Modeling Multistage Acid Fracturing Treatments in Carbonate Reservoirs

Abstract As our industry is tapping into tighter carbonate reservoirs than in the past, completion techniques need to be improved to stimulate the low-permeability carbonate formation. Multistage acid fracturing technique has been developed in recent years and proved to be successful in some carbonate reservoirs. A multistage acid fracturing job is to perform several stages of acid fracturing along a horizontal well. The goal of acid fracturing operations is to create enough fracture roughness through differential acid etching on fracture walls such that the acid fracture can keep open and sustain a high enough acid fracture conductivity under the closure stress. In multistage acid fracturing treatments, acid flow is in a radial flow scenario and the acid etching process can be different from acid fracturing in vertical wells. In order to accurately predict the acid-fracture conductivity, a detailed description of the rough acid-fracture surfaces is required. In this paper, we developed a 3D acid transport model to compute the geometry of acid fracture for multistage acid fracturing treatments. The developed model couples the acid fluid flow, reactive transport and rock dissolution in the fracture. We also included acid viscous fingering in our model since viscous fingering mechanism is commonly applied in multistage acid fracturing to achieve non-uniform acid etching. Our simulation results reproduced the acid viscous fingering phenomenon observed from experiments in the literature. During the process of acid viscous fingering, high-conductivity channels developed in the fingering regions. We modeled the acid etching process in multistage acid fracturing treatments and compared it with acid fracturing treatments in vertical wells. We found that due to the radial flow effect, it is more difficult to achieve non-uniform acid etching in multistage acid fracturing treatments than in vertical wells. We investigated the effects of perforation design and pad fluid viscosity on multistage acid fracturing treatments. We need to have an adequate number of perforations in order to develop non-uniform acid etching. We found that a higher viscosity pad fluid helps acid to penetrate deeper in the fracture and result in a longer and narrower etched channel.

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Modeling Acid Fracturing Treatments with Multi-Stage Alternating Injection of Pad and Acid Fluids

10.2118/203985-ms ◽

2021 ◽

Author(s):

Rencheng Dong ◽

Mary F. Wheeler ◽

Hang Su ◽

Kang Ma

Keyword(s):

Viscous Fingering ◽

High Viscosity ◽

Carbonate Reservoirs ◽

Acid Etching ◽

Fracture Geometry ◽

Fracture Conductivity ◽

Acid Fracturing ◽

Fracture Surfaces ◽

Low Viscosity ◽

Multi Stage

Abstract Acid fracturing technique is widely applied to stimulate the productivity of carbonate reservoirs. The acid-fracture conductivity is created by non-uniform acid etching on fracture surfaces. Heterogeneous mineral distribution of carbonate reservoirs can lead to non-uniform acid etching during acid fracturing treatments. In addition, the non-uniform acid etching can be enhanced by the viscous fingering mechanism. For low-perm carbonate reservoirs, by multi-stage alternating injection of a low-viscosity acid and a high-viscosity polymer pad fluid during acid fracturing, the acid tends to form viscous fingers and etch fracture surfaces non-uniformly. To accurately predict the acid-fracture conductivity, this paper developed a 3D acid fracturing model to compute the rough acid fracture geometry induced by multi-stage alternating injection of pad and acid fluids. Based on the developed numerical simulator, we investigated the effects of viscous fingering, perforation design and stage period on the acid etching process. Compared with single-stage acid injection, multi-stage alternating injection of pad and acid fluids leads to narrower and longer acid-etched channels.

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Modeling Acid Fracturing Treatments in Heterogeneous Carbonate Reservoirs

10.2118/204304-ms ◽

2021 ◽

Author(s):

Rencheng Dong ◽

Mary F. Wheeler ◽

Hang Su ◽

Kang Ma

Keyword(s):

Reactive Transport ◽

Transport Model ◽

Viscous Fingering ◽

Carbonate Reservoirs ◽

Acid Etching ◽

Fracture Conductivity ◽

Acid Fracturing ◽

Fracture Surfaces ◽

Etching Pattern ◽

Viscous Fingers

Abstract The goal of acid fracturing operations is to create enough fracture roughness through non-uniform acid etching on fracture surfaces such that the acid fracture can keep open and sustain a high enough acid fracture conductivity under the formation closure stress. A detailed description of the rough acid-fracture surfaces is required for accurately predicting the acid-fracture conductivity. In this paper, a 3D acid transport model was developed to compute the geometry of acid fracture for acid fracturing treatments. The developed model couples the acid fluid flow, reactive transport and rock dissolution in the fracture. We also included acid viscous fingering in our model since the viscous fingering mechanism is commonly applied in acid fracturing to achieve non-uniform acid etching. Carbonate reservoirs mainly consists of calcite and dolomite minerals but the mineral distribution can be quite heterogeneous. Based on the developed model, we analyzed the effect of mineral heterogeneity on the acid etching process. We compared the acid etching patterns in different carbonate reservoirs with different spatial distributions of calcite and dolomite minerals. We found that thin acid-etched channels can form in carbonate reservoirs with interbedded dolomite layers. When the reservoir heterogeneity does not favor growing thin acid-etched channels, we investigated how to utilize the acid viscous fingering technique to achieve the channeling etching pattern in such reservoirs. Through numerical simulations, we found that thin acid-etched channels can form inside acid viscous fingers. The regions between viscous fingers are left less etched and act as barriers to separate acid-etched channels. In acid fracturing treatments with viscous fingering, the etching pattern is largely dependent on the perforation spacing. With a proper perforation design, we can still achieve the channeling etching pattern even when the reservoir does not have interbedded dolomite layers.

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Advanced Fracturing Design Simulator-Assisted Modeling Coupled with Application of Enhanced Stimulation Fluids Raises Performance of Acid Fractured Wells

10.2118/205139-ms ◽

2021 ◽

Author(s):

Ruslan Kalabayev ◽

Dmitriy Abdrazakov ◽

Yeltay Juldugulov ◽

Vladimir Stepanov ◽

Denis Emelyanov ◽

...

Keyword(s):

Single Phase ◽

Viscous Fingering ◽

Low Ph ◽

Transport Processes ◽

Carbonate Reservoirs ◽

Productivity Index ◽

Fracture Geometry ◽

Acid Fracturing ◽

Fracture Simulation ◽

Half Length

Abstract Important factors affecting acid fracturing efficiency include etched fracture geometry, cleanup, and optimum differential etching to retain open channels after fracture closure. A recently applied integrated approach combined improvements in all three factors: new fracture simulation techniques enabled fracture geometry optimization, single-phase retarded acid provided significant increase in half-length, and high retained permeability viscous fluids supported better fracture cleanup. The approach was successfully implemented in several carbonate oil fields and resulted in a substantial productivity index increase. The approach enables acid fracture optimization in three steps. First, the high retained permeability, low-pH pad fluids and polymer-free leakoff control acids are used in combination to enhance formation cleanup after a treatment and to reduce the concentration of polymers in fissures network of naturally fractured carbonate reservoirs. Second, a new single-phase retarded acid is used to achieve longer half-length due to retarded reaction with formation rock and favorable viscous fingering effects. Third, a new acid fracturing simulation model is used to optimize fracture geometry. The simulation technique employs an innovative transport model that includes the viscous fingering effect, advanced leakoff simulation, changing acid rheology upon spending, and a novel calculation approach to mixed fluids' rheology. This combined concept was applied during acid fracturing treatments in moderate permeability wells of carbonate reservoirs with target intervals up to 4,600 m TVD and temperatures up to 125°C. The treatments consisted of guar-free low-pH pad fluid, polymer-free leakoff control acid, and single-phase retarded acid. Treatment optimization was performed using an advanced acid fracturing simulator to properly address the transport processes within the fracture in a low-stress-contrast environment. After the treatments, the pressure transient analysis indicated a strong linear regime for more than 15 hours, indicating effective fracture half-length at least 25% higher than average half-length after acid fracturing in offset wells where the conventional approach had been applied. Post-treatment half-length calculations showed a good match with advanced simulator results and proved the importance of accounting for viscous fingering effects during acid fracture half-length calculations. Calculation of the productivity index from the production data showed at least 15% increase compared to conventional acid fracturing treatments. The post-fracturing production decline rate was at least 20% slower than that of the conventional treatment in offset wells, which can be explained by the longer conductive fracture.

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Analysis of Flow Behavior for Acid Fracturing Wells in Fractured-Vuggy Carbonate Reservoirs

Mathematical Problems in Engineering ◽

10.1155/2018/6431910 ◽

2018 ◽

Vol 2018 ◽

pp. 1-20 ◽

Cited By ~ 1

Author(s):

Mingxian Wang ◽

Zifei Fan ◽

Xuyang Dong ◽

Heng Song ◽

Wenqi Zhao ◽

...

Keyword(s):

Composite System ◽

Numerical Solutions ◽

Transient Flow ◽

Flow Behavior ◽

Outer Region ◽

Carbonate Reservoirs ◽

Single Fracture ◽

Specific Flow ◽

Type Curves ◽

Acid Fracturing

This study develops a mathematical model for transient flow analysis of acid fracturing wells in fractured-vuggy carbonate reservoirs. This model considers a composite system with the inner region containing finite number of artificial fractures and wormholes and the outer region showing a triple-porosity medium. Both analytical and numerical solutions are derived in this work, and the comparison between two solutions verifies the model accurately. Flow behavior is analyzed thoroughly by examining the standard log-log type curves. Flow in this composite system can be divided into six or eight main flow regimes comprehensively. Three or two characteristic V-shaped segments can be observed on pressure derivative curves. Each V-shaped segment corresponds to a specific flow regime. One or two of the V-shaped segments may be absent in particular cases. Effects of interregional diffusivity ratio and interregional conductivity ratio on transient responses are strong in the early-flow period. The shape and position of type curves are also influenced by interporosity coefficients, storativity ratios, and reservoir radius significantly. Finally, we show the differences between our model and the similar model with single fracture or without acid fracturing and further investigate the pseudo-skin factor caused by acid fracturing.

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Factors affecting reorientation of hydraulically induced fracture during fracturing with oriented perforations in shale gas reservoirs

Frattura ed Integrità Strutturale ◽

10.3221/igf-esis.58.01 ◽

2021 ◽

Vol 15 (58) ◽

pp. 1-20

Author(s):

Qingchao Li ◽

Liang Zhou ◽

Zhi-Min Li ◽

Zhen-Hua Liu ◽

Yong Fang ◽

...

Keyword(s):

Shale Gas ◽

Injection Rate ◽

Single Fracture ◽

Fluid Viscosity ◽

Fracture Conductivity ◽

Factors Affecting ◽

Controllable Factors ◽

Initiation Pressure ◽

Shale Reservoirs ◽

Induced Fractures

Hydraulic fracturing with oriented perforations is an effective technology for reservoir stimulation for gas development in shale reservoirs. However, fracture reorientation during fracturing operation can affect the fracture conductivity and hinder the effective production of shale gas. In the present work, a numerical simulation model for investigating fracture reorientation during fracturing with oriented perforations was established, and it was verified to be suitable for all investigations in this paper. Based on this, factors (such as injection rate and fluid viscosity) affecting both of initiation and reorientation of the hydraulically induced fractures were investigated. The investigation results show that the fluid viscosity has little effect on initiation pressure of hydraulically induced fracture during fracturing operation, and the initiation pressure is mainly affected by perforation azimuth, injection rate and the stress difference. Moreover, the investigation results also show that perforation azimuth and difference between two horizontal principle stresses are the two most important factors affecting fracture reorientation. Based on the investigation results, the optimization of fracturing design can be achieved by adjusting some controllable factors. However, the regret is that the research object herein is a single fracture, and the interaction between fractures during fracturing operation needs to be further explored.

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

10.2118/205328-ms ◽

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.

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Study on Acid Fracturing Technology for Carbonate Reservoirs in Ordos Basin

10.1115/1.0005147v ◽

2021 ◽

Author(s):

Lufeng Zhang ◽

Jianye Mou ◽

Shicheng Zhang ◽

Mu Li ◽

Minghui Li

Keyword(s):

Ordos Basin ◽

Carbonate Reservoirs ◽

Acid Fracturing

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Using Advance Acid Fracturing Design to Increase the Production Efficiency in a HPHT Reservoir: A Success Story from Southern Mexico

10.2118/207332-ms ◽

2021 ◽

Author(s):

Frank Figueroa ◽

Gustavo Mejías ◽

José Frías ◽

Bonifacio Brito ◽

Diana Velázquez ◽

...

Keyword(s):

High Temperature ◽

Laboratory Tests ◽

Reaction Rates ◽

Gas Production ◽

Carbonate Reservoir ◽

Fluid Distribution ◽

Acid Etching ◽

Southern Mexico ◽

Acid Fracturing ◽

Fluid Systems

Abstract Enhanced hydrocarbon production in a high-pressure/high-temperature (HP/HT) carbonate reservoir, involves generating highly conductive channels using efficient diversion techniques and custom-designed acid-based fluid systems. Advanced stimulation design includes injection of different reactive fluids, which involves challenges associated with controlling fluid leak-off, implementing optimal diversion techniques, controlling acid reaction rates to withstand high-temperature conditions, and designing appropriate pumping schedules to increase well productivity and sustainability of its production through efficient acid etching and uniform fluid distribution in the pay zone. Laboratory tests such as rock mineralogy, acid etching on core samples and solubility tests on formation cuttings were performed to confirm rock dissolving capability, and to identify stimulation fluids that could generate optimal fracture lengths and maximus etching in the zone of interest while corrosion test was run to ensure corrosion control at HT conditions. After analyzing laboratory tests results, acid fluid systems were selected together with a self-crosslinking acid system for its diversion properties. In addition, customized pumping schedule was constructed using acid fracturing and diverting simulators and based on optimal conductivity/productivity results fluid stages number and sequence, flow rates and acid volumes were selected. The engineered acid treatment generated a network of conductive fractures that resulted in a significant improvement over initial production rate. Diverting agent efficiency was observed during pumping treatment by a 1,300 psi increase in surface pressures when the diverting agent entered the formation. Oil production increased from 648.7 to 3105.89 BPD, and gas production increased from 4.9 to 26.92 MMSCFD. This success results demonstrates that engineering design coupled with laboratory tailor fluids designs, integrated with a flawless execution, are the key to a successful stimulation. This paper describes the details of acidizing technique, treatment design and lessons learned during execution and results.

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