Maximizing Recovery from a Depleted Oil Rim Carbonate Reservoir Through an Integrated FDP Approach: Case Study Onshore Field Abu Dhabi, UAE

2021 ◽  
Author(s):  
Magdy Farouk Fathalla ◽  
Mariam Ahmed Al Hosani ◽  
Ihab Nabil Mohamed ◽  
Ahmed Mohamed Al Bairaq ◽  
Aditya Ojha ◽  
...  
Keyword(s):  
Water Injection ◽  
Primary Objective ◽  
Carbonate Reservoir ◽  
Full Field ◽  
Water Breakthrough ◽  
Artificial Lift ◽  
Reservoir Simulation Model ◽  
Oil Rim ◽  
Project Objectives ◽  
Gas Lift

Abstract This paper examines risk and rewards of co-development of giant reservoir has gas cap concurrently produce with oil rim. The study focus mainly on the subsurface aspects of developing the oil rim with gas cap and impact recoveries on both the oil rim and gas cap. The primary objective of the project was to propose options to develop oil rims and gas cap reservoir aiming to maximize the recovery while ensuring that the gas and condensate production to the network are not jeopardized and the existing facility constraints are accounted. Below are the specific project objectives for each of the reservoirs: To evaluate the heterogeneities of the reservoir using available surveillance information data.To evaluate the reservoir physics and define the depleted oil rims current Gas oil contact and Water Oil Contact using the available surveillance information and plan mitigate reservoir management plan.To propose strategies in co-development plan with increase in oil rim recovery without impact on gas cap recovery.To propose the optimum Artificial methods to extended wells life by minimize the drawn down and reduce bottom head pressure.To propose methods to reduce the well head pressure to reduce back pressure on the wells. The methodology adopted in this study is based on the existing full field compositional reservoir simulation model for proposing different strategical co-development scenario: Auto gas lift Pilot implementation phase.Reactivate using Auto gas lift all the in-active wells.Propose the optimum wells drilling and completion design, like MRC, ERD and using ICV to control water and gas breakthrough.Proposing different field oil production plateauPropose different water injection scheme The study preliminary findings that extended reach drilling (ERD) wells were proposed, The ability to control gas and water breakthrough along the production section will be handled very well by deploying the advanced flow control valves, reactivation of existing Oil rim wells with Artificial lift increases Oil Rim recovery factor, and optimize offtake of gas cap and oil rim is crucial for increase the recovery factories of oil Rim and gas cap.

The Auk Field, Block 30/16, UK North Sea

2003 ◽  
Vol 20 (1) ◽  
pp. 483-496 ◽  
Author(s):  
Nigel H. Trewin ◽  
Steven G. Fryberger ◽  
Helge Kreutz
Keyword(s):  
Lower Cretaceous ◽  
Upper Cretaceous ◽  
Cross Flow ◽  
Full Field ◽  
Western Margin ◽  
Reservoir Architecture ◽  
The North ◽  
Water Breakthrough ◽  
Artificial Lift ◽  
Year 2000

AbstractThe Auk Field is located in Block 30/16 at the western margin of the Central Graben. Block 30/16 was awarded in June 1970 to Shell/Esso, and the discovery well 30/16-1 spudded in September 1970. The well found oil in a complex horst block sealed by Upper Cretaceous chalk and Tertiary claystones. The field contained an original oil column of up to 400 ft within Rotliegend sandstones, Zechstein dolomites, Lower Cretaceous breccia and Upper Cretaceous chalk. Production by natural aquifer drive commenced from a steel platform in 1976, initially from the Zechstein carbonates and now predominantly from the Rotliegend sandstone. Artificial lift was installed in 1988 helping to maintain production at economic levels past the year 2000. A complex reservoir architecture with cross flow between the Rotliegend and Zechstein reservoirs, a strong aquifer causing early water breakthrough via faults, and a limited seismic definition led to significant production variations from the initial forecasts. Equally important for the field, horizontal well technology opened up additional reserves and accelerated production from the complex Rotliegend reservoir; the most recent volumetric estimate for the total field predicts an ultimate recovery of 151 MMBBL for the existing wells from a STOIIP of 795 MMBBL. Full field reservoir simulation and 3D seismic data acquisition took place since mid 1980s but only recently resulted in a satisfactory understanding of the reservoir behaviour.The field is situated about 270 km ESE from Aberdeen in 240-270 ft of water. It covers a tilted horst block with an area of 65 km2, located at the western margin of the Central Graben. The Auk horst is bounded on the west by a series of faults with throws of up to 1000 ft, the eastern boundary fault has a throw of 5000 ft in the north reducing in throw southwards. The best reservoir lithology in the Zechstein is a vuggy fractured dolomite, and in the Rotliegend dune slipface sandstones provide the majority of the production. Both reservoirs and the overlying Lower Cretaceous breccia shared a common FWL at 7750 ft TVDss. The 38° API oil with a GOR of 190 SCF/STB was sourced from organic-rich Kimmeridge Clay.

Interpretation of Immiscible WAG Repeat Pressure-Falloff Tests

2011 ◽  
Vol 14 (06) ◽  
pp. 687-701 ◽  
Author(s):  
B.A.. A. Stenger ◽  
S.A.. A. Al-Kendi ◽  
A.F.. F. Al-Ameri ◽  
A.B.. B. Al-Katheeri
Keyword(s):  
Water Injection ◽  
Carbonate Reservoir ◽  
Mobility Control ◽  
Reservoir Properties ◽  
Injection Wells ◽  
Pressure Derivative ◽  
Full Field ◽  
Field Development ◽  
Phase Mobility ◽  
Injection Cycle

Summary This paper reviewed the interpretation of repeat pressure-falloff (PFO) tests acquired in two vertical pattern injectors operating in a carbonate reservoir undergoing full-field development. Enhanced vertical-sweep conformance through phase mobility control in the presence of strong reservoir heterogeneity was the major expected benefit from an immiscible water-alternating-gas (WAG) displacement mechanism. PFO tests were carried out during the monophasic injection phase to determine well injectivity and reservoir properties, and were subsequently acquired at the end of each 3-month injection cycle. Analytical falloff-test interpretation relied on the use of the two zone radial composite model. Multiple falloff-test interpretations indicated that the two pattern vertical injectors behaved differently even though both had been fractured. The difference in behavior was linked to different perforated intervals and reservoir properties. Gas- and water-injection rates were showing differences between both pattern injectors as a consequence. Injected gas banks had a small inner radius and were almost undetectable at the end of the subsequent water cycle. Changes in the pressure-derivative slope at the end of the subsequent water-injection cycle indicated most likely the creation of an effective mixing zone of injected gas and water in the reservoir. Numerical finite-volume simulation was required to account for potential injected-fluid segregation and the heterogeneous multilayered nature of the reservoir. Repeat saturation logs acquired in observation wells monitored the saturation distribution away from the injection wells. Fluid saturations derived from the simulation model were showing a good agreement with the analytical results in general, although the need to account for gas trapping was confirmed. Eight planned development WAG injectors were repositioned as a consequence of WAG 1 and WAG 2 pattern performance.

Achieving Productivity and Clean Inflow from an Unconventional Reservoir in North Kuwait

2022 ◽  
Author(s):  
Zamzam Mohammed Ahmed ◽  
Abrar Mohammed Salem ◽  
Liu Pei Wu ◽  
Benjamin Mowad
Keyword(s):  
Particulate Material ◽  
Primary Objective ◽  
Carbonate Reservoir ◽  
Hydraulic Fractures ◽  
Full Field ◽  
Fully Integrated ◽  
New Era ◽  
Field Development ◽  
Shale Reservoirs ◽  
Rock Mechanical Properties

Abstract Jurassic Kerogen shale/carbonate reservoir in North Kuwait provides the same challenges as North American shales in addition to ones not yet comparable to any other analogue reservoir globally. It is the Kerogen's resource density; however, that makes this play so attractive. Like ‘conventional’ unconventional in the US and Canada this kerogen is believed to be a source rock and is on the order of micro-to nano-Darcy permeability. As such, industry learnings show that likely long horizontal laterals with multiple hydraulic fractures will be necessary to make commercial wells. Following this premise, the immediate objective is to establish clean inflow into wellbore as the previous attempts to appraise failed due to "creep" of particulate material and formation flowing into the wellbore. Achieving this milestone will confirm that this formation is capable of solids free inflow and will open a new era in unconventional in Kuwait. Planning for success, the secondary objective is to then upscale to full field development. The main uncertainties lie in both producibility and ‘frac-ability’, and certainly, these challenges are not trivial. A fully integrated testing program was applied to both better understand the rock mechanical properties and to land on an effective frac design. Scratch, unconfined stress, proppant embedment and fluid compatibility tests were conducted on full core samples for geo-mechanics to prepare a suite of strength measurements ahead of frac design and to custom-design the fracture treatment and "controlled" flowback programs to establish inflow from Kerogen without "creep". Unlike developed shale reservoirs, the Jurassic Kerogen tends to become unconsolidated when treated. The pre-frac geomechanics tests will be outlined in this paper with the primary objective of finding the most competent reservoir unit to select the limited perforation interval to frac through so that formation competency can be maintained. Previous attempts failed to maintain a competent rock matrix even only after pumping data-fracs. Acidizing treatments also turn the treated rock volume into sludgy material with no in-situ stability nor ability to deliver "clean inflow". A propped fracturing treatment with resin-coated bauxite was successfully placed in December 2019 in a vertical appraisal well perforated over 6 ft at 12 spf shot density. "Controlled" flowback carried out in January 2020 achieved the strategically critical "clean inflow" with reservoir fluids established to surface. Special proppant technologies provided by an industry leading manufacturer overcame the embedment effects and to control solids flowback. A properly designed choke schedule to balance unloading with a delicate enough drawdown to avoid formation failure was executed. Local oilfields relied on the vast reserves and produced easily from carbonate reservoirs that required only perforating or acid squeezes to easily meet or exceed high production expectations. This unconventional undertaking in Kuwait presents a real challenge as it is a complete departure from the ways of working yet it points towards a very high upside potential should the appraisal campaign can be completed effectively.

First Digital Intelligent Artificial Lift Production Optimization Technology in UAE Dual-String Gas Lift Well - Business Case and Implementation Plan

2019 ◽  
Author(s):  
Ahmed Alshmakhy ◽  
Khadija Al Daghar ◽  
Sameer Punnapala ◽  
Shamma AlShehhi ◽  
Abdel Ben Amara ◽  
...  
Keyword(s):  
Business Case ◽  
Production Optimization ◽  
Implementation Plan ◽  
Artificial Lift ◽  
Gas Lift

scholarly journals Injection-production optimization of carbonate reservoir based on an inter-well connectivity model

2021 ◽  
pp. 014459872199465
Author(s):  
Yuhui Zhou ◽  
Sheng Lei ◽  
Xuebiao Du ◽  
Shichang Ju ◽  
Wei Li
Keyword(s):  
History Matching ◽  
Water Injection ◽  
Field Application ◽  
Carbonate Reservoir ◽  
Production Optimization ◽  
Oil Field ◽  
Carbonate Reservoirs ◽  
Utilization Rate ◽  
Production Volume ◽  
Connectivity Model

Carbonate reservoirs are highly heterogeneous. During waterflooding stage, the channeling phenomenon of displacing fluid in high-permeability layers easily leads to early water breakthrough and high water-cut with low recovery rate. To quantitatively characterize the inter-well connectivity parameters (including conductivity and connected volume), we developed an inter-well connectivity model based on the principle of inter-well connectivity and the geological data and development performance of carbonate reservoirs. Thus, the planar water injection allocation factors and water injection utilization rate of different layers can be obtained. In addition, when the proposed model is integrated with automatic history matching method and production optimization algorithm, the real-time oil and water production can be optimized and predicted. Field application demonstrates that adjusting injection parameters based on the model outputs results in a 1.5% increase in annual oil production, which offers significant guidance for the efficient development of similar oil reservoirs. In this study, the connectivity method was applied to multi-layer real reservoirs for the first time, and the injection and production volume of injection-production wells were repeatedly updated based on multiple iterations of water injection efficiency. The correctness of the method was verified by conceptual calculations and then applied to real reservoirs. So that the oil field can increase production in a short time, and has good application value.

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