The Douglas Oil Fields, Block 110/13b, East Irish Sea

2003 ◽  
Vol 20 (1) ◽  
pp. 61-75 ◽  
Author(s):  
A. Yaliz ◽  
N. McKim
Keyword(s):  
Sea Water ◽  
Water Injection ◽  
Oil Field ◽  
Irish Sea ◽  
High Porosity ◽  
Injection Wells ◽  
Depositional Processes ◽  
Sandstone Formation ◽  
Two Phases ◽  
And Migration

AbstractThe Douglas Field, on stream in February 1996, is the first oil field to be developed in the East Irish Sea Basin, with an estimated STOIIP of 202 MMBBL. The field structure consists of three tilted fault blocks formed during extensional faulting in Triassic-early Jurassic times, and later readjusted by contractional movements during Tertiary inversion. The oil is trapped in the Triassic Ormskirk Sandstone Formation, which comprises moderate to high porosity aeolian and fluvial sandstones. The reservoir depth is shallow (2140 ft) with a maximum oil column of 375 ft. The reservoir can be divided into several laterally extensive units based on vertical facies variations. The reservoir quality is principally controlled by primary depositional processes, and authigenic clay minerals are not important. However, bitumen is formed extensively in specific areas of the field causing significant permeability reduction. The hydrocarbon filling history of the field was complex, with the occurrence of at least two phases of oil generation and migration. The field contains a relatively 'dead' oil with a low GOR (170scf/bbl). Pressure maintenance is achieved through sea water injection, and to date ten production and six injection wells have been drilled. The crude is light (44° API) and contains high levels of H2S (0.5mol%) and mercaptans, which are removed during processing offshore.

The Hamilton and Hamilton North Gas Fields, Block 110/13a, East Irish Sea

2003 ◽  
Vol 20 (1) ◽  
pp. 77-86 ◽  
Author(s):  
A. Yaliz ◽  
P. Taylor
Keyword(s):  
Gas Production ◽  
Irish Sea ◽  
Hydrocarbon Generation ◽  
High Porosity ◽  
Water Contact ◽  
The North ◽  
Depositional Processes ◽  
Sandstone Formation ◽  
Two Phases ◽  
Water Cut

AbstractThe Hamilton and Hamilton North Fields are located in Block 110/13a in the East Irish Sea, and contain 627 BCF and 230 BCF GIIP, respectively. First gas was produced from the Hamilton North Field in December 1995. The fields are being developed with four producers in the Hamilton Field and three in the Hamilton North Field. The Hamilton Field structure consists of a N-S trending horst block with dip closure to the north and south, while the Hamilton North structure is defined by major faults to the north and west with dip closure to the east and south. The gas is trapped in the highly productive Triassic Ormskirk Sandstone Formation. The reservoir comprises high porosity aeolian and fluvial sandstones. Depth to reservoir is shallow (2300-2600 ft) with the gas-water contact being at 2910 ft in the Hamilton Field and 3166 ft in the Hamilton North Field. Reservoir quality is principally controlled by primary depositional processes and no significant diagenetic effects are observed. The hydrocarbon filling history was complex, with at least two phases of hydrocarbon generation. Hamilton North gas is sweet whereas the Hamilton gas contains up to 11OOppm H2S, which is removed during processing at the Douglas complex and at the Point of Ayr gas terminal. Cumulative gas production to May 1999 was 180 BCF and no water-cut has been observed to date.

AN ANALYSIS OF THE PRODUCTION PERFORMANCE OF THE WINDALIA SAND RESERVOIR OF THE BARROW ISLAND OIL FIELD

1977 ◽  
Vol 17 (1) ◽  
pp. 105 ◽  
Author(s):  
C. T. Williams
Keyword(s):  
Oil Recovery ◽  
History Matching ◽  
Water Injection ◽  
Feasibility Studies ◽  
Oil Field ◽  
Production Performance ◽  
High Porosity ◽  
Injection Wells ◽  
Well Completion ◽  
East West

The Windalia Sand is a high porosity, low permeability oil reservoir. Currently 454 wells penetrate the unit for production or water injection operations, and are drilled on a north-south, east-west 16 ha (40 ac.) spacing. Early production performance data indicated a trend of water break-through into wells located east and west of water injection wells in an inverted nine-spot pattern. This early trend has continued and the east- west break-through has become more widespread with time. It was recognised that it could be possible to improve the performance of the waterflood if the factors causing the phenomenon were able to be identified. A detailed geological review of well data was initiated to investigate causes and possible controls of the phenomenon and to determine if oil recovery could be improved. This work was augmented by an engineering study of production data. Subsequently, a computer model was developed to investigate the simulated effects of changes to well patterns on the field's production performance.The geological review determined that the reservoir contains significant local and transitional irregularities (or inhomogeneities). The mapping of a number of reservoir parameters has shown there are genetic patterns or trends and these are postulated as being at least partial controls of preferential direction of fluid movement.Previously the reservoir had been regarded as being a more uniform "layer-cake" sand. Well completion practices and timing together with production and injection methods are thought to have accentuated the latent genetic controls. Imposed pressure parting has been postulated, on engineering premises, as a control of fluid movement. The modelling study used the notion of anisotropic permeability in attempting to history-match production performances.Because of the reservoir size and anisotropy it was impractical to model the entire field. Selected type areas within the reservoir were studied. Good history-matching of various well types (based on location within a pattern) was possible. Predictions of production performance can be made for various simulated pattern changes allowing feasibility studies to be made of possible conversion programs.East-west producing wells are being converted to injectors as they water out. This program has converted part of the reservoir to a line-drive injection configuration and improved performance in these areas is evident.

The Lennox Field, Blocks 110/14c and 110/15a, UK East Irish Sea

2020 ◽  
Vol 52 (1) ◽  
pp. 320-333 ◽  
Author(s):  
J. Bunce
Keyword(s):  
Initial Conditions ◽  
Oil Production ◽  
Gas Production ◽  
Irish Sea ◽  
Second Phase ◽  
Injection Wells ◽  
Field Development ◽  
Production Wells ◽  
Sandstone Formation ◽  
Two Phases

AbstractThe Lennox Field is a saturated oilfield with a significant primary gas cap at initial conditions. Located in the East Irish Sea withincBlocks 110/14c and 110/15a, the field was discovered in 1992. First oil was achieved in February 1996. Lennox is a rollover anticline structure. The Triassic Ormskirk Sandstone Formation reservoir comprises good-quality aeolian and fluvial sandstones with typicalcporosities of 11–21%. The gas column reaches a height of c. 850 ft and overlays a 143 ft oil column. Oil initially-in-place is estimated to be 202 MMbbl, whilst total gas initially-in-place is 521 bcf. The field has been developed by a wellhead platform tied-back to the neighbouring Douglas Complex. The field development has been split into two phases: the first phase focused on oil production and involved the drilling of 12 horizontal and multilateral production wells and two gas injection wells. Oil production ceased in 2012 with total produced volumes of 103 MMbbl. The second phase comprised the gas cap blowdown, and the optimization of the existing well stock for gas production. Eni UK acquired the operatorship of the field in April 2014 and has focused on maximizing and accelerating gas production from the field.

The Lennox Oil and Gas Field, Block 110/15, East Irish Sea

2003 ◽  
Vol 20 (1) ◽  
pp. 87-96 ◽  
Author(s):  
A. Yaliz ◽  
T. Chapman
Keyword(s):  
Oil And Gas ◽  
Hanging Wall ◽  
Gas Production ◽  
Oil Field ◽  
Irish Sea ◽  
High Porosity ◽  
Gas Field ◽  
Blow Down ◽  
Depositional Processes ◽  
Oil Rim

AbstractThe Lennox Field, located in blocks 110/15 and 110/14, was the second oil field to be developed in the East Irish Sea Basin. It contains 184 MMBBL of oil in-place within a 143 ft thick oil rim overlain by a large gas cap up to 750 ft thick. The GIIP is estimated to be 497 BCF. The field came on stream in February 1996, and it is now being developed with seven horizontal oil producers, including two multi-lateral wells and two crestal gas injectors. Production from the field can be divided into two distinct phases; the oil rim development phase, and the gas cap blow-down phase. The latter phase is currently anticipated to commence in 2004. The field structure consists of a roll-over anticline formed in the hanging wall of the Formby Point Fault during extensional faulting in Triassic-early Jurassic times, and later readjusted by contractional movements during Tertiary inversion. The oil and gas are trapped in the highly productive Triassic Ormskirk Sandstone Formation. The reservoir comprise high porosity aeolian and fluvial sandstones occurring at a shallow depth (c. 2500 ft) with a maximum gas column of 750 ft above an oil rim of 143 ft. The reservoir quality is principally controlled by primary depositional processes as no significant adverse diagenetic effects are observed. The hydrocarbon filling history was complex, with at least three phases of oil and gas generation. The field contains a light, saturated oil (45° API) with a GOR of 650 SCF/BBL. The crude contains high levels of H2S (0.1 mol%) and mercaptans (450 ppm), which are removed during processing at the Douglas complex. Water cut from the field is currently around 2-5%, and no free gas production has been observed to date. Gas production from Lennox is anticipated to start in 2004.

Solubility Of Common Oil Field Scales Of Injection Water And High–barium Concentration And High–salinity Formation Water

2012 ◽  
Author(s):  
Amer Badr Merdhah ◽  
Abu Azam Mohd Yassin
Keyword(s):  
Oil And Gas ◽  
High Salinity ◽  
Sea Water ◽  
Water Injection ◽  
Gas Production ◽  
Oil Field ◽  
Formation Water ◽  
Oil And Gas Production ◽  
Barium Concentration ◽  
Injection Water

Kerak pemendapan merupakan satu daripada masalah paling penting dan serius dalam sistem suntikan air. Kerak kadangkala mengehadkan atau menghalang penghasilan gas dan minyak melalui penyumbatan matrik atau perpecahan pembentukan minyak dan jeda yang berlubang. Makalah ini mengetengahkan kesimpulan pengukuran makmal bagi kerak terbentuk di dalam keterlarutan medan minyak biasa dalam sintetik air masin (pembentukan air dan air laut) bagi pembentukan air yang mengandungi barium dan kandungan garam yang tinggi pada suhu 40 hingga 90°C pada tekanan atmosfera. Keputusan uji kaji mengesahkan pola kebergantungan keterlarutan bagi kerak medan minyak biasa pada keadaan ini. Pada suhu yang lebih tinggi, kerak bagi CaCO3, CaSO4, dan SrSO4 meningkat manakala kerak BaSO4 menurun disebabkan oleh keterlarutan CaCO3, CaSO4, dan SrSO4 menurun dan keterlarutan BaSO4 meningkat dengan kenaikan suhu. Kata kunci: Masalah pengskalaan; skala keterlarutan; paras kandungan garam tinggi; logam barium tinggi Scale deposition is one of the most important and serious problems which water injection systems are generally engaged in. Scale sometimes limits or blocks oil and gas production by plugging the oil–producing formation matrix or fractures and the perforated intervals. This paper presents a summary of the laboratory measurements of the solubility of common oil field scales in synthetic brines (formation water and sea water) of high–barium and high–salinity formation waters at 40 to 90°C and atmospheric pressure. The experimental results confirm the general trend in solubility dependencies for common oil field scales at these conditions. At higher temperatures the deposition of CaCO3, CaSO4 and SrSO4 scale increases and the deposition of BaSO4 scale decreases since the solubilities of CaCO3, CaSO4 and SrSO4 scales decreases and the solubility of BaSO4 increases with increasing temperature. Key words: Scaling problems; solubility of scale; high salinity; high barium

The Emerald Field, Blocks 2/10a, 2/15a, 3/11b, UK North Sea

1991 ◽  
Vol 14 (1) ◽  
pp. 111-116 ◽  
Author(s):  
D. M. Stewart ◽  
A. J. G. Faulkner
Keyword(s):  
North Sea ◽  
Water Injection ◽  
Maximum Flow ◽  
Oil Field ◽  
Injection Wells ◽  
Initial Development ◽  
Flexible Risers ◽  
Northern North Sea ◽  
The Uk ◽  
Gas Lift

AbstractThe Emerald Oil Field lies in Blocks 2/10a, 2/15a and 3/1 lb in the UK sector of the northern North Sea. The field is located on the 'Transitional Shelf, an area on the western flank of the Viking Graben, downfaulted from the East Shetland Platform. The first well was drilled on the structure in 1978. Subsequently, a further seven wells have been drilled to delineate the field.The Emerald Field is an elongate dip and fault closed structure subparallel to the local NW-SE regional structural trend. the 'Emerald Sandstone' forms the main reservoir of the field and comprises a homogeneous transgressive unit of Callovian to Bathonian age, undelain by tilted Precambrian and Devonian Basement Horst blocks. Sealing is provided by siltstones and shales of the overlying Healther and Kimmeridge Clay Formations. The reservoir lies at depths between 5150-5600 ft, and wells drilled to date have encountered pay thicknesses of 42-74 ft. Where the sandstone is hydrocarbon bearing, it has a 100% net/ gross ratio. Porosities average 28% and permeabilities lie in the range 0-1 to 1.3 darcies. Wireline and test data indicate that the field contains a continouous oil column of 200 ft. Three distinct structural culminations exist on and adjacent to the field, which give rise to three separate gas caps, centred around wells 2/10a-4, 2/10a-7 and 2/10a-6 The maximum flow rate achieved from the reservoir to date is 6822 BOPD of 24° API oil with a GOR of 300 SCF/STBBL. In-place hydrocarbons are estimated to be 216 MMBBL of oil and 61 BCF of gas, with an estimated 43 MMBBL of oil recoverable by the initial development plan. initial development drilling began in Spring 1989 and the development scheme will use a floating production system. Production to the facility, via flexible risers, is from seven pre-drilled deviated wells with gas lift. An additional four pre-drilled water injection wells will provide reservoir pressure support.

GEOLOGY OF BARROW ISLAND OIL FIELD

1973 ◽  
Vol 13 (1) ◽  
pp. 49 ◽  
Author(s):  
Keith Crank
Keyword(s):  
Oil And Gas ◽  
Water Injection ◽  
Water Source ◽  
Upper Jurassic ◽  
Oil Field ◽  
Late Triassic ◽  
Low Permeability ◽  
High Porosity ◽  
The South ◽  
The North

The Barrow Island oil field, which was discovered by the drilling of Barrow 1 in 1964, was declared commercial in 1966. Since then 520 wells have been drilled in the development of this field which has resulted in 309 Windalia Sand oil producers (from about 2200 feet), eight Muderong Greensand oil wells (2800 feet), five Neocomian/Upper Jurassic gas and oil producers (6200 to 6700 feet), eight Barrow Group water source wells and 157 water injection wells.Production averages 41,200 barrels of oil per day, and 98% of this comes from the shallow Windalia Sand Member of Cretaceous (Aptian to Albian) age. These reserves are contained in a broad north-plunging nose truncated to the south by a major down-to-the-south fault. The anticline is thought to have been formed initially from a basement uplift during Late Triassic to Early Jurassic time. Subsequent periods of deposition, uplift and erosion have continued into the Tertiary and modified the structure to its present form. The known sedimentary section on Barrow Island ranges from Late Jurassic to Miocene.The Neocomian/Jurassic accumulations are small and irregular and are not thought to be commercial in themselves. The Muderong Greensand pool is also a limited, low permeability reservoir. Migration of hydrocarbons is thought to have occurred mainly in the Tertiary as major arching did not take place until very late in the Cretaceous or early in the Palaeocene.The Windalia Sand reservoir is a high porosity, low permeability sand which is found only on Barrow Island. One of the most unusual features of this reservoir is the presence of a perched gas cap. Apparently the entire sand was originally saturated with oil, and gas subsequently moved upstructure from the north, displacing it. This movement was probably obstructed by randomly-located permeability barriers.

scholarly journals Shale volume and permeability of the Miocene unconsolidated turbidite sands of Bonga oil field, Niger delta, Nigeria

2017 ◽  
Vol 5 (1) ◽  
pp. 37 ◽  
Author(s):  
Inyang Namdie ◽  
Idara Akpabio ◽  
Agbasi Okechukwu .E.
Keyword(s):  
Niger Delta ◽  
Gamma Ray ◽  
Water Saturation ◽  
Strong Dependence ◽  
Water Injection ◽  
Oil Field ◽  
Reservoir Properties ◽  
Injection Wells ◽  
Log Data ◽  
Shale Volume

Bonga oil field is located 120km (75mi) southeast of the Niger Delta, Nigeria. It is a subsea type development located about 3500ft water depth and has produced over 330 mmstb of hydrocarbon till date with over 16 oil producing and water injection wells. The producing formation is the Middle to Late Miocene unconsolidated turbidite sandstones with lateral and vertical homogeneities in reservoir properties. This work, analysis the petrophysical properties of the reservoir units for the purpose of modeling the effect of shale content on permeability in the reservoir. Turbidite sandstones are identified by gamma-ray log signatures as intervals with 26-50 API, while sonic, neutron, resistivity, caliper and other log data are applied to estimate volume of shale ranging between 0.972 v/v for shale intervals and 0.0549 v/v for turbidite sands, water saturation of 0.34 v/v average in most sand intervals, porosity range from 0.010 for shale intervals to 0.49 v/v for clean sands and permeability values for the send interval 11.46 to2634mD, for intervals between 7100 to 9100 ft., Data were analyzed using the Interactive Petrophysical software that splits the whole curve into sand and shale zones and estimates among other petrophysical parameters the shale contents of the prospective zones. While Seismic data revealed reservoir thickness ranging from 25ft to over 140ft well log data within the five wells have identified sands of similar thickness and estimated average permeability of700mD. Within the sand units across the five wells, cross plots of estimated porosity, volume of shale and permeability values reveal strong dependence of permeability on shale volume and a general decrease in permeability in intervals with shale volume. It is concluded that sand units with high shale contents that are from0.500 to0.900v/v will not provide good quality reservoir in the field.

scholarly journals Design method and application of accurate adjustment scheme for water injection wells around adjustment wells

2021 ◽  
Author(s):  
Tongchun Hao ◽  
Liguo Zhong ◽  
Jianbin Liu ◽  
Xiaodong Han ◽  
Tianyin Zhu ◽  
...  
Keyword(s):  
Production Efficiency ◽  
Design Method ◽  
Water Injection ◽  
Oil Field ◽  
Productivity Index ◽  
Injection Wells ◽  
Wellhead Pressure ◽  
Production Wells ◽  
Drilling Operations ◽  
The Impact

AbstractAffected by the surrounding injection and production wells, the formation near the infill adjustment well is in an abnormal pressure state, and drilling and completion operations are prone to complex situations and accidents such as leakage and overflow. The conventional shut-in method is to close all water injection wells around the adjustment well to ensure the safety of the operation, but at the same time reduce the oil field production. This paper proposes a design method for shut-in of water injection wells around adjustment wells based on injection-production data mining. This method uses water injection index and liquid productivity index as target parameters to analyze the correlation between injection and production wells. Select water injection wells with a high correlation and combine other parameters such as wellhead pressure and pressure recovery speed to design accurate adjustment schemes. Low-correlation wells do not take shut-in measures. This method was applied to 20 infill adjustment wells in the Penglai Oilfield. The correlation between injection and production wells was calculated using the data more than 500 injection wells and production wells. After a single adjustment well is drilled, the surrounding injection wells can increase the water injection volume by more than 5000 m3. This method achieves accurate adjustment for water injection wells that are high correlated with the adjustment well. Under the premise of ensuring the safety of drilling operations, the impact of drilling and completion on oilfield development is minimized, and oilfield production efficiency is improved. It has good application and promotion value.

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