Insights on Water Sources for Injection Development of Large Oilfields in Southeast Iraq and Appraisal of Paleogene Shallow Water Source Formation

2021 ◽  
Author(s):  
Guosheng Qin ◽  
Youjing Wang
Keyword(s):  
Shallow Water ◽  
Sequence Stratigraphy ◽  
Oil Recovery ◽  
Water Injection ◽  
Water Source ◽  
Water Volume ◽  
Preliminary Evaluation ◽  
Core Analysis ◽  
High Porosity ◽  
Enhance Oil Recovery

Abstract As many large oilfields in southeast Iraq entered the final stage of depletion development, water injection appears to be the most economical and technically feasible method to enhance oil recovery. Considering the shortage of freshwater and huge investment in seawater supply project, it is very important to appraise and optimize the favorable shallow water source formation to ensure sufficient water injection supply. Based on regional seismic, well data, core analysis and production test data, Paleogene sequence stratigraphy was determined by integrating well and seismic interpretation. Under framework of sequence stratigraphy, the sedimentary evolution of main water source formations was characterized. Subsequently, combined with core analysis and special logging data, the petrophysical characteristics of the formations were evaluated, and the volume of the regional water source was estimated. The research shows that: 1) Dammam limestone and Ghar sandstone are the two main Paleogene shallow water source formations; 2) Dammama developed carbonate shelf, from southwest to northeast, the formation thickness decrease with the sedimentary evolved from inner slope to out slope. Expose and dissolution increased the porosity which is favorable for water storage; 3) Ghar developed alluvial and delta, from southwest to northeast, the formation thickness increase with the sedimentary evolved from alluvial fan, alluvial river to delta. Delta developed abundant and unconsolidated sandstone with high porosity and permeability; 4) The water sample analysis showed the water belong to Cacl2 type with total dissolved solids greater than 250,000 ppm which indicated well sealing condition. Production tests have shown that both Dammam and Ghar have a water supply capacity of 8,000-10,000 barrels per day. The preliminary evaluation of the water volume in the Ghar area can up to 1 trillion barrels. Paleogene shallow water formation is currently the most realistic and economic water source choice for water injection to enhance oil recovery in large oil fields in southeastern Iraq. Dammam formation and Ghar formation of Paleogene had the characteristics of shallow buried, good water quality and sufficient reserves. Thus, they are the preferred target water source formations for injection development of large oilfields in southeastern Iraq.

scholarly journals Numerical Simulation of Two-Phase Flows in Heterogeneous Porous Media

2020 ◽  
Vol 21 (2) ◽  
pp. 339
Author(s):  
I. Carneiro ◽  
M. Borges ◽  
S. Malta
Keyword(s):  
Porous Media ◽  
Oil Recovery ◽  
Flow Behavior ◽  
Water Injection ◽  
Heterogeneous Porous Media ◽  
Flow In Porous Media ◽  
High Porosity ◽  
Two Phase ◽  
Recovery Method ◽  
Porosity And Permeability

In this work,we present three-dimensional numerical simulations of water-oil flow in porous media in order to analyze the influence of the heterogeneities in the porosity and permeability fields and, mainly, their relationships upon the phenomenon known in the literature as viscous fingering. For this, typical scenarios of heterogeneous reservoirs submitted to water injection (secondary recovery method) are considered. The results show that the porosity heterogeneities have a markable influence in the flow behavior when the permeability is closely related with porosity, for example, by the Kozeny-Carman (KC) relation.This kind of positive relation leads to a larger oil recovery, as the areas of high permeability(higher flow velocities) are associated with areas of high porosity (higher volume of pores), causing a delay in the breakthrough time. On the other hand, when both fields (porosity and permeability) are heterogeneous but independent of each other the influence of the porosity heterogeneities is smaller and may be negligible.

Reservoir Simulation Study on Air-Foam Flooding to Enhance Oil Recovery in Waterflooding Sandstone Reservoir

2014 ◽  
Vol 962-965 ◽  
pp. 461-464
Author(s):  
Ping Yuan
Keyword(s):  
Low Temperature ◽  
Oil Recovery ◽  
Water Injection ◽  
Steam Injection ◽  
Utilization Rate ◽  
Low Temperature Oxidation ◽  
Temperature Oxidation ◽  
Sandstone Reservoir ◽  
Foam Flooding ◽  
Enhance Oil Recovery

In the later waterflooding sandstone reservoir, there are many serious development contradictions, especially in the aspects of water breakthrough and heterogeneous development. Based on the laboratory experiments, numerical simulation research on historical match of the low temperature oxidation kinetics model, the injection mode, foaming agent concentration, gas to liquid ratio, steam injection rate and other key parameters of air-foam flooding were carried out. The results show that, air foam flooding technology integrated comprehensive effect of low-temperature oxidation, air flooding and foam flooding, which enhance oil recovery nearly 8% by block the thief layer effectively and improving the swept volume. Air-foam flooding technology also can reduce the amount of water injection and water production, which improved the utilization rate of water resources and reduced output liquid processing cost. This technology shows its broad prospect of application and can provide reference for similar reservoirs.

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 Field application of a modular multiple thermal fluid generator for heavy oil recovery

2021 ◽  
Author(s):  
Liguo Zhong ◽  
Cheng Wang ◽  
Yigang Liu ◽  
Wei Zhang ◽  
Xiaodong Han ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Fuel Injection ◽  
Water Injection ◽  
Oil Production ◽  
Field Application ◽  
Injection System ◽  
Water Volume ◽  
Oil Viscosity ◽  
Production Platform

AbstractA modular multiple thermal fluid generator is introduced to enhance heavy oil production, which consists of water treatment system, fuel injection system, air compressor, central burning and heat exchanging system, and measuring and controlling system. All the components are mounted in three separated light shelters, which are easy to be lifted and installed, especially on the offshore production platform. It could be operated under 350 ℃ and 20 MPa, and the temperature and GWR (ratio of the volume of gas to the equivalent water volume of steam under standard conditions) could be adjusted by the water injection rate under the given heating capability of the central burning chamber. The temperature of the generated fluid is usually 200–300 ℃ with GWR of 200–300 m3/m3. Compared to conventional steam generator, such compact multiple thermal fluid generator is easy to be installed on the offshore oil production platform, and the generated multiple thermal fluid is potential to enhance heavy oil production in mechanisms of reducing heavy oil viscosity by both heating and injected gas, enlarging the heating reservoir chamber, and pressure by injected gas. In the past 10 years, the multiple thermal fluid generator has been applied to more than 40 wells in Bohai Offshore Oilfield and Xinjiang Oilfield in cyclic multiple thermal fluid stimulation (CMTFS in short) process. As a result, the multiple thermal fluid generators were operated soundly, and the heavy oil production of these wells was enhanced remarkably. (The oil production rate was 2–3 times more than cold production.)

scholarly journals A laboratory approach to enhance oil recovery factor in a low permeable reservoir by active carbonated water injection

2021 ◽  
Vol 7 ◽  
pp. 3149-3155
Author(s):  
Xinxiao Chen ◽  
Aminsadegh Paprouschi ◽  
Marischa Elveny ◽  
Dmitriy Podoprigora ◽  
Grigory Korobov
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Recovery Factor ◽  
Carbonated Water Injection ◽  
Carbonated Water ◽  
Enhance Oil Recovery

Study on CO2 Injection for Enhancing the Oil Recovery at Gao89 Block in Shengli Oilfield

2013 ◽  
Vol 734-737 ◽  
pp. 1464-1467
Author(s):  
Song Lin Shi ◽  
Jian Kang ◽  
Meng Li
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Water Injection ◽  
Low Permeability ◽  
Recovery Method ◽  
Shengli Oilfield ◽  
Geological Features ◽  
Efficient Recovery ◽  
Original Production ◽  
Enhance Oil Recovery

Gao 89 Block is a low permeability oil reservoir. These reservoirs have difficulty in water injection, poor well condition, and low original production. Gas injection can solve this problem. It is the most efficient recovery method for low-permeability reservoirs at home and abroad. In accordance with the geological features and development actuality of Gao89 Block, the feasibility and optimization of gas injection are studied, the effect of gas injection on the development index and development results are demonstrated. The results indicate that the gas injection can dramatically enhance oil recovery and increase the oil production.

The Triangle "U" Sussex Unit - A Case History Comparing Two Chemical Enhanced Waterflood Methods

1998 ◽  
Vol 1 (06) ◽  
pp. 545-550 ◽  
Author(s):  
J.E. Smith ◽  
Dan Larsen
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Rocky Mountain ◽  
Water Source ◽  
Cationic Polymer ◽  
Injection Wells ◽  
Recovery Method ◽  
Secondary Recovery ◽  
Permeable Rock

Summary The Triangle "U" unit is located in Campbell County, Wyoming, in the Powder River basin. The field produces mainly from the Sussex A sandstone, with completions and limited production from the Sussex B. The flood recovered 12.8% original oil in place (OOIP) on primary before the waterflood, which began in March 1981. The Sussex A is relatively tight, with an average permeability of 15 md and porosity of 13.5%. The rock contains swelling and migrating clays, and the initial injection water source was fresh, leading to concerns about long-term injectivity. To stabilize clays, two different processes were applied. Earlier injection wells were treated with a combination of potassium chloride (KCl) and cationic polymer. Later injection wells were treated with potassium hydroxide (KOH). A recent comparison of long-term performance of the two groups of injection wells shows that the wells treated with KOH injected 476,437 bbls/porosity-ft more water than the wells treated with cationic polymer, in 1.4 years less time. This is an 83% increase in cumulative water injection. After KOH, all injection wells were put on a low concentration of imbibition agent to maximize in-depth penetration of water into low permeable rock. Cumulative oil recovery through March 1997 is 36.4% OOIP, compared to the original waterflood projection of 26.6% OOIP. A total of 37.7% pore volume (PV) water has been injected, and the water/oil ratio (WOR) is currently 0.71, for a fairly efficient flood in this tight, dirty sandstone. Introduction The Triangle "U" unit produced 12.8% OOIP on primary before initiation of a waterflood. Several methods of secondary recovery were considered for this reservoir. Gas injection was not feasible because of limited supplies, and micellar injection was too expensive and risky. Waterflood susceptibility testing in cores showed favorable displacement of oil by water, making this the most appropriate secondary recovery method. The waterflood was projected to recover an additional 13.8% OOIP. Polymer flooding was not considered, because the mobility ratio was favorable and the reservoir was relatively tight, with an average permeability of 15 md. There were two basic challenges to waterflooding. First, there was concern that clays would limit injectivity over time. Also, the rock exhibited a permeability variation of 0.65, which could lead to bypassing of recoverable oil as water tended to establish channels through more permeable rock. Clays can exacerbate channeling. SPE 53007 was revised for publication from paper SPE 39937, first presented at the 1998 SPE Rocky Mountain Regional/Low Permeability Reservoirs Symposium, Denver, Colorado, 5-8 April.

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.

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