scholarly journals Evaluation and Optimization of Bypassed Oil in Carbonate Reservoir at Mature Field with Integration of Saturation Log and Cement Bond Quality

2021 ◽  
Vol 2 (1) ◽  
pp. 7
Author(s):  
Agus Amperianto ◽  
Dyah Rini Ratnaningsih ◽  
Dedy Kristanto
Keyword(s):  
Carbonate Reservoir ◽  
Production Optimization ◽  
Production Performance ◽  
Water Production ◽  
Water Contact ◽  
Current Saturation ◽  
Cumulative Production ◽  
Zonal Isolation ◽  
Water Cut ◽  
Bypassed Oil

AA field is a unitized asset operated by Corporate Oil Company since May 2018. The main producing formation of AA field is a reef build-up carbonate reservoir. The field has been on production since 2004 with OOIP of 297 MMSTB. As of November 2019 the cumulative production was estimated 120.7 MMSTB with RF of 41%. The carbonate reservoir has properties with relatively high heterogeneity –both vertically as well as laterally – which leads to production variation of the wells. The production performance shows an estimated 30% decline and significantly increasing water-cut. The production data shows a much faster water production compared with the cumulative production, which is also the greatest challenge in the AA field.There are several key contributing factors for the water production in AA field:Water channeling behind casing due to poor cement bond. This is supported by Chan Plot analysis.Uneven production of the wells leading to varying water rise and introduces difficulty in water contact determination.Water coning due to production exceeding the critical rate.Several efforts have been performed to optimize production, namely: identification of the potential of remaining hydrocarbon (bypassed oil) in the wells by evaluating current saturation evaluation through downhole surveillance, estimation of current water contact and cement bond improvement.The preparation steps of the production optimization process are summarized below:Screening of Candidate WellsEvaluation of Cement Bond QualityWellsite Execution for Bypassed Oil EvaluationWell PreparationOptimum C/O Log to Evaluate Current Saturation and to Identify Bypassed Oil ZonesBypassed Oil Interval ProductionThis section discusses one of successful cases in the production optimization effort implemented in the AA- field.AA-12 wellThe last production of AA-12 well was 84 BOPD. Chan plot showed possibility of water channeling, which was supported by CBL result. The zone of existing perforation interval was indicated to have “free pipe” behind the casing. Remedial cementing was then performed until sufficient zonal isolation was obtained. After subsequent CBL confirmed good zonal isolation, C/O log was then performed. The C/O log result indicated several reservoir zones with potential bypassed oil. The new production interval was selected based on following consideration: So between 55-60%, height above current OWC of 185 ft (56 m), distance to the adjacent wells of 1306 ft (398 m), porosity 12-17% and Production test of the new perforation resulted in 2186 BOPD with 0% water-cut.

Real-Time EM Look-Ahead Resistivity for Mapping of Oil/Water Contact While Drilling at Low Deviated Well, New Perspective for Mature Oil Fields Development: A Case Study Of Umm Gudair Field, Kuwait

2021 ◽  
Author(s):  
Nasser Faisal Al-Khalifa ◽  
Mohammed Farouk Hassan ◽  
Deepak Joshi ◽  
Asheshwar Tiwary ◽  
Ihsan Taufik Pasaribu ◽  
...  
Keyword(s):  
Water Saturation ◽  
High Water ◽  
Carbonate Reservoir ◽  
Water Contact ◽  
Saturation Zone ◽  
Look Ahead ◽  
Production History ◽  
Oil Water ◽  
High Water Cut ◽  
Water Cut

Abstract The Umm Gudair (UG) Field is a carbonate reservoir of West Kuwait with more than 57 years of production history. The average water cut of the field reached closed to 60 percent due to a long history of production and regulating drawdown in a different part of the field, consequentially undulating the current oil/water contact (COWC). As a result, there is high uncertainty of the current oil/water contact (COWC) that impacts the drilling strategy in the field. The typical approach used to develop the field in the lower part of carbonate is to drill deviated wells to original oil/water contact (OOWC) to know the saturation profile and later cement back up to above the high-water saturation zone and then perforate with standoff. This method has not shown encouraging results, and a high water cut presence remains. An innovative solution is required with a technology that can give a proactive approach while drilling to indicate approaching current oil/water contact and geo-stop drilling to give optimal standoff between the bit and the detected water contact (COWC). Recent development of electromagnetic (EM) look-ahead resistivity technology was considered and first implemented in the Umm Gudair (UG) Field. It is an electromagnetic-based signal that can detect the resistivity features ahead of the bit while drilling and enables proactive decisions to reduce drilling and geological or reservoir risks related to the well placement challenges.

An Innovated Water Shutoff Technology in Offshore Carbonate Reservoir

2021 ◽  
Author(s):  
Yong Yang ◽  
Xiaodong Li ◽  
Changwei Sun ◽  
Yuanzhi Liu ◽  
Renkai Jiang ◽  
...  
Keyword(s):  
Heavy Oil ◽  
Bottom Water ◽  
High Water ◽  
Carbonate Reservoir ◽  
Oil Reservoir ◽  
Water Production ◽  
Water Shutoff ◽  
Water Breakthrough ◽  
Heavy Oil Reservoir ◽  
Water Cut

Abstract The problem of water production in carbonate reservoir is always a worldwide problem; meanwhile, in heavy oil reservoir with bottom water, rapid water breakthrough or high water cut is the development feature of this kind of reservoir; the problem of high water production in infill wells in old reservoir area is very common. Each of these three kinds of problems is difficult to be tackled for oilfield developers. When these three kinds of problems occur in a well, the difficulty of water shutoff can be imagined. Excessive water production will not only reduce the oil rate of wells, but also increase the cost of water treatment, and even lead to well shut in. Therefore, how to solve the problem of produced water from infill wells in old area of heavy oil reservoir with bottom water in carbonate rock will be the focus of this paper. This paper elaborates the application of continuous pack-off particles with ICD screen (CPI) technology in infill wells newly put into production in brown field of Liuhua, South China Sea. Liuhua oilfield is a biohermal limestone heavy oil reservoir with strong bottom water. At present, the recovery is only 11%, and the comprehensive water cut is as high as 96%. Excessive water production greatly reduces the hydrocarbon production of the oil well, which makes the production of the oilfield decrease rapidly. In order to delay the decline of oil production, Liuhua oilfield has adopted the mainstream water shutoff technology, including chemical and mechanical water shutoff methods. The application results show that the adaptability of mainstream water shutoff technology in Liuhua oilfield needs to be improved. Although CPI has achieved good water shutoff effect in the development and old wells in block 3 of Liuhua oilfield, there is no application case in the old area of Liuhua oilfield which has been developed for decades, so the application effect is still unclear. At present, the average water cut of new infill wells in the old area reaches 80% when commissioned and rises rapidly to more than 90% one month later. Considering that there is more remaining oil distribution in the old area of Liuhua oilfield and the obvious effect of CPI in block 3, it is decided to apply CPI in infill well X of old area for well completion. CPI is based on the ICD screen radial high-speed fluid containment and pack-off particles in the wellbore annulus to prevent fluid channeling axially, thus achieving well bore water shutoff and oil enhancement. As for the application in fractured reef limestone reservoir, the CPI not only has the function of wellbore water shutoff, but also fills the continuous pack-off particles into the natural fractures in the formation, so as to achieve dual water shutoff in wellbore and fractures, and further enhance the effect of water shutoff and oil enhancement. The target well X is located in the old area of Liuhua oilfield, which is a new infill well in the old area. This target well with three kinds of water problems has great risk of rapid water breakthrough. Since 2010, 7 infill wells have been put into operation in this area, and the water cut after commissioning is 68.5%~92.6%. The average water cut is 85.11% and the average oil rate is 930.92 BPD. After CPI completion in well X, the water cut is only 26% (1/3 of offset wells) and the oil rate is 1300BPD (39.6% higher than that of offset wells). The target well has achieved remarkable effect of reducing water and increasing oil. In addition, in the actual construction process, a total of 47.4m3 particles were pumped into the well, which is equivalent to 2.3 times of the theoretical volume of the annulus between the screen and the borehole wall. Among them, 20m3 continuous pack-off particles entered the annulus, and 27.4m3 continuous pack-off particles entered the natural fractures in the formation. Through the analysis of CPI completed wells in Liuhua oilfield, it is found out that the overfilling quantity is positively correlated to the effect of water shutoff and oil enhancement.

Application of Multilateral Wells for Production and Enhanced Oil Recovery: Case Studies from Canada

2021 ◽  
pp. 1-23
Author(s):  
Eric Delamaide
Keyword(s):  
Oil Recovery ◽  
Horizontal Wells ◽  
Production Performance ◽  
Water Production ◽  
Public Data ◽  
Heavy Oil Reservoirs ◽  
Complex Architectures ◽  
Cumulative Production ◽  
Tertiary Recovery ◽  
And Performance

Summary The use of multilateral wells started in the mid-1990s in particular in Canada, and they have since been used in many countries. However, few papers on multilateral wells focus on their production performance. Thus, what can be expected from such wells in terms of production is not clear, and this paper will attempt to address that gap. Taking advantage of public data, the production performance of multilateral wells in various Western Canadian fields has been studied. In the cases reviewed in this paper, these wells always target a single formation; they have been used in a variety of fields and reservoirs, mostly for primary production but also for polymer flooding in some cases. Multiple examples will be provided, mostly in heavy oil reservoirs, and production performance will be compared with nearby horizontal wells whenever possible. From the more classical dual and trilateral, to more complex architectures with seven or eight laterals, and the more exotic with laterals drilled from laterals, the paper will present the architecture and performance of these complex wells and of some fields that have been developed almost exclusively with multilateral wells. Interestingly, multilateral wells have not been used much for secondary or tertiary recovery, probably because of the difficulty of controlling water production after breakthrough. However, field results suggest that this may not be such a difficult proposition. One of the most remarkable wells producing a 1,250-cp oil under polymer flood has achieved a cumulative production of more than 3 million bbl, which puts it among the top producers in Canada. Although multilateral wells have been in use for more than 25 years, very few papers have been devoted to the description of their production performance. This paper will bring some clarity to these aspects. It will also attempt to address when multilateral wells can be used and to compare their performance to that of horizontal wells in the same fields. It is hoped that this paper will encourage operators to reconsider the use of multilateral wells in their fields.

scholarly journals The Application of Diagnostic Plots to Evaluate Water Flooding

2020 ◽  
Vol 1 (1) ◽  
pp. 36
Author(s):  
Ratna Widyaningsih ◽  
Muhamad Zamzam Istimaqom ◽  
Hizballah Nidaulhaq ◽  
Atma Budi Arta
Keyword(s):  
Production Optimization ◽  
Water Flooding ◽  
Diagnostic Plots ◽  
Plot Analysis ◽  
Water Breakthrough ◽  
Production Wells ◽  
Light Oil ◽  
Current Production ◽  
Cumulative Production ◽  
Water Cut

To analyze production optimization using waterflood, several types of diagnostic plots are needed to determine the response to using waterflood. If you have analyzed 1 plot, it is necessary to conduct a comprehensive analysis to evaluate its success rate by combining it using another plot analysis. The X-Min Field is a field that produces light oil and is managed by the Asset Optimization SLO North PT. Chevron Pacific Indonesia. This field was discovered in 1959 and started to be produced in 1966. Currently, 100 wells have been drilled with 37 active wells from 43 production wells, active injector wells are 18 out of 19, inactive wells 30, 4 wells have been plugged in, and there are 4 active wells that produce gas. The number of OOIPs in this field is 593 MMBO with cumulative production reaching 283.7 MMBO and Recovery Factor reaching 47.7%. In 2017 it was noted that the current production in December 2017 amounted to 5,374 BOPD / 121,264 BFPD or in other words the water cut reached 96.6%. Meanwhile, the amount of injection used to optimize this field is 144,103 BWIPD. Reservoirs in this field have 4 reservoirs namely Res-1, Res-2, Res-3, and Res-4 wherein each reservoir there are several grains of sand optimized using waterflood. There was 8 sand analyzed, including Sand Asyique, Sand Bajubaru, Sand Cemangad, Sand Emakpintar, Sand Fantamantap, Sand Gulungulung, Sand Harikita, and Special Sand. Closes the producer indicated premature water breakthrough. General recommendations given to various sands include adding or subtracting, both injectors and producers based on the response of each sand to water flooding.

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.

New Gel Aggregates To Improve Sweep Efficiency During Waterflooding

2011 ◽  
Vol 14 (01) ◽  
pp. 120-128 ◽  
Author(s):  
Guanglun Lei ◽  
Lingling Li ◽  
Hisham A. Nasr-El-Din
Keyword(s):  
Low Cost ◽  
Oil Production ◽  
High Water ◽  
Resistance Factor ◽  
Water Production ◽  
Sweep Efficiency ◽  
Low Viscosity ◽  
Productivity Decline ◽  
High Water Cut ◽  
Water Cut

Summary A common problem for oil production is excessive water production, which can lead to rapid productivity decline and significant increases in operating costs. The result is often a premature shut-in of wells because production has become uneconomical. In water injectors, the injection profiles are uneven and, as a result, large amounts of oil are left behind the water front. Many chemical systems have been used to control water production and improve recovery from reservoirs with high water cut. Inorganic gels have low viscosity and can be pumped using typical field mixing and injection equipment. Polymer or crosslinked gels, especially polyacrylamide-based systems, are mainly used because of their relatively low cost and their supposed selectivity. In this paper, microspheres (5–30 μm) were synthesized using acrylamide monomers crosslinked with an organic crosslinker. They can be suspended in water and can be pumped in sandstone formations. They can plug some of the pore throats and, thus, force injected water to change its direction and increase the sweep efficiency. A high-pressure/high-temperature (HP/HT) rheometer was used to measure G (elastic modulus) and G" (viscous modulus) of these aggregates. Experimental results indicate that these microspheres are stable in solutions with 20,000 ppm NaCl at 175°F. They can expand up to five times their original size in deionized water and show good elasticity. The results of sandpack tests show that the microspheres can flow through cores with permeability greater than 500 md and can increase the resistance factor by eight to 25 times and the residual resistance factor by nine times. The addition of microspheres to polymer solutions increased the resistance factor beyond that obtained with the polymer solution alone. Field data using microspheres showed significant improvements in the injection profile and enhancements in oil production.

Investigation of Fluid Conductive Faults and Modeling of Complex Water Influx in the Khafji Oil Field, Arabian Gulf

2000 ◽  
Vol 3 (05) ◽  
pp. 401-407 ◽  
Author(s):  
N. Nishikiori ◽  
Y. Hayashida
Keyword(s):  
Water Movement ◽  
Arabian Gulf ◽  
Oil Field ◽  
Water Production ◽  
Water Contact ◽  
Water Influx ◽  
Model Complex ◽  
Oil Water ◽  
Sandstone Reservoir ◽  
Sandstone Reservoirs

Summary This paper describes the multidisciplinary approach taken to investigate and model complex water influx into a water-driven sandstone reservoir, taking into account vertical water flux from the lower sand as a suspected supplemental source. The Khafji oil field is located offshore in the Arabian Gulf. Two Middle Cretaceous sandstone reservoirs are investigated to understand water movement during production. Both reservoirs are supported by a huge aquifer and had the same original oil-water contact. The reservoirs are separated by a thick and continuous shale so that the upper sand is categorized as edge water drive and the lower sand as bottomwater drive. Water production was observed at the central up structure wells of the upper sand much earlier than expected. This makes the modeling of water influx complicated because it is difficult to explain this phenomenon only by edge water influx. In this study, a technical study was performed to investigate water influx into the upper sand. A comprehensive review of pressure and production history indicated anomalous higher-pressure areas in the upper sand. Moreover, anomalous temperature profiles were observed in some wells in the same area. At the same time, watered zones were trailed through thermal-neutron decay time(TDT) where a thick water column was observed in the central area of the reservoir. In addition, a three-dimensional (3D) seismic survey has been conducted recently, revealing faults passing through the two reservoirs. Therefore, as a result of data review and subsequent investigation, conductive faults from the lower sand were suspected as supplemental fluid conduits. A pressure transient test was then designed and implemented, which suggested possible leakage from the nearby fault. Interference of the two reservoirs and an estimate of supplemental volume of water influx was made by material balance. Finally, an improved full-scale numerical reservoir model was constructed to model complex water movement, which includes suspected supplemental water from the lower sand. Employment of two kinds of water influx—one a conventional edge water and another a supplemental water invasion from the aquifer of the lowers and through conductive faults—achieved a water breakthrough match. Introduction The Khafji oil field is located in the Arabian Gulf about 40 km offshore Al-Khafji as shown by Fig. 1. The length and width of the field are about 20 and 8 km, respectively. The upper sandstone reservoir, the subject of this study, lies at a depth of about 5,000 ft subsea and was discovered in1960. The average thickness of the reservoir is about 190 ft. The reservoir is of Middle Cretaceous geologic age. Underlying the upper sandstone reservoir is another sandstone reservoir at a depth of about 5,400 ft. It has an average gross thickness of about 650 ft and is separated from the upper sand by a thick shale bed of about 200 ft. Both reservoirs had the same original oil-water contact level as shown by the subsurface reservoir profile in Fig. 2. Both sandstone reservoirs are categorized as strong waterdrive that can maintain reservoir pressure well above the bubblepoint. On the other hand, water production cannot be avoided because of an unfavorable water-to-oil mobility ratio of 2 to 4 and high formation permeability in conjunction with a strong waterdrive mechanism. In a typical edge water drive reservoir, water production normally begins from the peripheral wells located near the oil-water contact and water encroaches as oil production proceeds. However, some production wells located in the central up structure area of the upper sand started to produce formation water before the wells located in the flank area near the water level. In 1996, we started an integrated geological and reservoir study to maximize oil recovery, to enhance reservoir management, and to optimize the production scheme for both sandstone reservoirs. This paper describes a part of the integrated study, which focused on the modeling of water movement in the upper sand. The contents of the study described in this paper are outlined as:diagnosis and description of the reservoir by fully utilizing available data, which include comprehensive review of production history, TDT logs, formation temperatures, pressures, and 3D seismic; introduction of fluid conductive faults as a suspected supplemental water source in the central upstructure area; design and implementation of a pressure transient test to investigate communication between the reservoirs and conductivity of faults; running of material balance for the two reservoirs simultaneously to assess their interference; and construction of an improved full-scale reservoir simulation model and precise modeling of complex water movement. Brief Geological Description of the Upper Sand The structure of the upper sand is anticline with the major axis running northeast to southwest. The structure dip is gentle (Fig. 3) at about3° on the northwestern flank and 2° on the southeastern flank. The upper sand is composed mainly of sandstone-dominated sandstone and shale sequences. It is interpreted that the depositional environment is complex, consisting of shoreface and tide-influenced fluvial channels.

Pilot Project Evaluating WAG Efficiency for Carbonate Reservoir in Eastern Siberia

2021 ◽  
Author(s):  
Valentina Zharko ◽  
Dmitriy Burdakov
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Oil Production ◽  
Pilot Project ◽  
Carbonate Reservoir ◽  
Recovery Factor ◽  
Eastern Siberia ◽  
Water Cut ◽  
Wag Injection ◽  
Injection Rates

Abstract The paper presents the results of a pilot project implementing WAG injection at the oilfield with carbonate reservoir, characterized by low efficiency of traditional waterflooding. The objective of the pilot project was to evaluate the efficiency of this enhanced oil recovery method for conditions of the specific oil field. For the initial introduction of WAG, an area of the reservoir with minimal potential risks has been identified. During the test injections of water and gas, production parameters were monitored, including the oil production rates of the reacting wells and the water and gas injection rates of injection wells, the change in the density and composition of the produced fluids. With first positive results, the pilot area of the reservoir was expanded. In accordance with the responses of the producing wells to the injection of displacing agents, the injection rates were adjusted, and the production intensified, with the aim of maximizing the effect of WAG. The results obtained in practice were reproduced in the simulation model sector in order to obtain a project curve characterizing an increase in oil recovery due to water-alternating gas injection. Practical results obtained during pilot testing of the technology show that the injection of gas and water alternately can reduce the water cut of the reacting wells and increase overall oil production, providing more efficient displacement compared to traditional waterflooding. The use of WAG after the waterflooding provides an increase in oil recovery and a decrease in residual oil saturation. The water cut of the produced liquid decreased from 98% to 80%, an increase in oil production rate of 100 tons/day was obtained. The increase in the oil recovery factor is estimated at approximately 7.5% at gas injection of 1.5 hydrocarbon pore volumes. Based on the received results, the displacement characteristic was constructed. Methods for monitoring the effectiveness of WAG have been determined, and studies are planned to be carried out when designing a full-scale WAG project at the field. This project is the first pilot project in Russia implementing WAG injection in a field with a carbonate reservoir. During the pilot project, the technical feasibility of implementing this EOR method was confirmed, as well as its efficiency in terms of increasing the oil recovery factor for the conditions of the carbonate reservoir of Eastern Siberia, characterized by high water cut and low values of oil displacement coefficients during waterflooding.

Advanced Multi-Disciplinary Simulation Workflow for Well Placement, Hydraulic Fracturing and Production Optimization Applied to the Diyab Unconventional Play in Onshore UAE

2021 ◽  
Author(s):  
Hamid Pourpak ◽  
Samuel Taubert ◽  
Marios Theodorakopoulos ◽  
Arnaud Lefebvre-Prudencio ◽  
Chay Pointer ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
United Arab Emirates ◽  
Reservoir Characterization ◽  
Horizontal Wells ◽  
Production Optimization ◽  
Production Performance ◽  
Well Placement ◽  
Fully Integrated ◽  
Sector Model ◽  
The Impact

Abstract The Diyab play is an emerging unconventional play in the Middle East. Up to date, reservoir characterization assessments have proved adequate productivity of the play in the United Arab Emirates (UAE). In this paper, an advanced simulation and modeling workflow is presented, which was applied on selected wells located on an appraisal area, by integrating geological, geomechanical, and hydraulic fracturing data. Results will be used to optimize future well landing points, well spacing and completion designs, allowing to enhance the Stimulated Rock Volume (SRV) and its consequent production. A 3D static model was built, by propagating across the appraisal area, all subsurface static properties from core-calibrated petrophysical and geomechanical logs which originate from vertical pilot wells. In addition, a Discrete Fracture Network (DFN) derived from numerous image logs was imported in the model. Afterwards, completion data from one multi-stage hydraulically fracked horizontal well was integrated into the sector model. Simulations of hydraulic fracturing were performed and the sector model was calibrated to the real hydraulic fracturing data. Different scenarios for the fracture height were tested considering uncertainties related to the fracture barriers. This has allowed for a better understanding of the fracture propagation and SRV creation in the reservoir at the main target. In the last step, production resulting from the SRV was simulated and calibrated to the field data. In the end, the calibrated parameters were applied to the newly drilled nearby horizontal wells in the same area, while they were hydraulically fractured with different completion designs and the simulated SRVs of the new wells were then compared with the one calculated on the previous well. Applying a fully-integrated geology, geomechanics, completion and production workflow has helped us to understand the impact of geology, natural fractures, rock mechanical properties and stress regimes in the SRV geometry for the unconventional Diyab play. This work also highlights the importance of data acquisition, reservoir characterization and of SRV simulation calibration processes. This fully integrated workflow will allow for an optimized completion strategy, well landing and spacing for the future horizontal wells. A fully multi-disciplinary simulation workflow was applied to the Diyab unconventional play in onshore UAE. This workflow illustrated the most important parameters impacting the SRV creation and production in the Diyab formation for he studied area. Multiple simulation scenarios and calibration runs showed how sensitive the SRV can be to different parameters and how well placement and fracture jobs can be possibly improved to enhance the SRV creation and ultimately the production performance.

Unlocking Field Potential of Mature Fields Using Hybrid Fuzzy Modelling and Kriging Method

2021 ◽  
Author(s):  
Saransh Surana
Keyword(s):  
Oil And Gas ◽  
Field Potential ◽  
High Water ◽  
Production Optimization ◽  
Secondary Development ◽  
Wellhead Pressure ◽  
Mature Field ◽  
High Water Cut ◽  
Water Cut ◽  
Well Data

Abstract Reservoir uncertainties, high water cut, completion integrity along with declining production are the major challenges of a mature field. These integrated with dying facilities and poor field production are key issues that each oil and gas company is facing these days. Arresting production decline is an inevitable objective, but with the existing techniques/steps involved, it becomes a cumbersome and exorbitant affair for the operators to meet their requirements. In addition, incompetent and flawed well data makes it more challenging to analyze mature fields. Although flow rate data is the most easily accessible data for mature fields, the absence of pressure data (flowing bottom-hole or wellhead pressure) remains a big obstacle for the application of conventional production enhancement and well screening strategies for most of the mature fields. A real-time optimization tool is thus constructed by developing a hybrid modelling technique that encapsulates Kriging and Fuzzy Logic to account for the imprecisions and uncertainties involved while identification of subsurface locations for production optimization of a mature field using only production data. The data from the existing wells in the field is used to generate a membership function based on its historical performance and productivity, thereby generating a spatial map of prospective areas, where secondary development operations can be taken up for production optimization.

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