Multi-stage Fracture Stimulation Research Articles

Technology Focus: Unconventional and Tight Reservoirs (July 2024)

Unconventional reservoirs bear a unique perplexity in that, at every scale, they are different from their conventional counterparts and even one another. Small nuances in any one parameter can result in a vastly different well result, which may affect how an area, or even an entire play, is interpreted. This month’s selection of papers is all about those differences, in recognition that it is technology that drives innovation through understanding what these differences mean and how best to extract value from these vast resources. Starting at the well scale and looking at the benefits of knowing the efficacy of each stimulation stage, paper URTeC 3864145 is from the Ordos Basin in China. Investigating hydraulic fracture performance on a stage-by-stage basis proves time and time again that understanding the details can improve overall development outcomes. The case study reviews two hydraulic fracture diagnostic techniques used in combination to determine water breakthrough and shutoff plans. Zooming out to the play scale, paper SPE 216292 is focused on the most variable of unconventional reservoirs: the carbonate reservoir. This case study of the Austin Chalk formation in Texas analyses the production uplift from application of horizontal, multistage fracture stimulation technology in tight or fractured carbonate reservoirs. The application of unconventional technology in carbonate reservoirs can extended field life, and the deployment of this technology should be considered for any redevelopment or reassessment of potential resources trapped in tight carbonate reservoirs. Finally, paper OTC 34832 draws on the concept of innovation that is required to unlock unconventional resources. Novel methods of stimulation are the cornerstone of unconventional technology in that well stimulation is a basic requirement of all low-permeability reservoirs. The paper describes a trial pilot from idea through execution from Kuwait Oil Company for enhanced oil recovery in tight formations using downhole hydrogen generation from in-situ exothermic multistage chemical reactions between two unique hydroreacting agents. The paper also provides lessons learned and optimization insights from the trial, concluding that a successful, low-cost alternative stimulation technique was demonstrated and repeatable. Recommended additional reading at OnePetro: www.onepetro.org. SPE 216139 Tight Gas Reservoir Characterization and Comparison of PLT Methods: Microseismic Monitoring, Fiber-Optical Production Logging, and Tracer-Coated Sand Monitoring Applied in the Same Well by Xiao Yao, Petrochina, et al. SPE 216149 New Insight in Developing Tight Fractured Carbonate Reservoirs, Mishrif Formation, West Kuwait by M. El-Jeaan, Kuwait Oil Company, et al. SPE 215712 Successful Utilization of In-Situ Dune Sands in Saudi Arabian Unconventional Frac Operations by Nahar Qahtani, Saudi Aramco, et al.

Study Explores Potential of Carbon Leakage in Denver-Julesburg Basin Wells

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 210256, “Wellbore-Integrity Impact on Carbon Leakage To Ensure Safe Geological Sequestration,” by Yanrui Ning, SPE, and Ali Tura, Colorado School of Mines. The paper has not been peer reviewed. _ In the complete paper, poorly understood leakage potential is researched to quantify the carbon-leakage rate along one legacy well when carbon is injected into a storage formation in the Denver-Julesburg (DJ) Basin. The authors’ results indicate that, for secure carbon sequestration, a good geological storage site should be kept away from wells that have a surface casing depth of 476 ft or shallower and that were drilled before 1994. The effective well permeability highly affects leakage rate, suggesting the importance of estimating the most-representative value or range for this parameter. Introduction To estimate risks associated with geological carbon storage, the National Risk Assessment Partnership (NRAP) Open-Integrated Assessment Model (IAM) tool used in this study presents a modeling approach that can couple efficient reservoir and wellbore components with low computational cost. Two wellbore model components, the open-wellbore model and the multisegmented-wellbore model, were studied to estimate the leakage rate during and after carbon-injection operations. The effective permeability of the disturbed zone outside the well casing is an important parameter in leakage models. However, estimating a reasonable range for the effective well permeability of the disturbed zone remains a challenge. For this study, a more than 1-sq-mile section in the Wattenberg Field of the DJ Basin was used. The goal was to quantify the leakage rate when carbon dioxide (CO2) escapes through a well 1,100 ft from the CO2 injector. First, a reservoir simulation model was built to reflect the pressure and saturation changes during the 30-year injection period and the 100-year postinjection period. This model, based on an ongoing field study, included the CO2 injector, the legacy well that is the potential pathway of CO2 leakage, and the carbon storage formation. Study Area Carbon Storage Potential in Colorado. The top-ranked CO2 emission facilities in Colorado are above the DJ Basin. According to carbon-emission data, 13 facilities in Colorado, including five coal plants, emitted more than 0.7 million tons of CO2 in 2020. All the coal plants are scheduled to be retired by 2034. All eight CO2 emission facilities are in the DJ Basin, with half of those in the Wattenberg Field. This makes the DJ Basin, especially the Wattenberg Field, a good target for carbon storage. The stacked formations of oil and gas reservoirs and saline aquifers in the DJ Basin are potential CO2-storage formations. The current drilling activities with multistage fracture stimulation of horizontal wells target the oil- and gas-producing zones of Niobrara through Greenhorn. These oil and gas producers penetrate the shallower Pierre sandstone formation. This study quantifies the carbon-leakage risk when the Pierre sandstone is the carbon-storage formation and when one nearby Niobrara legacy well penetrates the storage formation and may behave as a potential leakage pathway.

Technology Focus: Hydraulic Fracturing Operations (June 2022)

The recovering global economy, post the pandemic and current geopolitical circumstances, has underscored the reliance on energy to drive global development. Underinvestment in oil and gas projects over the past few years, coupled with a sudden increase in energy demand, has put the onus on oil and gas companies to accelerate the ramp-up of deferred projects. As winter approaches every year, global gas consumption increases exponentially. Because gas is a cleaner source of energy, countries and organizations once solely focused on oil exploration have shifted their strategies to concurrently explore for gas reserves. As a means of meeting the current increase in energy requirements, there is a push around the world to replicate the North American shale-development strategy of long horizontals with multiple hydraulically fractured stages targeting these oil and gas reserves. Low oil and gas prices in the recent past have necessitated a focus on the wider implementation of efficient fracturing technologies, in terms of both operations and production, with the aim of maximizing returns with minimal investment. There has been greater emphasis on moving away from the factory approach and using a more-engineered well-by-well approach. The past decade has seen many technological innovations in the well-completion domain focused on hydraulic fracturing. Within openhole multistage completions, we have seen a wider use of higher-expansion-ratio packers, such as metal expandable packers; fracturing-sleeve configurations, which enable greater stage count in a single well than previously possible; multicluster fracturing sleeves; dissolvable ball and seat technologies; and reclosable sleeves, to name a few. On the other end of the spectrum, when we look at cased-hole completions, we have seen great improvements in pumpdown technologies, dissolvable plugs, and advanced perforation and logging technologies, among other developments. There have also been great advances in fracture propagation and stage-contribution monitoring, moving from traditional radioactive tracers to various nonradioactive tracers, and developments in microseismic and fiber-optic monitoring as well as production-logging technologies. In an environment where we are limited by both surface facilities and subsurface well placement, these technologies have been crucial in trying to better understand the interaction between parent and child wells along with formulating field strategies in new basins. The implementation of machine learning and artificial intelligence in the fracture design and analysis domain, as well as in fracturing equipment operation and maintenance, has led to further optimization in planning and resource management. Some of these technologies can indirectly help us lower the carbon footprint while fracturing. As an industry, we are at a critical point where, along with advancements in hydraulic fracturing optimization, it is important to focus on highlighting our technological achievements and developments through the mainstream media. It is critical to emphasize the efforts of the oil and gas industry in lowering the environmental impact of hydraulic fracturing by using minimal resources and maximizing energy generation to fuel global economic growth. Considering the renewed focus on hydraulic fracturing as a means of meeting the world’s energy requirements, we can expect to see considerable advancement and introduction of new innovative technologies in the near future. Recommended additional reading at OnePetro: www.onepetro.org. SPE 200846 - Novel Application To Recognize a Breakdown Pressure Event on Time Series Fracture Data vs. an Artificial-Intelligence Approach by Alberto Jose Ramirez, Well Data Labs, et al. SPE 201376 - Pumpdown Diagnostics for Plug-and-Perf Treatments by David Cramer, ConocoPhillips, et al. SPE 203284 - Critical Review of Multistage Fracturing Completions and Stimulation Methods by Eyad A. Alali, Saudi Aramco, et al.

The retention and flowback of fracturing fluid of branch fractures in tight reservoirs

A small percentage of the fracturing fluid pumped can be recovered after multi-stage fracturing stimulation in tight reservoirs. One cause for this can be the numerous branch fractures formed at different scales during large volume fracturing. Understanding the retention mechanism and flowback law of fracturing fluid in branch fractures is a key to solving this problem. In this study, we used a leaser macroscope, a low-field nuclear magnetic resonance (NMR) instrument, and a permeability device to scan fracture surface morphology and conduct fracturing fluid retention and permeability regain experiments. Meanwhile, retention mechanisms and the flowback process of fracturing fluid in branch fractures during flowback is considered. The experimental results show that the fracturing fluid present in branch fractures can be divided into free movable water (FMW), restricted movable water (RMW) and retained water (RW). The average proportion of FMW, RMW, and RW in Lucaogou and Longmaxi shale reservoirs in our work are about 0.16: 0.14: 0.7 and 0.1: 0.1: 0.8, respectively. The rougher the surface and the greater the tortuosity of the fracture are, the higher the retention percentage of fracturing fluid in branch fractures is. The main mechanisms of fracturing fluid retention in branch fractures include water film, capillary retention on the fracture surface, and matrix imbibition. The critical T2 of FMW and RMW in branch fractures in the Lucaogou shale reservoir are 25.3 ms and 10.2 ms, respectively. However, they are 64 ms and 3.7 ms in the Longmaxi shale reservoir. During the flowback, FMW and partial RMW gradually flowback to the surface. After this, the permeability regains with the decrease of water retention in branch fractures. This study contributes to understanding fracturing fluid retention mechanism in tight reservoirs and provides guidance for the optimization of fracturing flowback.

Degradation behavior of Mg-4Zn-2Ni alloy with high strength and high degradation rate

To developed a disintegrating fracturing ball used for multi-stage fracturing stimulation, the Mg-4Zn-2Ni alloy was fabricated and subjected to extrusion at the ram speed of 0.1 mm/s in present work. The results indicated that the as-extruded Mg-4Zn-2Ni alloy mainly contained MgZn2, Mg2Ni and MgZnNi (τ) phase. In addition, both the dynamic recrystallized (DRXed) grain size and DRXed ratio increased accompanied with the increasing extrusion temperature. The compressive strength and degradation rate of Mg-4Zn-2Ni alloy extruded at 200 °C were 512.6 ± 4.2 MPa and 619.35 mm/y, respectively, both of which were higher than the current values for Mg alloys of fracturing balls. The results of electrochemical experiments further verified that Mg-4Zn-2Ni alloy extruded at 200 °C has a faster degradation rate. Among the factors that influencing the degradation rate of Mg alloy, the dislocation density and secondary phase were thought as the key role. Galvanic corrosion consisting of the secondary phase and magnesium matrix preferentially occurs in the unDRXed region with high dislocation density. And then corrosion propagate to the DRXed regions.

Intermittent and multi-stage fracture stimulation to optimise fracture propagation around a single injection well for enhanced in-situ leaching applications

Artificial fracture stimulation in host rock formations is a potential technique to improve the recovery efficiency of in-situ leaching mining applications, which is gradually creeping in as an alternative mining method for mineral extraction in low-grade ore deposits. In this study, we report two new methods of fracture stimulation by injecting a modified Soundless Cracking Demolition Agent (SCDA) into a target rock through an injection well as opposed to completely filling the injection well once with SCDA to produce a fracture. The first method, intermittent charging (where the injection well is charged intermittently with SCDA), was found to minimize the amount of SCDA used to fracture a finite rock mass. Experimental results suggest a 22.4% improvement in the efficiency (measured by the area of fracture produced per unit mass of SCDA) of fracturing for intermittent charging compared to continuous charging. Numerical simulations were carried out in conjunction using Particle Flow Code 3D (PFC3D) to understand the underlying mechanics of rock fragmentation during intermittent charging. The simulations reveal that during intermittent charging, an additional bending force is applied to the uncharged regions resulting in a supplementary fracture propagation, which improves fracturing efficiency. The second method, multi-stage charging (where SCDA is injected in two consecutive stages using the same injection well) increases the fracture density of a finite rock mass without the need for multiple injection wells. During stage two injection, the fracture density was increased, first by extending the fractures created during the first stage of injection, and second by creating micro hairline fractures around the first stage fractures. The laboratory experiments suggest that the methods introduced in this study can be used to optimize the fracture network generated in a host rock formation.

Inversion of Downhole Temperature Measurements in Multistage-Fracturing Stimulation of Horizontal Wells in Unconventional Reservoirs

Summary There are still many challenges involved with the quantitative interpretation of downhole distributed-temperature measurements for diagnosing multistage-fracturing treatments in horizontal wells. These challenges include handling enormous amounts of data measured by the sensors in a continuous time and space domain, a ready-to-use fast and robust forward model to simulate temperature behavior, and an efficient algorithm to invert the parameters that are of interest. Because multistage fracturing involves many uncertain parameters (ranging from reservoir properties to treatment design, to fracture geometries and conductivity), the problem becomes extremely complicated when the measured temperature is inverted to a downhole flow profile. In this study we present an approach for combining forward and inverse models to interpret downhole temperature data. Our goal was to improve computational efficiency. Field data from a gas well in the Marcellus Shale were used to illustrate the feasibility of quantitative interpretation of temperature measurement for fracture diagnosis. The forward model used the fast-marching method (FMM). The forward simulation was an order of magnitude faster than the semianalytical model, which is the essential contribution for successfully applying the method in the field case. The improved inversion procedure increased the efficiency of the interpretation. The inversion procedure began with a sensitivity study to select the inversion parameters among various other parameters, such as fracture half-length and the fracture conductivity, and to determine the impact of their uncertainty on inversion. The inversion model used the initial analysis of the temperature gradient to identify the fracture locations with significant temperature changes for interpretation and eliminated the rest of the fracture locations from interpretation. Thus, we obtained a prior estimation of the selected inversion parameters, which was used as an initial estimate for the inversion process. This prior estimation saved significant computation. The inversion was performed fracture by fracture using either parallel computing or sequential computing on the basis of the sensor locations. We began with a synthetic example containing multiple fractures to illustrate the approach and test the procedure accuracy and computation speed. The primary inversion parameter was flow rate, though we also interpreted either fracture length or fracture conductivity when assuming all the other parameters as additional constraints. With an adequate initial estimate, the inverted parameters matched the reference “true value” properly. The inversion process converged with reasonable iterations for each fracture (2–3 iterations). The operation time highlights the advantages of the inversion approach presented in this paper. The guided initial estimation ensured that the gradient inversion approach converged and avoided local minimization. Finally, a field application for interpreting the DTS measurement for the flow profile of the multistage-fractured horizontal well was performed using this inversion method, and it showed encouraging results. The results of our investigation illustrate the procedure feasibility for using temperature data to diagnose a multistage-fracturing treatment. Our proposed inversion model was fast and reliable and provided a promising tool that can be used to quantitatively interpret downhole temperature data.

Pushing the boundaries – deployment of innovative drilling, completion and production technology to advance a deep coal seam play

Following technical success of vertical and deviated wells, Strike Energy audaciously continued to push the envelope while proving the commerciality of the deep coal seam play in PEL96. It was clear that extending the reservoir contact area of the wellbore and using innovative dewatering to significantly increase drainage was prudent. A horizontal well intercepting a vertical well coupled with multi-stage fracture stimulation was selected to achieve that goal. Furthermore, a new application of wide operating range electric submersible pumps would enable dewatering to much lower water rates to avoid running the pumps dry or damaging the fracture network upon gas desorption and breakthrough. Although a wellbore stability issue was encountered during the well construction phase, requiring a modified well trajectory, the horizontal well successfully intercepted the vertical well, reaching planned total measured depth. It also altered fracture stimulation approach to an indirect vertical fracture completion application, whereby fractures are initiated from the interburden layer below the coal seam. A million pounds of proppant was successfully placed in seven fracture stages. During the proppant pumping, diagnostic tools (tiltmeter and microseismic) and chemical tracers were utilised. The real-time microseismic confirmed the propagation of fracture from interburden upwards into the target coal seam. This presents the integration of well performance, subsurface information, past drilling practices and stimulation treatment results to support the decision-making process of a horizontal well construction and stimulation design as well as integration of real-time information to overcome operation difficulties and optimise well delivery. Tracer samplings and ongoing production testing during dewatering are also presented.

Diagnosis of Production Performance After Multistage Fracture Stimulation in Horizontal Wells by Downhole Temperature Measurements

Summary Downhole temperature data that are measured by production logging tools (PLTs) or fiber-optic distributed-temperature sensors are used frequently today to diagnose multistage fracture treatments in horizontal or highly deviated wells. These temperature data, measured at the wellbore during fracturing and post-fracture, provide important transient-flow information that helps engineers understand the process of fracturing and the performance of fractured wells, to optimize fracture design. The interpretation models developed to translate temperature data to flow conditions can be fully numerical simulations or analytical/semianalytical approaches. With reasonable assumptions, analytical/semianalytical models are more suitable for real-time field applications. This paper presents the application of a coupled semianalytical fracture model and a wellbore model to predict temperature and pressure behavior in multiple-fracture horizontal wells during production. The thermal model calculated the heat transfer in the fracture/reservoir/wellbore system, considering subtle temperature changes caused by the Joule-Thomson cooling effects. The results showed that transient temperature behavior is sensitive enough to estimate the fracture-initiation points, the number of created fractures, and the flow profile along the wellbore. We discuss the characteristics of transient temperature behaviors and flow-rate distribution along a fractured horizontal wellbore. The temperature decreases when the gas entering the wellbore is strong at the toe and weak toward the heel and when the fractures are more evenly created along the wellbore because of the fluid mixture inside the wellbore. Two field cases are presented to illustrate the application of the temperature model to understand the fracture/flow distribution. The estimation of flow-rate distribution from the temperature model is compared with the interpretation of flow by PLTs. Although this is a single-phase gas model, we can identify the water sump at certain locations by identifying fast temperature recovery to geothermal value. Flow distribution from the temperature model presents a consistent trend with PLT measurement. It is more sensitive to the fluid entries (fracture locations) and less sensitive to the influence of the flow pattern inside the wellbore when compared with PLTs. This work shows that temperature data can identify fracture locations (fluid-entry points) and estimate flow-rate distribution. Because of the complexity of flow in a multistage, fractured horizontal well, any measurement alone would not be able to provide clear description of the created fracture system. A combination of temperature data with other diagnostic methods will provide a better description of the production performance of such a well.

Maximize Recovery by Minimizing Production Delays and Shut-ins

Technology Update The greatest challenge facing the oil and gas industry, particularly in this low-price environment, is to increase recovery rates. Experts in multiple disciplines across the industry are focusing on it because even a small improvement in recovery factors can make a major impact. To meet this challenge, the industry must do more than look to new, stepchange technologies; it must question current practices. For example, the practice of delaying first production after the multistage fracture stimulation of wells is widely seen as a sound operating strategy. Additional shut-ins, whether intentional or unexpected, are a part of everyday well operations. However, a growing body of evidence shows a negative effect on wellbore connectivity with the reservoir. A recent study examined more than 360 wells in six North American shale plays to determine the effect of production delay and shut-ins (Crafton and Noe 2013). The analyses showed that delaying production quickly damages wells, thus affecting wellbore connectivity and production. A similar result was found for shut-ins, with a strong correlation between the number of shut-ins and incurred damage. One of the mechanisms causing this damage is the energy stored in the fluid/ fluid interfaces in the form of a capillary pressure difference. Historically, the pressure difference has been understood to be relatively small, but in shale plays, it can easily be of the same magnitude as the original reservoir pressure. The study also examined the potential benefit of using a persistent interfacial tension management (pITM) nanofluid to mitigate these negative effects and found that in cases of production delay or shut-in, wells treated with pITM nanofluid showed improved connectivity and production compared with untreated wells. Therefore, the reduction of interfacial tension has the effect of reducing the amount of energy, or pressure drop, needed to allow flow to begin. The Study Methodology To determine the effect of production delay and shut-ins, two metrics were used to compare well performance. The first was the “apparent fracture length,” which describes the degree of connectivity between the wellbore and the reservoir. This value was normalized for proppant weight placed and determined based on flowback pressure and production data, using the reciprocal productivity index approach (Crafton 1997).

Disintegrating fracturing ball used in ball injection sliding sleeve for staged fracturing

Abstract A disintegrating fracturing ball used for multi-stage fracturing stimulation was developed, the decomposable characteristics and mechanical properties of the decomposable material were analyzed, and the ball was tested in both ground pressure test and field operation. The decomposable material is an Mg-based alloy with the density of 1.8-2.0 g/cm3. The decomposable material can be dissolved in KCl solution and the decomposing rate increases with increasing temperature, while the decomposing rate is low in the guar gum fracturing fluid; the compressive strength of the decomposable material can reach 360 MPa, and the material breaks when the deformation reaches 20% with a mixed ductile-brittle fracture. The ground pressure test showed that the ball could hold pressure of 70 MPa and keep for 4 hours under 80 °C, which meant that the sealing performance between fracturing ball and ball seat met operation needs. Field fracturing operation showed that the disintegrating fracturing ball demonstrated high quality performance during the operation and dissolves in-situ after fracturing, which eliminated the operation risk that might be caused by fracturing ball flow-back, thereby decreased production cost and saved operation time.

Characterizing and simulating the non-stationarity and non-linearity in unconventional oil reservoirs: Bakken application

This paper presents an innovative integrated methodology and working procedure for characterizing and simulating the strong non-linear and non-stationary features caused by changes in confined pressure–volume temperature (PVT) properties over time and the pressure-dependent permeability related to inherent pore-throat size, as well as the intervened multiple porous media created by multi-stage fracture stimulation. The complicated physics behind the observed phenomena are explored. More specifically, this paper demonstrates and discusses the following: (1) a new rate-transient analysis (RTA) procedure to infer the stimulated reservoir volume (SRV) and fracture parameters; (2) the impact of the non-stationary feature, compaction effect, and pore-throat related PVT properties on the flow regime and well performance; (3) how to incorporate the non-stationary and non-linear features into the reservoir model; (4) the integrated procedure for history matching, performance forecast, and reserve assessment; (5) several field examples in the Bakken to illustrate the procedure.The proposed procedure has been successfully applied for the following: (1) constructing the non-stationary and highly non-linear simulation models; (2) facilitating the history matching by addressing permeability reduction and PVT property variations caused by compaction and capillary pressure; (3) and ensuring more reliable performance forecasts and reserve assessments.The study shows that the reduction of the bubblepoint pressure could be several hundred psi in the typical Bakken rock; moreover, such reduction continues following depletion via the compaction effect. The compaction effect could impair the matrix permeability by up to one order of magnitude.The study reveals the following: (1) the confined PVT properties could widen the favored operation window, whereas the compaction effect could significantly impair the ultimate reserve of the wells; (2) the RTA-inferred SRV-related parameters are the key input for capturing the non-stationary features; (3) the impact on reserve could be over 50% without addressing the aforementioned non-stationary and non-linear issues.This paper explores several unique phenomena in unconventional oil reservoirs which have not previously been published. The proposed analysis and assessment procedure greatly enhances the understanding of unconventional assets, and we feel it will improve the accuracy of long-term rate and reserve forecasts.

Precise 3D seismic steering and production rates in the Wilrich tight gas sands of West Central Alberta

We evaluate the controls on production performance of the Wilrich tight gas sand play in West Central Alberta, and show that careful steering using 3D seismic to place the wellbore within the upper reservoir is the most important geophysical contribution to production outcomes. Geologic, geophysical, drilling, and production data from more than 20 wells are used in the analysis. The completion and production parameters within the study area are relatively invariant, creating a control experiment relative to other productivity factors. We thus isolate the effects of varying bottom hole pressures, porosity, wellbore length, number of stimulations, mud gas response, gamma ray measurements while drilling, mud weight, curvature, amplitude versus offset (AVO), amplitude versus azimuth (AVAz), velocity versus azimuth (VVAz), and position of the horizontal wellbore within the reservoir. These variables are treated separately and in a multivariate fashion to determine their relative and combined effect on the productivity of the wells. Several methods of statistical evaluation are used to test confidence in the results. The Wilrich sand is approximately 20-m thick, and it was expected that the multistage fracture stimulation would have minimized the importance of vertical permeability variations by adequately accessing the entire vertical reservoir section. Such is not the case; precise placement of the wellbore in the most permeable stratigraphy of the thin reservoir is of material importance. The pressure and porosity strongly affect the production performance, but to a lesser degree than vertical position within the reservoir. This suggests that stratigraphic concerns as they relate to permeability variation can be critical, even in thin fracture-stimulated reservoirs. Interesting relationships were observed between the AVAz and curvature measures, but neither they nor the AVO or VVAz attributes yielded statistically significant correlations to the production data.

Matrix Acidizing Innovation Surpasses Competing Methods in Saudi Carbonate

Technology Update Matrix acidizing is a method of stimulating carbonate reservoirs for oil and gas production. Unlike acid fracturing, matrix acidizing creates conductive flow channels, also known as wormholes, which possess much higher conductivity than the reservoir rock. These conductive channels transport reservoir fluids from within the formation matrix directly into the wellbore overcoming both low permeability and near wellbore damage. In matrix acidizing of moderate to prolific carbonate reservoirs, efficient acid placement is a major challenge, as acid tends to flow preferentially toward intervals with the highest permeability. It can result in overstimulation of these areas, leaving the low-permeability intervals untreated. A significant percentage of matrix acidizing treatments do not meet expectations because of an improper job design and acid placement. In some cases, an increase in water production occurs after a stimulation job as a result of preferential stimulation of high-permeability sections associated with water. Case Study: Khuff Carbonate Khuff is a carbonate formation deposited on a shallow continental shelf in the Ghawar structure of eastern Saudi Arabia. It is divided into four intervals, A to D, with production mainly coming from the two gas-bearing layers: Khuff-B, a tight dolomite, and Khuff-C, a more prolific calcite. Since its initial appraisal in the late 1970s, the majority of Khuff’s development activities have focused on the Permian Khuff-C formation. Extensive heterogeneity in stress, reservoir quality, and reservoir fluids throughout the field, combined with the deep and hot nature of the reservoir, makes effective stimulation of all layers a challenging task. All Khuff gas-producing wells require acid stimulation either by acid fracturing or matrix acidizing to obtain high production rates and sufficient flowing wellhead pressure to be tied into production facilities. Until mid-2011, the majority of Khuff horizontal gas wells were drilled toward the maximum horizontal in-situ stress (σmax) to enhance wellbore stability and achieve the best penetration rates. However, when multistage fracture stimulation is desired and the well is drilled in the max direction, the fractures will grow longitudinally (parallel to the wellbore) and cause potential risk of overlapping with subsequent fractures. Therefore, initiation of the second and third fractures becomes a challenge because of possible pressure communication across the first induced fracture. To avoid fracture overlapping, a well slated for multistage fracturing should be drilled toward the minimum horizontal in-situ stress (emin), which allows transverse fracture growth (perpendicular to the wellbore). Drilling wells toward min often poses challenges, such as wellbore instability and differential sticking, but the improved long-term productivity justifies the strategy.

Analysis and Application of Multi-Stage Fracture Stimulation in Yanchang Oilfield

The continental shale of Yanchang Formation in Ordos Basin is in complex facies. Being high in mud and low in brittle mineral, the reservoir quality is poor. Therefore multi-stage fracture stimulation has been applied there in horizontal wells. The fracture interval in horizontal well is a critical parameter and it has a great influence on the fracture interaction. Since the fracture interaction can directly determine the extent to which the stimulated reservoir volume (SRV) expands, its most necessary to study the mechanism of the effect. For this, a mathematical model based on elastic mechanics would be given. By using this model, we analyzed the influences on the fracturing work. An analysis of field data from Yanchang Oilfield shows that proper fracture interval can take good advantage of the fracture interaction so as to reduce the horizontal differential principal stress. However, exceeded fracture interaction may raise the fracture pressure. So the effect must be controlled by optimizing the fracture interval. To optimize the fracture interval, the results can be used to instruct the application of multi-stage fracture stimulation.

Technology Focus: Tight Reservoirs (October 2011)

Technology Focus Multistage fracturing of long horizontal wells remains the cornerstone for maximizing reservoir contact and drainage in low-permeability reservoirs. Operators are no longer satisfied with the “standard” design methodology of the past. Leading exploration and production companies are beginning to adopt a well-by-well design strategy for drilling and orienting the lateral to optimize the multistage fracturing treatments. As experience continues to grow, engineers develop increasingly more-accurate models and workflows for exploration, development, and production of tight hydrocarbon-bearing reservoirs. Geomechanics, petrophysics, and geophysics are coupled with microseismic, fracture-treatment-pressure signatures, and production data to place, drill, and perforate wells better, all in an effort to maximize production derived from multistage fracture-stimulation treatments. The best effective fracture half-length is not achieved automatically just by putting away millions of pounds of proppant with millions of gallons of water. Perforation strategies and pumping techniques do affect proppant placement for enhanced fracture conductivity. Hydraulic-fracture conductivity also is influenced by near-wellbore and far-field issues. Several papers indicate that production may increase significantly if actions are taken to address these issues. As our industry enjoys the privilege of developing these reservoirs, it is incumbent upon us to meet environmental challenges, comply with regulatory requirements, and ensure public trust. Tight Reservoirs additional reading available at OnePetro: www.onepetro.org SPE 144279 • “Shale-Gas Developments in North America: An Overview of the Regulatory and Environmental Challenges Facing the Industry” by S.L. Sakmar, University of San Francisco Law School. SPE 141597 • “Polymer Chemistry Improves Productivity in Tight Gas Hydraulic Fracturing” by Rick Hutchins, SPE, Schlumberger, et al. SPE 142040 • “Optimization of the Design of Transverse Hydraulic Fractures in Horizontal Wells Placed in Dual-Porosity Tight Gas Reservoirs” by S.E. Gorucu, Pennsylvania State University, et al. SPE 143304 • “The Effect of Fracture-Face Matrix Damage on Productivity of Fractured Wells With Infinite and Finite Fracture Conductivities in Shale-Gas Reservoirs” by Boyun Guo, University of Louisiana at Lafayette, et al. SPE 140555 • “Design of Multiple-Transverse-Fracture Horizontal Wells in Shale-Gas Reservoirs” by Bo Song, Texas A&M University, et al.