Ekofisk Field Research Articles

Facies Remolding in Allochthonous Chalk Packages, Ekofisk and Albuskjell Fields, North Sea: ABSTRACT

The Ekofish and Albuskjell fields in the Central Graben of the North Sea produce hydrocarbons from resedimented chalk reservoirs. Although the allochthonous nature of chalk in these fields has been recognized, the correlations of, and association between, allochthonous units has not been described. Core analysis of the Tor Formation (Maastrichtian) and the Ekofish Formation (Danian) reveals that slump deposits have been remolded into debris flows, ooze flows, and turbidites. Packages of allochthonous sediment were deposited in slope and base-of-slope environments. Two kinds of allochthonous packages occur. One package, 1-3-m thick, consists of a basal debris flow overlain by an ooze flow. The other package, 10-20-m thick, contains three units: a basal debris flow, an intermediate slump, and an overlying turbidite. Deposition of each type of package probably resulted from a single triggering event. Lateral changes in facies (increased convolution and decreased clastic content) and in type of deposit (slump or debris flow to ooze flow) within the packages resulted from differing degrees of deformation as the packages moved downslope. An increase in occurrence and angularity of chalk intraclasts, and in thickness of slump units from the Albuskjell field eastward to the Ekofisk field, suggest that the graben-bounding Hidra fault zonemore » (about 30 km away) is the source of the allochthonous deposits. Vertical changes in the type of allochthonous package (from debris and ooze flows upward to slumps and turbidites) reflect decreasing topographic relief along the fault escarpment as the graben filled. This model of vertical (basin shallowing) and lateral (downslope) facies changes allows correlation of allochthonous chalk units, which are excellent hydrocarbon reservoirs.« less

Distribution of In-Situ Stress and Natural Fractures in the Ekofisk Field, North Sea: Implications for Reservoir Permeability: ABSTRACT

Distribution of In-Situ Stress and Natural Fractures in the Ekofisk Field, North Sea: Implications for Reservoir Permeability: ABSTRACT

Subsidence due to oil/gas production : Christensen, S O; Janbu, N; Jones, M E Proc BOSS'88, Trondheim, June 1988V1, P143–157. Publ Trondheim, Tapir, 1988

This paper deals with the reasons for subsidence over oil and gas fields during the production period, and reviews the prerequisites for a priori predictions of subsidence for fields that are planned to be developed. Suggestions are also made for high-priority research projects to improve our capability for design predictions. The approaches suggested herein utilise basic concepts in mechanics and physics applied to porous, sedimentary soil-rock formations. It is believed that this classical approach has shed new light on the multiple mechanisms imbedded in the complex subsidence phenomena. The main ideas and suggestions herein are derived from studies of case records offshore, like the Ekofisk Field, and similar phenomenons onshore, like the Wilmington Oil Field in California, and the Wairakei Thermo Project in New Zealand.

Measurement of the (pressure, density, temperature) relation of Ekofisk natural gas in the temperature range from 273.15 to 323.15 K at pressures up to 8 MPa

Comprehensive ( p, ϱ, T) measurements on natural gas from the Ekofisk field (North Sea) have been carried out in the temperature range from 273.15 to 323.15 K at pressures up to 8 MPa. The accuracy of the density measurement itself is better than ±0.03 per cent or ±0.003 kg·m −3, whichever is greater. The total uncertainty of the density including the experimental uncertainties of the single measurements of p, ϱ, and T, and the uncertainty of the composition of the gas is less than ±0.1 per cent or less than ±0.003 kg·m −3, whichever is greater. Comparisons with experinental results of previous workers are presented. Furthermore, the new ( p, ϱ, T) values are compared with two current equations of state for natural gas and with a modified version of the AGA-NX-19 correlation method; the deviations range up to 0.2 per cent.

Compaction Monitoring in the Ekofisk Area Chalk Fields

In late Nov. 1984, the subsidence phenomenon was recognized in the Ekofisk field. To determine the magnitude and areal extent of the formation compaction, a program for measuring compaction with electric logging tools was initiated. Initial time-lapse surveys performed with cased-hole neutron tools indicated that reservoir compaction was occurring, but the accuracy of the determination of compaction rate was low. In addition to the cased-hole neutron survey, radioactive markers and a gamma ray (GR) detection tool were used to determine compaction rate in the reservoir more accurately and to determine whether compaction was occurring in the overburden. A program for implanting radioactive-marker bullets and subsequent monitoring with a four-detector GR tool was implemented. There are currently 13 wells equipped with radioactive markers in the compaction monitoring program. Compaction monitoring accuracy using the four-detector GR tool was found to depend on wellbore geometry, completion design, and radioactive-marker placement. This paper gives the results of the program to date and describes the operational procedures and analysis techniques used for compaction monitoring in the greater Ekofisk area chalk fields.

Reservoir Aspects of Ekofisk Subsidence

In Nov. 1984, Phillips Petroleum Co. discovered subsidence of the seabed overlying the Ekofisk oil reservoirs offshore Norway. This phenomenon is the result of the compaction of the porous chalk reservoirs and the transmission of this compaction through the overburden to the seafloor. This paper describes the geolgoic- and reservoir-related aspects of subsidence, including the mechanism leading to reservoir compaction and its effect on reservoir performance. The compaction of the Ekofisk reservoirs is shown to be a result of pore-pressure depletion. Although some of the compaction is elastic, the bulk results from plastic deformation (pore collapse) of high-porosity chalk. Reservoir compaction is shown to cause subsidence of the seabed through deformation of the overlying sediments. Reservoir compaction has also had a pressure-maintenance effect on the reservoir. Thus far, no loss in reservoir productivity has been observed. On the basis of analogy with the neighboring West Ekofisk field, no loss in reservoir productivity is anticipated, at least for the near future.

Rock Mechanics of the Ekofisk Reservoir in the Evaluation of Subsidence

Mechanical properties have been determined for Ekofisk reservoir rock for use in subsidence simulation. Tests were to describe the mechanical properties of the Ekofisk chalk for reservoir conditions. The mechanisms and time dependence of chalk compaction and the effect of waterflooding on chalk strength were also examined.

Casing Deformation in Ekofisk

Casing deformation resulting from reservoir compaction occurred in the Ekofisk field operated by Phillips Petroleum Co. Norway and is a serious problem in three of the fields. This study established a relationship between reservoir compaction and casing failure by statistical analyses, finite-element modeling (FEM), and the analyses of deformed casing and logs run through collapsed casings. Ekofisk casing deformation is related primarily to the near well incremental strain, well inclination, and casing diameter. Useful correlations to estimate future probabilities of casing deformation as a function of reservoir variables and well parameters were also obtained. The authors concluded that casing failure induced by reservoir compaction can be minimized through a pressure-maintenance program to reduce strain by drilling with the highest practical angle and by using the largest possible casing in the well.

Forecasting of Ekofisk Reservoir Compaction and Subsidence by Numerical Simulation

A finite-element computational procedure for simulating the reservoir compaction and subsidence processes at Ekofisk is described. Data input requirements are considered, and results are presented for selected reservoir management options. Field measurements of subsidence, subsidence rates, and subsidence-bowl profiles are shown to be in good agreement with calculated results.

Vertical isotopic variations in waters and carbonates from the Ekofisk field

Vertical isotopic variations in waters and carbonates from the Ekofisk field

EKOFISK PLATFORM 2/4C: RE-ANALYSIS DUE TO SUBSIDENCE.

The 2/4C platform is located near to the centre of the Ekofisk Field, and is a 12 legged fixed steel structure supporting drilling and production facilities. Because of a significant level of subsidence at Ekofisk is has meant that the platform be evaluated through structural analysis to determine the effects of the subsidence. This paper is concerned primarily with two aspects of the work carried our on the 2/4C platform. This covers model test results of wave action on the deck structure, followed by an elastic-plastic analysis of the deck structure when subjected to the high environmental forces due to wave action.

Use of Computers in the Operation of the Ekofisk Complex

Summary. The Greater Ekofisk complex consists of seven fields that produce into a central processing facility at Ekofisk Center, where gas and oil are separated. Gas is pipelined to Emden, West Germany, and oil is pipelined to Teesside, England. The complexity of the operations requires broad use of computers. This paper gives an overview of one of the most extensive systems of computer programs ever developed for operational assistance and reporting in offshore production of hydrocarbon reservoirs. Systems for the capture, concentration, storage, and retrieval of data are included, along with systems for simulating the surface facilities, for production allocation by component weights through C5+, for long-range production forecasting, and for operational and management reporting. Introduction Fields composing the Greater Ekofisk complex were discovered in the Norwegian Sector of the North Sea between 1968 and 1972. In order of discovery, these are Cod, Ekorisk, West Ekofisk, Tor, Eldfisk, Edda, and Albuskjell. The initial discoveries represented the first commercial oil fields found in the North Sea. Fig. 1 shows the Greater Ekofisk complex, Ekofisk and neighboring fields are located in the deepest part of the Tertiary basin in an area containing more than 1,350 ft [410 m] of Danian and Upper Paleocene sediments. About half of this interval consists of Danian and Upper Cretaceous chalk sections, and the other half is composed of Upper Paleocene clastics. The Danian and Upper Cretaceous chalks compose the primary hydrocarbon reservoirs in the Ekofisk, West Ekofisk, Tor, Edda, Eldfisk, and Albuskjell fields. In the Ekofisk area fields, an extensive fracture system extends both laterally and vertically in the chalk reservoirs. Oils are relatively volatile. with substantial variation in composition from field to field. Facilities for producing these fields were constructed in several stages. During the first phase, four Ekofisk wells were produced through separation facilities located on a jackup rig. Oil was loaded to tankers through a single-point mooring buoy. About 42,000 BOPD [6680 M 3 /d oil] was produced for 18 months in this manner. Associated gas was flared. The second phase consisted of installing three drilling platforms (two for production and one for gas reinjection and production), a field terminal platform, a four-story quarters platform, and a 1 × 106 -bbl [ 160 × 103-M3] concrete oil storage tank. Subsequent phases included construction of processing facilities at Ekofisk Center and gathering systems from the other fields as they were developed. A 36-in. [91.4-cm] pipeline 274 miles [441 km] long was constructed to transport gas to Emden, and a 34-in. [86.4-cm] pipeline 220 miles [354 km] long was constructed to transport oil to Teesside. A natural gas liquids (NGL) processing plant was built at Teesside to stabilize the oil and to extract ethane, commercial propane, isobutane, and commercial normal butane. The complexity of the operations made it obvious from a very early date that extensive use of computers would be required. A study was initiated in 1972 to determine computer hardware and software needed for Ekofisk operational reporting. The following major systems were found to be necessary.A system was needed to capture, to integrate, to store, and to retrieve data for metered flows. laboratory analyses, process conditions, valve status, well status, and other information required for day-today operating and reporting.A technical information system (TIS) was needed to produce operating and engineering reports from the data.A computer model simulating the surface facilities was needed to allow evaluation of changing field operations, changing process conditions, and proposed changes in operations.A means of allocating production from the various fields to the gas and oil product pipeline streams by components through C5+ was needed so that each field's light-component contribution to the gas and liquid streams would be properly credited.Long-range production forecasts for the Greater Ekorisk complex were needed, including compositional forecasts for each field and quantities and compositions of the Emden gas stream and the Teesside oil stream. These are not the only systems developed for use in operation of the Ekofisk complex. Many other programs, not discussed here, were later identified and developed. Capture and Initial Processing of Data Data are automatically obtained from a large number of points in the Ekofisk complex and at Teeside and Emden. JPT P. 809^

Ekofisk Waterflood Pilot

This paper describes the evaluation of a waterflood pilot in the highly fractured Maastrichtian reservoir of the Ekofisk field in the Norwegian sector of the North Sea. A four-well pilot consisting of one water injector and three producers was initiated in Spring 1981 and was concluded in mid-1984. A total of 21 x 10/sup 6/ bbl(3.3 x 10/sup 6/ m/sup 3/) of water was injected, and water breakthrough occurred in two of the production wells. Simulation of waterflood performance in the pilot was conducted with a three-dimensional (3D), three-phase dual-porosity model. Initial and boundary conditions were taken from a full 3D single-porosity model of the reservoir. The pilot was conducted to determine the following information for the Maastrichtian: water-cut performance vs. time, water imbibition characteristics, and anisotropy. Results from this work have been incorporated into a full-field waterflood study. Reservoir description included the determination of fractured areas, matrix block sizes, water/oil capillary imbibition, matrix permeability and porosity, and effective permeability. These data were derived from fracture core analysis, pressure transient tests, laboratory water/oil imbibition studies, repeat formation pressure test results, and open- and cased-hole logs. An excellent match of waterflood performance was obtained with the dual-porosity model. Of particular interestmore » are the imbibition characteristics of the Maastrichtian in the Ekofisk field and the character of the water-cut performance of the producing wells following injector shutdowns and startups.« less

The flow of water and displacement of hydrocarbons in fractured chalk reservoirs

Summary The fractured chalk reservoirs of the southern part of the Central Graben do not exhibit the flow characteristics more usually encountered in continuous sandstone formations. The Danian and Maastrichtian age formations of the Ekofisk Field are typical of these fractured chalk reservoirs. The Ekofisk Field has been extensively studied to understand better the geology and controlling fluid flow mechanisms prior to commencing enhanced oil recovery projects. During waterflooding the imbibition of water from the fracture network into the rock matrix will control the displacement of hydrocarbons. Extensive laboratory studies have been carried out to quantify the imbibition characteristics of the Danian and Maastrichtian formations. Several parameters that control the amount of water imbibed have been found. A field water-injection pilot project has been implemented to verify the mechanisms and laboratory results and to prove numerical techniques suitable for the prediction of recoveries under a full-field waterflood.

MONA, An Accurate Two-Phase Well Flow Model Based on Phase Slippage

Summary In two-phase flow, both holdup and pressure loss are related to interfacial slippage. A computation model based on phase slippage has been developed that allows a priori estimation of the slip parameter values. By parameter optimization, the accuracy of the model can be improved. The model was tested with production-well data from the Forties and the Ekofisk fields and flowline data from Prudhoe Bay. It was considerably more accurate than the standard models that were used for comparison.

The geology and geophysics of the Ekofisk Field waterflood

Successful waterflooding of Ekofisk Field will enhance recovery of the total oil-in-place, producing an extra 170 mm barrels of oil. Monitoring, matching and predicting the reservoir performance will be performed with a complex reservoir model of 7700 cells. The chalk reservoir sequence at Ekofisk is multilayered with each layer exhibiting distinct thickness, porosity, permeability and water saturation trends. The upper part of the Tor Formation is one of those layers with imbibition characteristics suitable for waterflooding. Overlying the Tor Formation is the Ekofisk Tight Zone, a thin layer of low but variable permeability and porosity which generally acts as an hydraulic barrier. This geological and geophysical model provides a data set for the required complex reservoir model.

The geology and geophysics of the Ekofisk field waterflood: Brewster, John, John Dangerfield and Helen Farrell, 1986. Mar. Petrol. Geol., 3(2):139–169. Elf Aquitaine Narge, P.O. Box 168, N-4001 Stavanger, Norway

The geology and geophysics of the Ekofisk field waterflood: Brewster, John, John Dangerfield and Helen Farrell, 1986. Mar. Petrol. Geol., 3(2):139–169. Elf Aquitaine Narge, P.O. Box 168, N-4001 Stavanger, Norway

Geology of the Edda Field Reservoir

The Edda Field, which was discovered in 1972, is located in the southern part of the Norwegian Sector of the North Sea. As in the nearby Ekofisk Field, chalk reservoir in the Danian (Lower Paleocene) and Maastrichtian (Upper Cretaceous) contain oil which originated in the Upper Jurassic organic rich shale sequence. A 15 slots drilling-production platform was installed on the basis of the results of 3 exploration appraisal wells. Seven producer wells were drilled and completed in 1979 and a production peak of about 33000 BOPD was reached in January 1980. All the development wells encountered less yield than expected and the 3 wells drilled on the southern flank of the structure were dry. Most of the characteristics of the chalk reservoir were known at that time but the existence of a pre-Maastrichtian paleo-relief in that area had not yet been established. This paleo-feature, the Lindesnes Ridge, strongly influenced the distribution and characteristics of the reservoir. Variation in initial porosity is the result of changes in sedimentation mode and rate as well as differential early cementation and mechanical compaction over the paleo-high. Differential porosity preservation is partly due to progressive infill of the trap by hydrocarbons but, as in most chalk fields, overpressure in the porous chalk layers was an important prerequisite.

The environmental impact assessment process for offshore oil and gas exploration and development in Norway

The appl ica t ion of environmental impact assessment (EIA) reflects the economic and political system of each country that uses it. Before present ing and discussing how EIAs are carried out in Norway, it is appropria te to first out l ine the Norwegian oil and gas s i tuat ion and the nai tonal policies regarding it. The history of Norway's pe t ro leum industry is brief. It started in 1962 when a mul t ina t iona l oil company approached the Norwegian Government with a request for sole rights to explore for and produce oil and gas on the Norwegian cont inental shelf. In 1963, Norway procla imed sovereignty over the cont inental shelf, and commenced seismic surveys of the North Sea basin. The first round of l icensing took place in 1965, when 278 blocks were pu t on bid. Of these, 70 were allocated to 22 licenses. The first field (Cod) was discovered in 1968, but it was not unt i l the Ekofisk Field was discovered in 1969 that the area was found to be commercial ly viable (Figures 1 and 2). T h e Frigg Field was discovered in 1971 in a block awarded in the second round. The Stat[jord Field blocks conta in ing both oil and gas were awarded i n 1973 after a discovery had been made in adjacent blocks on the British side of the North Sea. M o r e t h a n 400 wells have been drilled on the Norwegian Cont inental Shelf. Approximately three-quarters of these have been wildcat wells, the rest appraisal wells. The area currently under license to oil companies is about 2.7 mi l l ion ha (hectares) (January 1983). The current product ion of oil and gas in Norway is approximate ly 50 MTOE per year. Half of the produc t ion is oil, the other half gas. The ul t imately recoverable reserves of the Norwegian North Sea are estimated to be 4,700 MTOE, of which about 2,700 M T O E have already

Development and Achievements of a Computerized System for Inventory Control and Failure Analysis of Subsurface Safety Valves

Summary To improve safety and reduce costs of subsurface safety valve (SSSV) operations at Ekofisk, offshore Norway, a computer system was developed for inventory control and failure analysis. Improvements and identification of problem areas in SSSV operations have been realized from changes made problem areas in SSSV operations have been realized from changes made during development and use of the system. Introduction The Ekofisk field was discovered in the Norwegian sector of the North Sea in late 1969 by the Phillips Norway Group. This group is composed of Phillips Petroleum Co. Norway (PPCoN) (37%), Norske Agip A/S (30%), Norsk Phillips Petroleum Co. Norway (PPCoN) (37%), Norske Agip A/S (30%), Norsk Agip A/S (13%), and the Petronord Group (20%). A total of seven geologically separate fields have been developed in three phases with 11 producing and 11 support platforms as illustrated in Fig. 1. Greater Ekofisk was developed over a 10-year period, from discovery until the last platform came on production in 1979. There are a total of 118 producing wells, 6 gas-injection wells, and 1 water injection well. These wells were completed with several schemes utilizing mostly 4 1/2-in. [114-mm] tubing and some 3 1/2-in. [89-mm], 5-in. [127-mm] and 5 1/2-in. [140-mm] tubing. Wireline retrievable SSSV's are used as pall of the completion equipment in all Ekofisk wells. Many sizes and models of SSSV's were necessary because of the various completion types and sizes. SSSV Operations at Ekofisk SSSV assemblies at Ekofisk consist of a valve and lock, each having its own serial number. The lock and valve when considered separately have been defined within this paper as "devices." When the lock and valve are considered as an assembly, they will be referred to as an SSSV. Fifteen models of locks and valves in sizes of 3.68 in. [93.4 mm], 3.81 in. [96.8 mm], and 4.56 in. [115.8 mm] have been used. These devices are produced by three SSSV manufacturers. Ten of these models continue in use today. Surplus inventory must be maintained for each of the SSSV models in use. The total inventory of locks and valves is 460. Approximately 240 devices are in service in wells and 220 devices are required as spare inventory to ensure that a device will be available when a replacement is needed. An average of 450 SSSV's are run and pulled in wells each year at Ekofisk and as many as 90 replacements have occurred in 1 month. Reservoir pressure monitoring, production logging, tubing caliper inspection, and pressure monitoring, production logging, tubing caliper inspection, and other operations requiring wireline work below the SSSV cause most of the running and pulling of these SSSV's. Failures and malfunctions of SSSV's contribute to only 15 % of total replacements. SSSV's pulled from wells are transported to the onshore Norway base for repair. Many of the lock-and-valve combinations must be separated and sent to their respective repair shops, since the lock and valve of an assembly are not all from the same manufacturer. This requires separate tracking of the lock and valve. JPT p. 2301