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Abstract Today, Statoil has a number of subsea wells in production, has several ongoing projects, and has a number of promising prospects where the use of subsea wells will be essential for an economical sound development. These fields range from the development of the Norwegian Asgard and Gullfaks Satellite fields which include a large number of wells, complex reservoirs, and have a long field life, to small international fields like the Lufeng (offshore China) and Connemara (offshore Ireland) fields which include few wells, have a short field life, amd are very marginal developments. The paper reviews Statoil's and KOS's experience and ongoing work with subsea production systems, and address strategic activities taken to cover needs related to the development of smaller fields in the coming five year period. The paper focuses on the preparations which Statoil and KOS/FMC have undertaken to enable fast-track field developments. Essential in this is to remove the delivery of the subsea Xmas trees and other long lead items from the critical line of a field development. Flexibility and standardisation are key issues and the paper outlines how Statoil and KOS/FMC have focused on these when establishing low cost building blocks for international fast-track developments. The paper decribes how building blocks have been developed; both for the marginal subsea developments where low expenditure and risk are more important than maximising system availability, and for subsea developments with enough recoverable reserves to allow oil production to be optimised and the recovery factor to be maximised to a larger extent. The paper concludes that it is essential to undertake the preparatory work which is outlined in this paper in order to be able to improve cost efficiency and further reduce cost per barrel produced. Introduction Statoil has completed or placed equipment orders for about 150 subsea wells since Statoil completed its first subsea well on the Gullfaks field 11 years ago. Most of these wells are located in Norwegian waters. The use of subsea wells as the primary method of producing hydrocarbons has had its final breakthrough on the Norwegian shelf through the large developments Asgard/ Gullfaks Satellites (Operator Statoil) and Troll Oil (Operator Norsk Hydro). Here it has been essential to maximise oil recovery from complex reservoirs. There will be an increasing need for a cost efficient method to develop smaller, very often marginal fields which typically has a short field life and recoverable reserves in the order of 5 - 15 million Sm in the future. These smaller fields may be marginal for different reasons, but common for them all could be the method of development and the need to find internationally competitive solutions. The simple conclusion is that standardisation to international suppliers standard products and establishment of a close relationship with a few key contractors through frame contracts could give both fit for purpose low cost equipment and arrangements for short delivery times which would enable fast-tract developments. Definition of Subsea Systems and Cost Driving Factors Review of Statoil field development experience. KOS/FMC has become Statoil's main supplier of subsea production stations.
- Europe > Norway > North Sea > Northern North Sea (0.24)
- North America > United States > Texas > Kleberg County (0.24)
- North America > United States > Texas > Chambers County (0.24)
- Europe > Norway > Norwegian Sea > Halten Terrace > PL 128 > Block 6608/10 > Norne Field > Tofte Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > PL 128 > Block 6608/10 > Norne Field > Not Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > PL 128 > Block 6608/10 > Norne Field > Ile Formation (0.99)
- (56 more...)
Abstract A mathematical procedure for finding the most profitable gas field production policy to meet a gas profitable gas field production policy to meet a gas sales contract has been developed. Results indicate profits can be increased through combinations of profits can be increased through combinations of earlier liquids production, increased gas recovery, and investment reduction. The optimal plan for operating a gas field is found by applying nonlinear programming to the over-all problem o production programming to the over-all problem o production rate scheduling. Risk is accounted for by specifying that any investment yield some minimum incremental profit-to-investment ratio. Computed results, an profit-to-investment ratio. Computed results, an illustrated by several example problems, include average and peak production rate schedules for each reservoir, well-drilling schedules in each reservoirs, a list of recompletions, and compression purchases for the field. Compression can be assigned purchases for the field. Compression can be assigned to each reservoir or it can be pooled in the field.Dynamic programming is used to find the best investment schedule in each reservoir. Each gas reservoir is assumed to have a uniform pressure distribution throughout. Water influx is described by the van Everdingen-Hurst analytic solution for a radial aquifer. In each reservoir, one set of gas-well deliverability curves for production to four delivery pressures is employed, and in-place facilities are always operated to minimize compression requirements. THE SINGLE-RESERVOIR PROBLEM We shall solve the following optimization problem for a single gas reservoir: Given a desired gas delivery schedule and a specified peak delivery capability, find the optimal schedule for drilling new wells, the optimal plan for installing compressor horsepower, a detailed operating plan, and the total discounted profit for the best policy. We make the following assumptions in the analysis. 1. Pressure is uniform throughout the reservoir. This implies that well location is immaterial. 2. A single set of well deliverability curves is adequate. 3. The unsteady-state water influx equations satisfactorily describe aquifer behavior. 4. The optimum policy can be broken into two stages. In the first period, desired peak delivery capability is maintained through the addition of wells and compressive horsepower In the second period no new wells are drilled and no compression period no new wells are drilled and no compression is added; the reservoir flow rate declines. THE MATHEMATICAL MODEL THE RESERVOIR The gas reservoir is taken to be a tank with a uniform pressure throughout. Water influx is included. A material balance relating reservoir pressure, gas production, and water influx is where P/z = pressure/compressibility P/z = pressure/compressibility (P/z)i = pressure/compressibility at start Gp = fraction of original gas in place that hasbeen produced = Gp/G We = reservoir hydrocarbon pore volumes ofwater influx = We/(Bgi G) Water influx into the reservoir is described using the unsteady-state water influx equation for a radial aquifer: where (3) and h = net thickness of formation, ft phi = aquifer porosity, fraction phi = aquifer porosity, fraction cf+w = rock plus water compressibility, psi rR = effective reservoir radius, ft fR = fraction of reservoir periphery in contactwith aquifer SPEJ P. 279
Abstract. Demand for natural gas in Europe is expected to grow substantially in the coming years. The expected growth in demand is driven by increasing environmental awareness and technological improvement in the electricity sector. The demand growth takes piace in an environment of regulatory uncertainty and expected low oil prices. How will the industry respond? What will be Norway's role? 1. GAS DEMAND IN EUROPE, EXPECTED DEVELOPMENT In 1992 natural gas demand in Europe, defined as Western Europe plus Poland, Hungary and The Czech and Slovak Republics, amounted to 320 BCM. The demand may by 2010 reach as much as 520 BCM/yr. See Chart 1. If we exclude Hungary, Italy and Spain a market remains that potentially could be economically reached from Norway. By 2010 the total demand in this area may have grown from today's level of 250 BCM/yr to about 360 BCM/yr. The total gas demand in markets in North West Europe constitutes about 240 BCM/yr. By 2010 the total demand in this area may reach around 300 BCM/yr. Our forecasts are based on the following assumptions:โGDP growth of 2โ3% annually. โConstant energy prices, corresponding to an oil price of U.S.$20/barrel in 93-prices. โGas prices remaining competitive towards alternatives. As Chart 2 shows a substantial share of demand growth in the coming years will take place in the power sector. The expected growth in the power sector is chiefly based on growing environmental concern and the application of new technologies, such as combined cycles. The structure of energy input into power production has changed considerably during the past 30 years. In the 1960s coal was the dominating fuel, except in some countries rich in hydro power, like for instance Norway. In the 1960s oil entered this sector with success, but after two oil price shocks in the 1970s oil has lost ground and in some countries it has almost entirely been replaced by other fuels. The market share of natural gas in the power sector increased from about 1% in 1965 to 10% in 1975 (OECD-Europe). Thereafter also gas lost ground. This was a consequence of the fact that gas prices I Chart 1. Natural gas demand in countries in Europe. I Proceedings of the 14th World Petroleum Congress 0 1994 The Executive Board of the World Petroleum Congress Published by John Wiley & Sons BCM 500 Mo 5w COMMERCIAL POWERGENERATION 200 I I Chart 2. Demand for natural gas in European countriesby sector. 575 576 SUPPLY AND DEMAND [I 613 Conventinal coal plant 1 Invest./kw Coal I USD 1,350 Natural gas ] USD 71 O mostly were indexed to oil prices. Additionally Chart 3 is based on new coal gasification technatural gas was regarded to be a 'premium fuel', and nology which is known today. Tomorrow's tech-EC introduced a direct
- Europe > Norway (1.00)
- Africa > Middle East > Algeria (0.16)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Sognefjord Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Heather Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Fensfjord Formation (0.99)
- (15 more...)
- Health, Safety, Environment & Sustainability > Environment (1.00)
- Facilities Design, Construction and Operation > Natural Gas Conversion and Storage > Compressed natural gas (CNG) (0.56)
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (0.47)
This paper examines the environment in which improvements in ship construction can occur and looks at the type of planning that must be done to ensure benefits are realized. The Navy is now the major customer of the U.S. shipbuilding industry, and even with the increased emphasis on competitive procurement, by necessity, contracts for a significant amount of sole-source ship construction will exist due to technical or facility constraints. For these contracts, as well as many others, the shipbuilder has a limited incentive to accept the increases in risk inherent in changing his business strategy and existing industrial processes. Recognizing this problem, the Navy began, successfully, to change the environment for aircraft carrier construction. This paper describes the Navy's efforts.
- Shipbuilding (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- Government > Military > Navy (1.00)
- Energy > Oil & Gas (0.95)
- Management (0.47)
- Facilities Design, Construction and Operation (0.47)
Abstract Accurate measurement of steam quality and enthalpy delivery rate at the wellhead is required for efficient operation and reliable evaluation of enhanced recovery projects that utilize steam injection. Steam distribution through manifolds and tees can lead to uneven splitting and a wide variation of steam quality and enthalpy delivery rate for different wells fed from the same boiler. A field-grade densitometer, which is based on the principle of thermal neutron transmission, has been principle of thermal neutron transmission, has been developed and tested for measurement of steam quality at the wellhead. The meter is non intrusive, portable, robust, easy to operate, safe for field use and accurate. By combining the meter with a flow measuring device, such as a flow nozzle, accurate measurements of steam quality, mass flow rate and enthalpy delivery rate at the well-head are possible. This paper describes the densitometer's principle of operation and results from recent principle of operation and results from recent calibration tests conducted over a wide range of field conditions. Introduction In most enhanced recovery projects, steam is injected simultaneously into several wells through a distribution system. Steam from the generator facility is typically 80% quality. This steam is eventually split to feed individual pads, and then split again at the pad to feed individual wells. Depending on the mass flow rate, flow regime, steam quality and Junction geometry, steam splitting can be extremely uneven and difficult to predict. For example, in a given field in Cold Lake, Alberta, a pad-to-pad steam quality variation between 53% and 90% was reported. Also, for a pad with an input quality of 80%, the well-to-well variation was between 40% and 95%. This wide variation in wellhead steam quality, if not detected, results in inefficient energy management and unreliable evaluation of steam performance. Basic evaluation of well performance after steam injection consists of comparing the oil production to energy input. The energy input is production to energy input. The energy input is determined from the wellhead enthalpy delivery rate, which is derived from the pressure, mass flow rate and steam quality. In many fields, flow nozzles are used to measure enthalpy delivery rate by assuming a steam quality of 80%. For this procedure the steam quality remains unknown. procedure the steam quality remains unknown. However, some displacement mechanisms are sensitive to steam quality Therefore, a knowledge of enthalpy delivery rate without knowledge of steam quality is not adequate for reliable evaluation of well performance. Also, for steam additives that are contained in one of the two phases, measurement of wellhead steam quality is required for monitoring additive delivery rates and, thus, for evaluating performance with additives. Over the past four years Atomic Energy of Canada Ltd. (AECL), Intevep of Venezuela and Petro-Canada have jointly developed a neutron Petro-Canada have jointly developed a neutron densitometer for field measurement of wellhead steam quality. An initial feasibility study showed that thermal neutron attenuation could give a direct measure of the average density or void fraction of wet steam. Development proceeded on the assumption that steam quality could be derived from an appropriate slip correlation or by direct calibration at field conditions. A laboratory prototype was constructed and tested on 3-inch, schedule-160 pipe sections under field conditions at the Sheridan Park Engineering Laboratory of AECL in Mississauga, Park Engineering Laboratory of AECL in Mississauga, Ontario, Canada. The results were extremely encouraging. This initial success led to the design and construction of three field-grade meters. The design criteria were that the meter should be non-intrusive, robust, portable, easy to operate, safe for field use and accurate over a wide range of field conditions. P. 353
- North America > United States (1.00)
- North America > Canada > Alberta (0.34)
- North America > Canada > Ontario (0.24)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Downhole and wellsite flow metering (1.00)