scholarly journals Experimental simulation of proppant permeability in hydraulic fracturing at extended time under bottom-hole conditions

2021 ◽  
Author(s):  
Ali Seyfeddine Guenaoui ◽  
Abdelmadjid Dobbi ◽  
Hamid Lebtahi ◽  
Ahmed Ali Zerrouki
Keyword(s):  
Hydraulic Fracturing ◽  
High Stress ◽  
Experimental Simulation ◽  
Productivity Index ◽  
Reservoir Pressure ◽  
Extended Time ◽  
Fracture Conductivity ◽  
Bottom Hole ◽  
Hard Formation ◽  
Key Parameter

AbstractDuring hydraulic fracturing treatment, huge quantities of gel are pumped into the formation to initiate the fracture, maintain it open and transport the proppant. The fracture dimensionless conductivity (Fcd) is a key parameter to optimize the fracturing design, to estimate the productivity Index (PI) and the folds of increase (FOI). However, these parameters are affected by the gel residues which decrease the fracture conductivity; thus, the proppant cleanup is a very important step to avoid additional damage caused by fracturing fluid due to high gel concentration and the extended time of gel staying in the fracture before cleanup. Throughout the life of Hassi Messaoud, Algeria field, hydraulic fracturing technique has been aggressively used mainly in four producing formations in the Cambrian, with hard formation characteristics, an average permeability range and low reservoir pressure (0.15–0.45 psi/ft) and high stress value between 6000 and 9000 psi. In this paper, an experimental simulation is applied using a self-made cell to determine the effect of different parameters on the fracture conductivity under various bottom-hole conditions where different variables were used: effect of Proppant type, guar gel concentration, temperature, breaker concentration and closure pressure at extended time. An important drop in fracture conductivity was observed varied between 10 and 80% under stresses at interval of 2000 psi and 8000 psi, gel concentration up to 200 lb/1000 gal at extended time and temperature.

New Analytical Approach to Operational Assessment of Fractured Well Productivity with Variable Permeability

2021 ◽  
Author(s):  
Evgeniy Viktorovich Yudin ◽  
George Aleksandrovich Piotrovskiy ◽  
Maria Vladimirovna Petrova ◽  
Alexey Petrovich Roshchektaev ◽  
Nikita Vladislavovich Shtrobel
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Free Parameter ◽  
Numerical Solutions ◽  
Analytical Models ◽  
Productivity Index ◽  
Finite Conductivity ◽  
Well Productivity ◽  
Fracture Conductivity ◽  
Variable Permeability

Abstract Requirements of targeted optimization are imposed on the hydraulic fracturing operations carried out in the conditions of borderline economic efficiency of fields taking into account geological and technological features. Consequently, the development of new analytical tools foranalyzing and planning the productivity of fractured wells, taking into account the structuralfeatures of the productive reservoir and inhomogeneous distribution of the fracture conductivity, is becoming highly relevant. The paper proposes a new approach of assessing the vertical hydraulic fracture productivityin a rectangular reservoir in a pseudo-steady state, based on reservoir resistivity concept described in the papers of Meyer et al. However, there is a free parameter in the case of modeling the productivity of a hydraulic fracture by the concept. The parameter describes the distribution of the inflow along the plane of the fracture. This paper presents a systematic approach to determining of the parameter. The resulting model allows to conduct an assessment of the influence of various complications in the fracture on the productivity index. During the research a method of determining the free parameter was developed,it was based on the obtained dependence of the inflow distribution on the coordinate along the fracture of finite conductivity. The methodology allowed to refine existent analytical solution of the Meyer et al. model, which, in turn, allowed to assess the influence of different fracture damages in the hydraulic fracture on the productivity index of the well. The work includes the cases of the presence of fracture damages at the beginning and at the end of the fracture. A hydraulic fracture model was built for each of the types of damages, it was based on the developed method, and also the solution of dimensionless productivity ratio was received. The results of the obtained solution were confirmed by comparison with the numerical solutions of commercial simulators and analytical models available in the literature. The advantage of the methodology is the resulting formulas for well productivity are relatively simple, even for exotic cases ofvariable conductivity fractures. The approaches and algorithms described in the paper assume the calculation of the productivity of a hydraulic fracture with variable conductivity and the presence of other complicatingfactors.The methodology of the paper can be used for analysis and diagnosis problems with formation hydraulic fracturing. The efficiency of the calculations allows using the presented methodology to solve inverse problems of determining the efficiency of the hydraulic fracturing operation.

Hydraulic Fracturing Design Developments Towards Improved Effectiveness in North Kuwait Reservoirs

2021 ◽  
Author(s):  
Zamzam Mohammed Ahmed ◽  
Abrar Mohammed Alostad ◽  
Liu Pei Wu
Keyword(s):  
Hydraulic Fracturing ◽  
High Stress ◽  
Natural Fracture ◽  
Unconventional Reservoirs ◽  
Fiscal Year ◽  
Reservoir Pressure ◽  
Gas Field ◽  
Matrix Acidizing ◽  
Field Development

Abstract The North Kuwait Jurassic Gas (NKJG) reservoirs pose productivity challenges due to their geological heterogeneity, complex tectonic settings, high stress anisotropy, high pore pressure, and high bottom-hole temperature. Additionally, high natural fracture intensity in clustered areas play an important role in the wells hydrocarbon deliverability. These challenges are significant in field development starting from well design and stimulation up to production stages. The Gas Field Development Group (GFDG) are introducing for the first time in Kuwait new completion designs at high fracturing intensity; open-hole Multi Stage Completions (MSC), 4.5" Monobores and hybrid completions along with customized and efficient stimulation methods. This development strategy designed to overcome reservoir difficulties and enhance the well performance during initial testing and long-term production phases. At early stages of production, most of the wells were stimulated with simple matrix acidizing jobs and this method was sufficient to reach commercial production in conventional reservoirs. However, the reservoir depletion trend has negatively affected stimulation effectiveness and the wells performance in the recent years; hence, short and long-term solutions introduced to manage the sub-hydrostatic reservoir pressure. Our current focus is on the short-term stimulation solutions as they are relatively easier to apply compared to the long-term solutions that require additional resources, which are not available in the country. As a result, the stimulation methods, specifically the hydraulic fracturing treatments, increased production dramatically compared to previous years and it applied across North Kuwait Fields in conventional and unconventional reservoirs to reach the production targets of 2020-2021. The hydraulic fracturing treatment designs improved during the 2020-2021 fiscal year. The number of operations tripled compared to before and alternative chemical treatments with new fracturing designs implemented. In addition, these treatments executed across different well completions and reservoir properties. The objectives behind each fracturing treatment were different; for example: discovering new areas, re-stimulating under-performing wells, fracturing unconventional reservoirs, etc. Some promising wells did not flow as per expectation after matrix acidizing treatments despite the logs showing good reservoir quality similar to offset wells with good production. After re-stimulating with acid fracturing, the wells performed much better and one of them set a benchmark as the best producer amongst the offset wells. This paper evaluates the gaps in developing NKJG reservoirs, including fracturing treatments and highlights of the pros/cons for each operation, which in future supports the improvement of stimulation job designs. Moreover, it reveals the future requirements that control the operation success and how to reduce the well cleaning time post-fracturing in the event of low reservoir pressure. Finally, it describes how the outcome of the analyses directly assists reaching the production targets; since NKJG's production mainly depends on stimulation techniques.

scholarly journals Laboratory Testing of Fracture Conductivity Damage by Foam-Based Fracturing Fluids in Low Permeability Tight Gas Formations

Energies ◽  
2021 ◽  
Vol 14 (6) ◽  
pp. 1783
Author(s):  
Klaudia Wilk-Zajdel ◽  
Piotr Kasza ◽  
Mateusz Masłowski
Keyword(s):  
Hydraulic Fracturing ◽  
Guar Gum ◽  
Polymer Concentration ◽  
Laboratory Research ◽  
Damage Effect ◽  
Tight Gas ◽  
Fracturing Fluid ◽  
Fracture Conductivity ◽  
Fracturing Fluids ◽  
Sandstone Rock

In the case of fracturing of the reservoirs using fracturing fluids, the size of damage to the proppant conductivity caused by treatment fluids is significant, which greatly influence the effective execution of hydraulic fracturing operations. The fracturing fluid should be characterized by the minimum damage to the conductivity of a fracture filled with proppant. A laboratory research procedure has been developed to study the damage effect caused by foamed and non-foamed fracturing fluids in the fractures filled with proppant material. The paper discusses the results for high quality foamed guar-based linear gels, which is an innovative aspect of the work compared to the non-foamed frac described in most of the studies and simulations. The tests were performed for the fracturing fluid based on a linear polymer (HPG—hydroxypropyl guar, in liquid and powder form). The rheology of nitrogen foamed-based fracturing fluids (FF) with a quality of 70% was investigated. The quartz sand and ceramic light proppant LCP proppant was placed between two Ohio sandstone rock slabs and subjected to a given compressive stress of 4000–6000 psi, at a temperature of 60 °C for 5 h. A significant reduction in damage to the quartz proppant was observed for the foamed fluid compared to that damaged by the 7.5 L/m3 natural polymer-based non-foamed linear fluid. The damage was 72.3% for the non-foamed fluid and 31.5% for the 70% foamed fluid, which are superior to the guar gum non-foamed fracturing fluid system. For tests based on a polymer concentration of 4.88 g/L, the damage to the fracture conductivity by the non-foamed fluid was 64.8%, and 26.3% for the foamed fluid. These results lead to the conclusion that foamed fluids could damage the fracture filled with proppant much less during hydraulic fracturing treatment. At the same time, when using foamed fluids, the viscosity coefficient increases a few times compared to the use of non-foamed fluids, which is necessary for proppant carrying capacities and properly conducted stimulation treatment. The research results can be beneficial for optimizing the type and performance of fracturing fluid for hydraulic fracturing in tight gas formations.

scholarly journals Performance Evaluation of Enzyme Breaker for Fracturing Applications under Simulated Reservoir Conditions

Molecules ◽  
2021 ◽  
Vol 26 (11) ◽  
pp. 3133
Author(s):  
Yuling Meng ◽  
Fei Zhao ◽  
Xianwei Jin ◽  
Yun Feng ◽  
Gangzheng Sun ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Shear Resistance ◽  
Ammonium Persulfate ◽  
Fracturing Fluid ◽  
Medium Temperature ◽  
Fracture Conductivity ◽  
Wide Range ◽  
Reservoir Conditions ◽  
Alkaline Conditions ◽  
Resistance Performance

Fracturing fluids are being increasingly used for viscosity development and proppant transport during hydraulic fracturing operations. Furthermore, the breaker is an important additive in fracturing fluid to extensively degrade the polymer mass after fracturing operations, thereby maximizing fracture conductivity and minimizing residual damaging materials. In this study, the efficacy of different enzyme breakers was examined in alkaline and medium-temperature reservoirs. The parameters considered were the effect of the breaker on shear resistance performance and sand-suspending performance of the fracturing fluid, its damage to the reservoir after gel breaking, and its gel-breaking efficiency. The experimental results verified that mannanase II is an enzyme breaker with excellent gel-breaking performance at medium temperatures and alkaline conditions. In addition, mannanase II did not adversely affect the shear resistance performance and sand-suspending performance of the fracturing fluid during hydraulic fracturing. For the same gel-breaking result, the concentration of mannanase II used was only one fifth of other enzyme breakers (e.g., mannanase I, galactosidase, and amylase). Moreover, the amount of residue and the particle size of the residues generated were also significantly lower than those of the ammonium persulfate breaker. Finally, we also examined the viscosity-reducing capability of mannanase II under a wide range of temperatures (104–158 °F) and pH values (7–8.5) to recommend its best-use concentrations under different fracturing conditions. The mannanase has potential for applications in low-permeability oilfield development and to maximize long-term productivity from unconventional oilwells.

Investigation of Horizontal Wells with Multi-Stage Hydraulic Fracturing Technological Efficiency in the Development of Low-Permeability Oil Reservoirs

2021 ◽  
Author(s):  
Aleksander Valerievich Miroshnichenko ◽  
Valery Alekseevich Korotovskikh ◽  
Timur Ravilevich Musabirov ◽  
Aleksei Eduardovich Fedorov ◽  
Khakim Khalilovich Suleimanov
Keyword(s):  
Hydraulic Fracturing ◽  
Performance Indicators ◽  
Oil And Gas ◽  
Horizontal Wells ◽  
Productivity Index ◽  
Specific Mass ◽  
Horizontal Section ◽  
Technological Complexity ◽  
Multi Stage ◽  
Effective Development

Abstract The deterioration of the reservoir properties of potential oil and gas bearing areas on mature and green fields, as well as the increase in the volume of hard-to-recover reserves on low-permeable reservoirs set us new challenges in searching and using effective development technologies to maintain and even increase the oil production levels. Based on successful international experience, Russian oil and gas companies use horizontal wells (HW) with multi-stage hydraulic fracturing (MSHF) for the cost-effective development of low-permeable reservoirs. Thus, since the first pilot works of drilling technologies and completion of HW with MSHF in 2011, at the beginning of 2020, over 1,200 HW with MSHF were drilled and came on stream at the fields of LLC RN-Yuganskneftegaz, about half of which are at the exploitation play AS10-12 of the northern license territory (NLT) of the Priobskoye field. In searching the best technologies and engineering solutions, the company tested different lengths of horizontal section of HW, the number of hydraulic fracturing (HF) stages and distances between hydraulic fracturing ports, as well as different specific mass of the proppant per frac port. Recently, there has been a tendency in design solutions to increase the length of the HWs and the number of hydraulic fractures with a decreasing distance between the frac ports and a decreasing specific mass of the proppant per frac port. This work studies the actual and theoretical efficiency of HW with MSHF of various designs (different lengths of horizontal section of HW and the number of HF stages) and to assess the viability of increasing the technological complexity, as well as to analyze the actual impact of loading the proppant mass per port on performing HW with MSHF. The study is based on the results of the analysis of the factual experience accumulated over the entire history of the development of the exploitation play AS10-12 of the NLT of the Priobskoye field of the Rosneft Company. In studying the viability of increasing the technological complexity, especially, increasing the length of horizontal section of HW, increasing the number of HF stages, and reducing the distance between the frac ports: we discovered the typical methodological errors made in analyzing the efficiency of wells of various designs; we developed the methodology for analysis of the actual multiplicity of indicators of wells of various designs, in particular, HW with MSHF relative to deviated wells (DW) with HF; we carried out the statistical analysis of the actual values of the multiplicity of performance indicators and completion parameters of HW with MSHF of various designs relative to the surrounding DW with HF of the exploitation play AS10-12 of the NLT of the Priobskoye field; we performed the theoretical calculation of the multiplicity of the productivity coefficient for the HW with MSHF of various designs relative to DW with HF for the standard development system of the exploitation play AS10-12 of the NLT of the Priobskoye field; we compared the actual and theoretical results. The paper also presents the results of studying the actual effect of changes of proppant's mass per port on performance indicators of HW with MSHF of the same design and with an increase in the number of fractures of the hydraulic fracturing without changing the length of horizontal section of HW. As for performance indicators, being the basis for estimating the efficiency of HW with MSHF of various designs, we used the productivity index per meter of the effective reservoir thickness and the cumulative fluid production per meter of the effective reservoir thickness per a certain period of operation. And as the completion parameters, we used the length of the horizontal section of HW, the number of HF stages, the distance between the frac ports, and the specific mass of the proppant per meter of the effective reservoir thickness per frac port. The results of this work are the determining vector of development for future design decisions in improving the efficiency of HW with MSHF.

High-Resolution and Multimaterial Fracture Productivity Calculator for the Successful Design of Channel Fracturing Jobs

2021 ◽  
Author(s):  
Dimitry Chuprakov ◽  
Ludmila Belyakova ◽  
Ivan Glaznev ◽  
Aleksandra Peshcherenko
Keyword(s):  
High Resolution ◽  
Effective Conductivity ◽  
Productivity Index ◽  
Hydraulic Fractures ◽  
Total Production ◽  
Fracture Conductivity ◽  
Hindered Settling ◽  
Accurate Evaluation ◽  
Skin Factor ◽  
Fracture Closure

Abstract We developed a high-resolution fracture productivity calculator to enable fast and accurate evaluation of hydraulic fractures modeled using a fine-scale 2D simulation of material placement. Using an example of channel fracturing treatments, we show how the productivity index, effective fracture conductivity, and skin factor are sensitive to variations in pumping schedule design and pulsing strategy. We perform fracturing simulations using an advanced high-resolution multiphysics model that includes coupled 2D hydrodynamics with geomechanics (pseudo-3D, or P3D, model), 2D transport of materials with tracking temperature exposure history, in-situ kinetics, and a hindered settling model, which includes the effect of fibers. For all simulated fracturing treatments, we accurately solve a problem of 3D planar fracture closure on heterogenous spatial distribution of solids, estimate 2D profiles of fracture width and stresses applied to proppants, and, as a result, obtain the complex and heterogenous shape of fracture conductivity with highly conductive cells owing to the presence of channels. Then, we also evaluate reservoir fluid inflows from a reservoir to fracture walls and further along a fracture to limited-size wellbore perforations. Solution of a productivity problem at the finest scale allows us to accurately evaluate key productivity characteristics: productivity index, dimensional and dimensionless effective conductivity, skin factor, and folds of increase, as well as the total production rate at any day and for any pressure drawdown in a well during well production life. We develop a workflow to understand how productivity of a fracture depends on variation of the pumping schedule and facilitate taking appropriate decisions about the best job design. The presented workflow gives insight into how new computationally efficient methods can enable fast, convenient, and accurate evaluation of the material placement design for maximum production with cost-saving channel fracturing technology.

scholarly journals OPTIMISATION OF HYDRAULIC FRACTURING DESIGN IN LOWER OLIGOCENE RESERVOIR, KINH NGU TRANG OILFIELD

2018 ◽  
Vol 18 (3) ◽  
pp. 323-337
Author(s):  
Nguyen Huu Truong
Keyword(s):  
Hydraulic Fracturing ◽  
Complex Structure ◽  
Power Requirement ◽  
Fracture Conductivity ◽  
Fracture Width ◽  
The North ◽  
Fracture Closure ◽  
Average Water ◽  
White Tiger ◽  
Fracture Height

Kinh Ngu Trang oilfield is of the block 09-2/09 offshore Vietnam, which is located in the Cuu Long basin, the distance from that field to Port of Vung Tau is around 140 km and it is about 14 km from the north of Rang Dong oilfield of the block 15.2, and around 50 km from the east of White Tiger in the block 09.1. That block accounts for total area of 992 km2 with the average water depth of around 50 m to 70 m. The characteristic of Oligocene E reservoir is tight oil in sandstone, very complicated with complex structure. Therefore, the big challenges in this reservoir are the low permeability and the low porosity of around 0.2 md to less than 1 md and 1% to less than 13%, respectively, leading to very low fracture conductivity among the fractures. Through the Minifrac test for reservoir with reservoir depth from 3,501 mMD to 3,525 mMD, the total leak-off coefficient and fracture closure pressure were determined as 0.005 ft/min0.5 and 9,100 psi, respectively. To create new fracture dimensions, hydraulic fracturing stimulation has been used to stimulate this reservoir, including proppant selection and fluid selection, pump power requirement. In this article, the authors present optimisation of hydraulic fracturing design using unified fracture design, the results show that optimum fracture dimensions include fracture half-length, fracture width and fracture height of 216 m, 0.34 inches and 31 m, respectively when using proppant mass of 150,000 lbs of 20/40 ISP Carbolite Ceramic proppant.

Extended-Time Conductivity Testing of Proppants Used for Multi-Stage Horizontal Completions

2022 ◽  
Author(s):  
C. Mark Pearson ◽  
Christopher A. Green ◽  
Mark McGill ◽  
David Milton-Tayler
Keyword(s):  
American Petroleum Institute ◽  
Late Time ◽  
Extended Time ◽  
Economic Optimization ◽  
Time Data ◽  
Fracture Conductivity ◽  
White Sand ◽  
Productive Life ◽  
Well Completion ◽  
Multi Stage

Abstract The American Petroleum Institute Recommended Practice 19-D (2018) is the current industry standard for conductivity testing of proppants used in hydraulic fracturing. Similar to previous standards from both the API and ISO, it continues the practice of measuring a "reference" long-term conductivity after 50-hours of time at a given stress. The fracture design engineer is then left to estimate a damage factor to apply over the life of the well completion based on correlations or experience. This study takes four standard proppants used for multi-stage horizontal well completions in North America and presents test data over 250-days of "extended-time" at 7,500 psi of effective stress. The API RP 19-D procedure was followed for all testing, but extended for 250-days duration for the four proppant types: 40/70 mesh mono-crystalline "White" sand, 40/70 mesh multi-crystalline "Brown" sand, 100 mesh "Brown" sand, and 40/70 mesh Light Weight Ceramic (LWC). The 7,500 psi stress condition was chosen to replicate initial stress conditions for a 10,000 feet deep well with a 0.75 psi/ft fracture gradient - typical of unconventional resource plays such as the Bakken formation of North Dakota or the Delaware Basin in west Texas. Results presented provide a measure of the amount of damage occurring in the proppant pack due to time at stress. To the authors’ knowledge, there has never been any extended-time conductivity data published for multiple proppant types over the timeframe completed in this study - despite the obvious need for this understanding to optimize the stimulation design over the full life of the well. Results for the four proppant types are presented as conductivity curves as a function of time for the 250-days of testing. Pack degradation is shown to follow a semi-log decline. Late time continued degradation for all materials is extrapolated over the life of a typical well (40 years), and compared to extended-time particle size distribution and crush data to explain the results observed. Extended-time data such as this 250-day study have never been published on proppants such as these despite the fact that fracture conductivity has a major impact on the productive life of a well and the ultimate recovery of hydrocarbons from the formation. The data presented should be of great interest to any engineer involved with completion designs, or reservoir engineers assessing the productive life and ultimate recovery in the formation since economic optimization is primarily driven by the interplay of fracture length/area with extended-time in-situ fracture conductivity.

Evaluating the Performance of Horizontal Multi-Frac Wells in a Depleted Gas Condensate Reservoir in Sultanate of Oman

2022 ◽  
Author(s):  
Josef R. Shaoul ◽  
Jason Park ◽  
Andrew Boucher ◽  
Inna Tkachuk ◽  
Cornelis Veeken ◽  
...  
Keyword(s):  
Horizontal Well ◽  
Horizontal Wells ◽  
Gas Condensate ◽  
Integrated Analysis ◽  
Single Fracture ◽  
Reservoir Pressure ◽  
Well Test ◽  
Vertical Wells ◽  
Fracture Conductivity ◽  
Half Length

Abstract The Saih Rawl gas condensate field has been producing for 20 years from multiple fractured vertical wells covering a very thick gross interval with varying reservoir permeability. After many years of production, the remaining reserves are mainly in the lowest permeability upper units. A pilot program using horizontal multi-frac wells was started in 2015, and five wells were drilled, stimulated and tested over a four-year period. The number of stages per horizontal well ranged from 6 to 14, but in all cases production was much less than expected based on the number of stages and the production from offset vertical wells producing from the same reservoir units with a single fracture. The scope of this paper is to describe the work that was performed to understand the reason for the lower than expected performance of the horizontal wells, how to improve the performance, and the implementation of those ideas in two additional horizontal wells completed in 2020. The study workflow was to perform an integrated analysis of fracturing, production and well test data, in order to history match all available data with a consistent reservoir description (permeability and fracture properties). Fracturing data included diagnostic injections (breakdown, step-rate test and minifrac) and main fracture treatments, where net pressure matching was performed. After closure analysis (ACA) was not possible in most cases due to low reservoir pressure and absence of downhole gauges. Post-fracture well test and production matching was performed using 3D reservoir simulation models including local grid refinement to capture fracture dimensions and conductivity. Based on simulation results, the effective propped fracture half-length seen in the post-frac production was extremely small, on the order of tens of meters, in some of the wells. In other wells, the effective fracture half-length was consistent with the created propped half-length, but the fracture conductivity was extremely small (finite conductivity fracture). The problems with the propped fractures appear to be related to a combination of poor proppant pack cleanup, low proppant concentration and small proppant diameter, compounded by low reservoir pressure which has a negative impact on proppant regained permeability after fracturing with crosslinked gel. Key conclusions from this study are that 1) using the same fracture design in a horizontal well with transverse fractures will not give the same result as in a vertical well in the same reservoir, 2) the effect of depletion on proppant pack cleanup in high temperature tight gas reservoirs appears to be very strong, requiring an adjustment in fracture design and proppant selection to achieve reasonable fracture conductivity, and 3) achieving sufficient effective propped length and height is key to economic production.

Success Story of Optimizing Hydraulic Fracturing Design at Alpha Low-Permeability Reservoir

2021 ◽  
Author(s):  
Mario Hadinata Prasetio ◽  
Hanny Anggraini ◽  
Hendro Tjahjono ◽  
Aditya Bintang Pramadana ◽  
Aulia Akbari ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Oil Recovery ◽  
History Matching ◽  
Initial Period ◽  
Earth Model ◽  
Low Permeability ◽  
Stress Profile ◽  
Reservoir Pressure ◽  
Fracturing Fluid ◽  
Fracture Closure

Abstract This paper describes the evolution of the hydraulic fracturing approach and design in the Alpha reservoir over the past years. Alpha reservoir in XYZ field is a laminated sandstone reservoir with low permeability in the range of 20 to 140 md at a depth of approximately 4,000 to 4,500 ft true vertical depth (TVD). XYZ field is located in Rokan block, Riau, Central Sumatra region. Due to Alpha reservoir's nature, producing from this reservoir commercially requires stimulation. Hydraulic fracturing has been applied as the selected stimulation method to increase productivity from this reservoir. However, several challenges were recognized during the initial period, such as depleted reservoir pressure, indication of fracture height growth, and low to medium Young's modulus, which leads to few screened-out cases as well as low production gain after the fracturing treatment. The fracturing job in Alpha reservoir has been applied since 2002. However, pressure depletion was observed through this time until waterflood optimization started in May 2018 by converting commingled injection to injection dedicated to the Alpha reservoir. The pressure responded and increased from 350 psi to approximately 800 psi. Hence this reservoir still cannot be produced in single completion without the hydraulic fracturing job due to laminated reservoir and low-permeability character. A detailed look at the mechanical earth model (MEM) was done to revise the elastic properties and stress profile considering reservoir pressure change. The revised model was later used as an input for fracture geometry simulation. Calibration injection tests were performed and analyzed prior to the main fracturing treatments to determine fracture closure pressure and leakoff characteristics, which led to fracturing fluid efficiency. Results of these tests were used in job modifications regarding pad percentage, fracturing fluid rheology, proppant volume, and proppant concentration. Pressure history matching both after fracturing and in real time as well as the temperature log were used to validate the MEM and fracture geometries. Each change, approach, and impact were documented and statistically analyzed to determine a generic trend and design envelope for the Alpha reservoir. Between 2019 and 2020, nine wells were stimulated that specifically targeted the Alpha reservoir, with continuous improvement in fracturing design and geomechanics properties with each well. After fracturing, the 30-day oil recovery was superior, higher than previous fractured wells, reaching more than 255 BFPD on average. The successful development of the Alpha reservoir with hydraulic fracturing led to further milestones to maximize oil recovery in XYZ field.

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