) | Matin, Yasir (Weatherford) | Hadj-Moussa, Ayoub (Weatherford) | Saleh, Mujahed (Weatherford)
Abstract Drilling with a gas cap over the Natih formation in Oman often results in excessive flat time. Using the current dynamic fill equipment to deal with kick and loss scenarios leads to extensive nonproductive time on the rig. Managed pressure drilling (MPD) is a well-established drilling technology, and diverse variants exist to suit different requirements. All those variants use the rotating control device (RCD) as a common piece of equipment, but their procedures are different. The pressurized mud-cap drilling (PMCD) technique in the Natih formation replaces the need for traditional dynamic filling technology. The PMCD application enhances the drilling and completion processes by reducing flat time when total downhole losses are experienced. This paper elaborates on PMCD as a proven drilling technique in total loss scenarios when drilling with it for the first time in the Natih formation in Oman. It describes the PMCD process, the associated equipment, and the results of the inaugural application in the Qalah field.
Saroj, Vikram Singh (Petroleum Development Oman) | Al Zadjali, Faris Said (Petroleum Development Oman) | Calvert, Stephen John (Petroleum Development Oman) | Al Hattali, Ahmed Salim (Petroleum Development Oman) | Al Rawahi, Mohamed (Petroleum Development Oman) | Hussain, Abid (Petroleum Development Oman) | Al Kharusi, Dawood (Petroleum Development Oman)
Abstract This paper discusses the further development of Burhaan West Field, a complex multilayered onshore tight gas reservoir that is one of the largest in the Sultanate of Oman. After several years of production through vertical comingled fractured wells, the foreseen decline below production target triggered an integrated assessment of the field. After considering various subsurface development and surface evacuation options, an opportunity for further field development at minimum cost was identified and selected. The integrated assessment of the field for further development optimization included the following work-streams: Interdisciplinary data analysis to determine the critical elements of the recovery process. Building a range of integrated models capturing the subsurface complexity and diversity of rock properties. Optimized well type and spacing which focused on the advantages of infill drilling for improved aerial/vertical drainage. Phased development along with de-risking of the newly proposed areas. Decision based integrated production modelling to screen various evacuation options. Cost optimization The development of a Well Reservoir and Facility Management (WRFM) strategy. The proposed optimized field development enhances the field gas production capacity by 50%, while increasing ultimate recovery by 24%. This is achieved at low surface development cost, utilizing existing facilities, through infill drilling in the Core area and development of the Extension area. The conducted work highlighted the following key aspects of developing a tight gas reservoir: Integrated cross-discipline data analysis is required to identify the critical elements contributing to gas and condensate recovery processes. In the Burhaan Field, this has revealed the presence of key marginally resolvable to sub-seismic features that were not previously identified. Integrated Assessment (Integrated Production Modelling) enables for robust and quick evaluation of a variety of surface development options (e.g. evacuation routes and capacity) that is a key in achieving significant project cost optimization. Large gas field developments generally benefit from a phased development approach, where newly proposed areas can be de-risked while high confidence areas are being developed. A comprehensive WRFM plan is a key component of field development. This plan focuses on the activities required to address the field specific uncertainties and associated risks. It needs to be strictly implemented to ensure the delivery of promised volumes. This case study shares the insights on the challenges faced in developing multi-layered tight gas fields. It highlights how development decisions need to be governed by field specific characteristics that can be identified through multi-disciplinary integrated data analysis. The paper also provides an example of an effective Production Modelling workflow to screen through surface development options and demonstrates how focused data acquisition and specific WRFM activities can be embedded into tight gas developments.
de Koningh, Hans (Horizon Energy Partners) | Herold, Bernd Heinrich (Schlumberger Logelco, Inc) | Cig, Koksal (Schlumberger Oilfield Srvcs) | Ali, Fahd (Schlumberger) | Mahruqy, Sultan (Petroleum Development Oman) | Johnston, Sean (Schlumberger) | Karavadi, Venkata Narayana Rao (Petroleum Development Oman) | Abd El Moula, Ibrahim (Petroleum Development Oman)
Abstract In a time of declining production and increasing demand, geoscientists are challenged more and more often to develop new techniques and strategies for evaluation and appraisal of increasingly complex and deeper reservoirs. This paper describes the subsurface challenges and how, through optimized data acquisition and application of integrated formation evaluation techniques, tight gas reservoirs have been characterized and the objectives of data acquisition programs have been met. Examples are illustrated with data from three recent wells. The operating environment is very challenging, which affects the decisions for data acquisition. The use of salt-saturated mud systems creates a high resistivity contrast between mud and formation, affecting image and nuclear magnetic resonance data quality. The anisotropy in the stress field results in elliptical boreholes with breakouts. This leads to complex resistivity log responses, which require special corrections and a modeling approach. Furthermore, the data quality of wireline pad tools is compromised. The low-porosity formation affects the accuracy of water saturation calculations and fluid mobility ranges in the sub-md region make fluid sampling and the acquisition of formation pressures a complex task. Often completion decisions have to be based on basic formation evaluation data alone as acquiring pressure data or fluid samples is not possible. Only if borehole effects are sufficiently understood and corrected for can this basic formation evaluation be presented with some confidence. Trend analyses are, however, often more instructive than absolute averages of calculated pay summaries. Resulting porosity and saturation estimates should always be put in context of other well results and alternative data sources like borehole image and mud gas data. Introduction The exploration for deep gas in Oman started after a decision was made to deepen an exploration well targeting an oil reservoir at shallower stratigraphic levels. The Saih Nihayda gas-condensate field was discovered in 1989, followed by Saih Rawl (1990) and Barik (1991). Consequently exploration and development of gas and gas-condensate reservoirs has focused on deep reservoirs in the Haima Group in North Oman's Ghaba and adjacent Afar area (Fig. 1). The fields making up the Kauther cluster where discovered in 2001 and 2002 and are currently being developed. Following success in Ghaba basin exploration efforts have focused on the deeper still Haima formations in the Fahud Salt basin. As the reservoirs are typically relatively thick (~200m) and have low permeability (<0.1md) the developments are based on vertical wells that are stimulated with massive vertical fracs. Formation evaluation is becoming increasingly challenging with increasing depth. Three factors that affect our ability to interpret downhole data are discussed in detail in this article. The first one, an abnormal pressure regime, results in severe borehole breakouts. The second, increasing temperatures with increasing depth, results in reduction of data quality, tool failures and a reduction in available downhole sensors. The third, decreasing porosity with depth, requires high accuracy in sensors to allow correct porosity evaluation as inaccuracy in porosity estimates leads to unacceptable uncertainty in fluid saturation estimates. Combined these three factors result in a difficult logging environment making it increasingly difficult to acquire a good quality data set for formation evaluation.
Introduction Shell Global Solutions International (SGSI), CDS Engineering and Petroleum Development Oman LLC (PDO) are jointly field testing a new gas/oil/water in-line separation system (ILS) as part of the Smart Facilities Solutions portfolio of technologies. PDO has a requirement to have water injection facilities at the Al Huwaisah South West production site for reservoir support. Since start of production in 1971, the water cut has gradually increased to 85 - 90 % and is expected to increase further. This paper will describe the joint effort of Smart Facilities Solutions and CDS in applying new in-line separator equipment: a degasser, dewaterer, and hydrocyclone. PDO Al Huwaisah Water Injection Project The Al Huwaisah field has been producing since 1971 with current gross production about 45,000 m3/d (see Figure 1). To improve oil recovery water injection (as well as infill drilling and exploitation of undeveloped areas) new facilities are planned. The project is to develop the South West Area by installing a facility to treat the SW production fluid to provide injection quality water for the water injection wells in the SW area. Presently, the SW area has only wells with a Multi-port Selector Valve (MSV) feeding a 12 inch GRE line to Al Huwaisah gathering station. Over the years the water cut has gradually increased to 85+% and is expected to increase further. The facilities will separate water, oil and gas. The compact inline separation system is designed to separate water, oil and gas. The ILS system is described in the next section. Water is locally injected. Gas and oil and any excess water is combined and sent to the central gathering station through an existing 12 inch GRE pipeline with gas and crude exported to Yibal. The compact inline separation system is a joint effort of SGSI and CDS. In-line Separation System The ILS was seen as an important technology, so SGSI went out into the market for competitive tendering based on the specific criterias of the ILS. CDS Engineering was selected as most suitable for the requirements needed for Al Huwaisah SW project. The ILS has many advantages, such as:It replaces the conventional bulk separator and several stages of separation followed by a water polishing unit. It is built to pipe code, instead of vessel code It has low capital cost It requires less manufacturing time, so there is a faster project schedule and earlier production It is compact, so it requires much less space and weight, which is an advantage for offshore platforms and eventually subsea applications. Figure 2 shows the PFS of the ILS skid, which is composed of a Degasser, Dewaterer, booster pump and hydrocyclone. The ILS is designed for 12,000 m3/d (75,000 bpd) gross liquids and 65,000 m3/d (2.3 MMSCFD) gas. The crude is a light crude of 35 API gravity. The dewatered oil has a target specification of 15 vol% water in oil. The required injected water specification is less than 100 ppmv oil in water. In the Degasser (see Figure 3) a stationary, horizontal swirl element creates centrifugal forces to separate gas from the oil/water mixture. A gas core is formed in the center of the pipe, which is subsequently collected and routed to the vertical scrubber section. Fast action control valves are used to control the system. The Dewaterer uses similar principles as the Degasser to remove the bulk oil from the produced water stream. A small fraction of gas is also removed. The swirl element creates a core of oil, together with a small amount of gas, which is collected and routed to the vertical scrubber section. The produced water, which still contains a small amount of oil, is routed through a pump to a novel design, low pressure drop hydrocyclone for final separation of the oil from the produced water. Also, there is an additional Dewaterer test to be performed, which would process the 15 vol% water in oil stream to make a tighter specification of 5 vol% water in oil.
Mijnssen, F.C.J. (Petroleum Development Oman) | Davies, A.H. (Petroleum Development Oman) | Grondin, K. (Shell International Exploration & Production) | Keating, John (Petroleum Development Oman) | Hsu, C.F. (Shell International Exploration & Production) | Amthor, J. (Petroleum Development Oman)
Abstract The billion barrel Al Huwaisah Field is located in Northwest Oman and produces from heterogeneous rudist-dominated limestones of the Aptian Shuaiba Formation. It was discovered in 1969 and has been on-stream since 1971. Production peaked at ca. 44,000 bbl/d in 1973 after which production declined to ca. 19,000 bbl/d. Recently, production rates have increased to ca. 28,000 bbl/d, but field-wide recovery factor is still only 18 % indicating that potentially large scope volumes remain in the field. In 2000, an integrated review of the Al Huwaisah field indicated a number of opportunities to mature these large scope volumes. It was noted that key to maturing these opportunities was an improved understanding of the highly complex reservoir architecture, especially regarding the distribution of fractures. Subsequently, a comprehensive fracture study was executed that included both geological information and production data. This study resulted in an improved understanding of the water movements in the field explaining the highly variable first-year net oil rates (0 - 2,500 bbl/d) of the Al Huwaisah wells. The results of the fracture study were incorporated in newly created static and dynamic models that also took into account the small-scale sedimentological heterogeneities of the Al Huwaisah reef deposits. These models were used together with the historic production review to identify production optimization opportunities, like barefoot completion strategies and water shut-off using expandable tubulars. A few of these opportunities have been implemented so far, resulting in sometimes more than 50 % increase in net oil production for the targeted wells. The barefoot completion strategy has resulted in a 10 % cost saving per well. In addition, well planning using seismic amplitude information was tested, which resulted in more than doubling the initial net production in several wells compared to the average initial well rates in Al Huwaisah. In identifying the most optimal long-term development strategy for the Al Huwaisah field, the subsurface models are being used to test the benefits of introducing water injection and miscible gas flooding. Based on the model data, a limited water injection field trial is ongoing which resulted in a ca. 20 % increase in net oil production for the pilot area. Opportunities for implementing a miscible gas trial are currently being evaluated. Introduction The Al Huwaisah field is located in the NW part of Oman, some 350 km WSW of Muscat (Figure 1) and extends 20 km by 6 km. The field was discovered in 1969 and top structure is located at a depth of at 1,435 m tvdss (~1,535 m tvd).
Abstract Patterns for multilateral (ML) injector and producer wells are successful in boosting reservoir oil recovery, but waterflood sweep uniformity is critical in this environment. Until recently, complete quantitative evaluation of injection water distribution in ML legs has only been possible by whipstocking workover pipe into each lateral leg, and by subsequent log sensor pumpdown operations. Any well remediation operation was conducted separately from the logging operation. The complexities and costs of evaluating and treating MLs have left well operators with limited practical and economical options for remediation. The last 10 years have seen successful equipment development for selectively entering level 1 and 2 lateral extensions - classifications of the Technical Advancement of ML wells (TAML) (Fig. 1) - with coiled tubing (CT). This paper describes a new, combined diagnosis and treatment service enabled by conveying logging sensors into any selected leg of a ML well. Initially, the relative injection distribution between legs is measured by pulsed neutron logging the injection-water velocity along the well's natural path. Then a real-time decision is made as to which legs to enter for further evaluating the water-injection profile. Evaluation results are available in real time for planning treatments to improve waterflood sweep efficiency. The CT unit, using the same lateral reentry equipment as for log sensor conveyance, can then do stimulation or water shutoff treatments. If desired, the ML can undergo post-treatment evaluative logging. ML injector diagnosis and treatment are now possible with a single combined operation at the wellsite, without a workover or drilling rig. The ability to simultaneously access and log all levels of live ML wells with CT, for real-time decisions and action on optimal treatment, provides a cost-effective option for optimizing recovery. Introduction Drilling ML wells has significantly reduced field development costs and provided access to additional reserves. However, there is still a need for a better way to reenter laterals to effectively manage the reservoirs, enhance production, and maximize ultimate oil recovery. To date, the majority of ML wells drilled by Petroleum Development Oman (PDO) are in reservoirs in the Shuaiba formation of the Qarn Alam area. The Saih Rawl (SR), Musallim, and Burhaan fields are being developed with closely spaced ML injector and ML producer patterns. A total of 85 ML wells have been drilled in these three fields. They produce approximately 11,000 m/d amounting to almost 10% of PDO's total oil production. A recent reservoir simulation study revealed the potential to enhance production from these fields by approximately 800 m/d through ML remediation work, such as restimulation and zonal isolation. After several months on production, some wells have shown signs of early water breakthrough. It is imperative that diagnostic and treatment operations are conducted expediently to return the reservoir injection scheme to its optimal state with waterflood sweep uniformity. Until recently, to diagnose and treat an ML injector where there is suspected waterflood short-circuiting from a formation fracture, the following used to be involved (using the operations history on Well SR-115 as an example):Logging of the natural path with a pulsed neutron sensor (RST* Reservoir Saturation Tool) conveyed on CT and taking WFL* Water Flow Log measurements to find the leg taking most of the injected water. Moving a drilling or workover rig to the location. Whipstocking workover pipe down the length of the leg taking most of the injected water. Pumping an RST tool down the leg inside the workover pipe and taking WFL stations to evaluate the depth of the short-circuiting fracture. Repeating steps 3 and 4 for any subsequent legs. Running in for cementing and fluid pumping operations to isolate the fracture zone. Although the previous list is effective for ML diagnosis, it represents a costly and drawn-out procedure. Any well remediation operation is conducted separately from the diagnostic logging operation. The complexities and costs of evaluating and treating MLs have left PDO with limited practical and economical options for remediation.
Al-Mugheiry, Mohammed Adil (Petroleum Development Oman) | Mueller, Guy (Petroleum Development Oman) | Braas, Marcel (Petroleum Development Oman) | Materna, Thomas (Petroleum Development Oman) | Davies, Huw (Petroleum Development Oman) | Hsu, Chia Fu (Shell International) | Keating, John (Petroleum Development Oman)
Abstract After 30 years of production history in the Al-Huwaisah oil field of North Oman, it is still possible to bring best wells on stream. Both vertical and horizontal technologies have been implemented with variable combinations of gas-lifted or ESP completions and barefoot or lined reservoir sections. In addition, these technologies are implemented on this complex carbonate reservoir characterized by a high degree of heterogeneity embedded in four depositional environments (i.e. Channel, Fore Reef, Main Reef and Back Reef) and spread over an area of 22km by 10km with zones of strong and poor aquifer support. This necessitates the need for a sound data gathering strategy to manage the subsurface uncertainties. The improvement in recent production history was mainly the result of implementing a multidisciplinary team approach to define a more structured methodology for identifying the remaining oil targets and ranking them using basic petroleum engineering tools in a more synergistic fashion. Past operational experience has also helped in selecting the best completion and stimulation practices. The outcome of implementing these practices on such a complex field showed that improved oil recovery requires a more flexible approach in field development philosophy in the sense that not always horizontal well technology is better than vertical or lined wells are better than barefoot. The field is currently being evaluated for a possible application of Water-Alternate-Gas (or WAG) hydrocarbon recovery technique. Only parts of the field are found to be acceptable for the WAG pilot test according to the specified pre-requisites for this technology. It is evident that technology solutions for complex carbonate field such as Al-Huwaisah calls for a ‘dynamic focus’ in the sense that different parts of the field may require different types of technologies to meet the challenges of extremely variable complexity. Introduction The Al-Huwaisah field in North Oman (Figure 1) was discovered in 1969 and has been on stream since 1971. The field is a NE-SW elongated dome and is producing mainly from the Cretaceous Upper Shuaibah formation, located at a depth of about 1450 mss (1520 mTVDbgl). The free-water-level at 1490 mss is overlaid by large transition zone. The size of the field is about 22 km long by 10 km wide with strong aquifer drive along the NW flanks, and poor pressure support in the SW and SE direction. The initial reservoir pressure was 17,000 kpa with a bubble-point pressure of 6,000 kpa. The current average reservoir pressure is about 14,500 kpa in the high-pressure zones and 10,000 kpa in the low-pressure zones. The reservoir temperature is about 81°C. The field is divided into four areas based on old 2D seismic interpretation. These are shown in Figure 2 as follows:The Eastern Satellite Area The Eastern Flank Area The Main Area The South West Area The currently booked STOIIP is 249 Mm3 with the ultimate recovery factor of more than 25%. The crude density is 38° API with 1.2 cP viscosity. The average permeability is 20mD and the average porosity is about 20%. Cumulative oil production to date is about 41 Mm3. The current production of the field is typically 35,000 m3/d gross liquid rate and 4,500 m3/d net oil rate. Produced water from different areas is required to replace the voidage of the nearby Yibal field, which is the largest oil field in Oman.
Braas, J.C.M. (Petroleum Development Oman) | Aihevba, C.O. (Petroleum Development Oman) | Shandoodi, M. (Petroleum Development Oman) | Van Noort, R.H. (Shell International Exploration & Production) | Baaijens, M.N. (Shell International Exploration & Production)
Abstract Water production management starts to play a more important role as reservoirs mature. Production logging is required to identify watered out intervals in producers and thief zones in injectors. The interpretation of logs acquired in horizontal, barefoot wells in highly fractured, heterogeneous, carbonate reservoirs is challenging at least. Yet this technique has been successfully applied in Petroleum Development Oman (PDO) in the Yibal and Al Huwaisah fields (Fig. 1) and has lead to significant production improvements after the subsequent water shut off. Expandable Open Hole Clad (OHC) systems, with external seals, have been deployed to shut off water in both horizontal producers and injectors. The seal between the expanded pipe and the formation is further enhanced by elastomers with the ability to swell upon contact with formation fluids. Case histories are presented to demonstrate the viability of this new technology. Introduction As oil fields mature, production wells experience co-production of oil and water because of aquifer encroachment and/or water injection. Controlling the water production is one of the major challenges in reservoir management. Diagnosis of the zone of water influx in horizontal well bores, however, is not always straightforward and must certainly preceed any remedial water shut off treatments. This paper starts with a discussion on the water shut off technique using expandable tubulars, followed by two case histories in which more details are provided concerning production logging, expandable clad installation and production results. Technology Overview Previously published papers have discussed the concepts of Solid Expandable Tubular (SET) technology and the effect of the expansion process on the system's tubulars and connectors. The specific system used in PDO, with the required adaptations, will be reviewed in this paper. The basic principle is the down hole enlargement (expansion) of a solid pipe. Expansion is achieved with a cone that can either be pushed (typically by hydraulic force) or pulled through the pipe. SET can be applied for both well construction and remediation. Four general types of SET products can be identified:The Expandable Cased Hole Liner (CHL) is set in a cased hole environment and is typically used to isolate perforations or damaged or corroded casing. The Expandable Open Hole Liner (OHL) is used in the well bore construction process to provide an additional liner whilst minimizing Internal Diameter (ID) loss. This provides more options in the well design process to reach the required Total Depth (TD) without compromising hole size.
Abstract As the demand for natural Gas in the Sultanate Of Oman rises both internally through domestic and industrial growth, and externally through the LNG export, the development of more gas fields becomes a necessity. Being centrally located, close to existing central processing plant, and with considerable volume in place, the rich gas-condensate Saih Nihayda field, is seen as the next candidate for development. A full field model was built for Saih Nihayda to study uncertainties and investigate the optimum development option for the three deep stacked reservoirs. The hydrostatically pressured Barik sandstone being the shallowest and the most complex is a gas-condensate reservoir, whereas the Miqrat and the Amin sandstone are both over-pressured dry gas reservoirs. This paper details an integrated approach followed in assessing the impact of various uncertainties on development options. It highlights the modelling process from seismic inversion to demand driven forecasting and economic assessment. Special attention was paid to gas-condensate specific phenomena such as condensate impairment. Beside the high technical demand associated with understanding the physical behaviours of gas-condensate reservoirs, the variability in static and dynamic characteristics of the three Saih Nihayda sandstone reservoirs offers commercially challenging development options. Comparison studies included commingled reservoir production versus non-commingled and the impact of hydraulic fracturing versus non-fracturing on reduction in total well numbers and acceleration of early condensate. The paper touches on the benefit of variability in characteristics coupled with economical and technical viability on considering exotic development options like dump-flooding and gas recycling. Introduction The LNG upstream development project was started with the development of the Saih Rawl and Barik fields in Central Oman. Both fields came on stream mid 1999 when the Central Processing Plant (CPP) in Saih Rawl was ready to receive and treat the gas. Saih Nihayda field is deemed the next field in line to be developed, with an earliest start-up date of 1/10/2004. The first development wells for the field have to come on stream between 1/10/2004 and beginning 2005. The Saih Nihayda gas field is located some 300 km south of Muscat, the Capital, but only about 28 km east of the existing Saih Rawl CPP and some 20 km north-west of the Qarn Alam oil station. See Figure 1. The Saih Nihayda FDP work forms an integral part of the long term LNG Upstream development strategy. Following the identification of coming development requirement, the development of the field is looked at in enough detail to determine the most optimal development method and the most optimal drilling timing and sequence taking into account the field uncertainties. Quite distinc for Saih Nihyada (SN) is the presence of three stacked gas bearing sandstone reservoirs. The Barik sandstone at a depth of about 4050 mss, the Miqrat sandstone at a depth of about 4475 mss and the smaller Amin sandstone at a depth of about 4630 mss. The purpose of this paper is to highlight the effort made in underpinning the uncertainties and the risks associated with the development of these three reservoirs. In arriving to an optimal base case development, various development scenarios were investigated, taking advantage of the characteristics of these reservoirs and the characteristics of the hydrocarbon fluid that each one of them accommodate. All information from the appraisal over the last five years and analogues with the producing Saih Rawl and Barik fields have been included in this excersice. The Saih Nihayda field faces some challenges similar to the aforementioned Central Oman fields, in particular in the SN-Barik reservoir, but also some unique ones, like the possible water encroachment in all three reservoirs and the commingling of three reservoirs in single wells with different pressure regimes.
Summary Gas reserves sufficient for a major export scheme have been found in Central Oman. To support appraisal and development planning of the gas/condensate fields, a dedicated, multi-disciplinary study team comprising both surface and subsurface engineers was assembled. The team fostered a high level of awareness of cross-disciplinary needs and challenges, resulting in timely data acquisition and a good fit between the various work-activities. A field development plan was completed in March 1994. The foundation of the subsurface contributions was a suite of advanced full-field reservoir models which:–provided production and well requirement forecasts; –quantified the impact of uncertainties on field performance and project costs; –supported the appraisal campaign; -optimised the field development plan; –derived recovery factor ranges for reserves estimates. The models were constructed early during the study, initially using general data with large uncertainty ranges, and gradually refined using new appraisal data, ultimately resulting in more than twenty full scenarios, quantifying and ranking the remaining uncertainty ranges. Geological/petrophysical uncertainties were quantified using newly-developed, 3-D probabilistic modelling tools. An efficient computing environment allowed a large number of sensitivities to be run in a timely cost-effective manner. The models also investigated a key concern in gas/condensate fields: well impairment due to near-well condensate precipitation. Its impact was assessed using measured, capillary number-dependent, relative permeability curves. Well performance ranges were established on the basis of Equation of State single-well simulations, and translated into the volatile oil full-field models using pseudo relative permeability curves for the wells. The models used the sparse available data in an optimal way and, as part of the field development plan, sustained confidence in the reserves estimates and the project, which is currently in the project specification phase. Introduction Gas in Oman In 1989 a development well in the Saih Nihayda Field was deepened to approximately 4500 m. This well discovered gas and condensate, proving a major gas exploration play in the Ghaba salt basin of Central Oman. The follow up exploration campaign has so far resulted in several further commercial discoveries, located in the Barik and Saih Rawl fields (Figure 1). All discoveries are deep (4500 to 5500 m) low permeability (1 to 10 mD) sandstone reservoirs. With the new discoveries, Oman's gas reserves significantly exceed the foreseeable domestic requirements and this has opened up the possibility of a major gas export scheme: in mid-1992 an identification study for an LNG project started. Appraisal and Development Team The objectives of the upstream part of the study were:–to identify a technologically and economically feasible and optimised development concept; and –to quantify the range of gas and condensate reserves contained in the reservoirs. To execute the work, an appraisal and development team was set up. The team was multi-disciplinary at two levels. At the higher level, it contained facilities, pipeline, operations and subsurface engineers.