With the current technology, only 3-10% of gas from tight shale is recovered economically through natural depletion, demonstrating a significant potential for enhanced shale gas recovery (ESGR). Experimental studies have demonstrated that shale kerogen/organic matter has a higher adsorption affinity for CO 2 than methane, CH 4 . CO 2 is preferentially adsorbed over CH 4 with a ratio of up to 5:1. This paper examines CO 2 -ESGR in compressible shale during huff-and-puff injection to better understand the parameters controlling its feasibility and effectiveness. A mathematical model will be presented where the CO 2 -CH 4 substitution mechanism is implemented in an injection-production setting representative of field implementation. A single hydraulic fracture surrounded symmetrically by a shale matrix will be considered. During primary depletion, gas is produced from the shale to the fracture by pressure driven flow and gas desorption. The porosity and permeability of matrix reduces due to compressibility. Stopping production and then injecting CO 2 through the fracture and into the shale leads to increase in pressure, causing both the preferential adsorption of CO 2 over CH 4 and the restoration of porosity and permeability. The shale matrix then releases more CH 4 in favor of the more chemically sorptive CO 2 . Restarting production from the well then allows more CH 4 gas to be produced. Experimental adsorption data were used to quantify the substitution parameters while typical field data were used for the operating and geometrical conditions. Additional investigated production mechanisms include gas diffusion and changes in apparent permeability and porosity due to compressibility (addressed in Section 2.3.2). Through a series of simulations, it was found that for the example studied, diffusion contributes the most to the performance of CO 2 -ESGR. Compressibility significantly reduces the matrix porosity and permeability during primary depletion, giving a positive effect to gas recovery. During CO 2 injection, matrix porosity and permeability mostly recovers depending on pressure increase in the reservoir. The gas production seemed little sensitive to fracture permeability. The pore radius, the diffusion coefficient and the rock compressibility, parameters related to flow in the matrix, all affected the performance of CO 2 -ESGR.

Lost circulation is a major contributor to non-productive time (NPT). Any efforts to better understand the factors that lead to it and subsequently identify a suitable cure will translate to tremendous savings of time and money for operators. Conventional materials such as calcium carbonate, nut shells, graphites and fibers are successful in curing many cases of seepage and partial lost circulation. However, there is a practical limit to the concentration of these materials used to combat the most severe losses due to the limitation of pumps and drilling assembly. In porous formations, high fluid loss squeeze pills have seen some success in reducing losses by forming a high compressive strength plug, but these pills do not have a good success rate in large fractures or vugular formations. Such challenges are better addressed by cross-linking pills, but even this solution does not always have a high success rate due to the low compressive strength of the formed plug. The new phase-transforming loss circulation material (PTLCM) was designed to be pumped easily and achieve thixotropic behaviour under downhole conditions, resisting losses in the thief zone prior to setting as a rigid plug with high compressive strength. A setting-control additive ensures the LCM does not prematurely set. The additive is used at a concentration calculated by considering the time required for pumping and the bottom hole temperature (BHT) in the thief zone. After the LCM sets, a high compressive strength solid plug is formed that can resist fluid loss to the formation. The LCM has a high acid solubility of ~95%, making this system a viable option for deploying in reservoir sections, depending on the client requirement and well conditions. This paper describes two recent successful applications deploying this novel technology. Case Study #1: While drilling in sandstone, the well experienced total losses, which presented an immediate challenge to maintain hydrostatic pressure. The operator responded by pumping several conventional pills loaded with a broad particle size range of fibers, granules and polymers. These pills were unsuccessful at healing the losses, so the operator opted to deploy the new technology LCM. The losses were cured successfully with a single application. Case study #2: Wells drilled in the Western Desert have traditionally experienced severe to total losses while drilling fractured dolomite. Frequently, such events have been difficult to cure by conventional means. The only solution has been multiple applications of cement plugs to heal the losses. This case study describes a well with dynamic losses of more than 150 bbl/hr that were healed by spotting one pill through the circulating sub across the thief zone. The losses were successfully cured, allowing the operator to continue drilling.

The highly complex geology of the Sichuan Shale gas play, especially in relation to natural fracture systems at different scales, affects the hydraulic completion efficiency and performance. Ant-tracking-based workflows and borehole image data are regularly used to optimize completion campaigns, but bridge-plug-stuck and screen-out risks are still high. The lack of sufficient understanding and accurate identification of the natural fracture systems are the major challenges to address these engineering risks. Surface microseismic monitoring campaigns were conducted over several wells of the Changning field, Sichuan Basin, China. The surface receivers were placed in a radial pattern to record microseismicity generated by hydraulic fracturing. The failure mechanism of all mapped microseismic events (i.e., strike, dip, rake, etc.) was extracted using a moment tensor inversion (MTI) method. Improved understanding of the natural fracture systems and their influence during the hydraulic fracturing process has been achieved by integrating the regional geological data, pumping data and MTI results. Several hydraulic fracturing cases that stimulated near natural fracture systems were investigated. The microseismic monitoring results show that (i) most of the hydraulically induced fractures located in the vicinity of the natural facture or fault did not propagate along the regional maximum stress direction, (ii) the bridge plug got stuck and (iii) screen-out happened frequently in these areas. Moment tensor inversion reveals that (i) the dominant failure mechanism of the natural fractures different from hydraulically induced fractures, (ii) more than one group of natural fractures develop along different directions. Real-time adjustments of the pumping schedule and bridge-plug settings were conducted to reduce engineering risks based on the improved understanding of natural fractures, which proved effective. The innovation of using surface microseismic monitoring results to improve understanding of natural fractures and reduce the engineering risks in real time represents a key step forward to mitigate natural fracture influence and improve the effectiveness of stimulation.

In this case study, high resolution temperature array data, acquired during a Drill Stem Test (DST), were able to identify and quantify flow behind the liner. Quantifying the flow rate behind the liner between the production zones was of significant value to the operator to reduce the uncertainty in the Pressure Transient Analysis (PTA). The high resolution temperature array was deployed clamped to the outside of the Tubing Conveyed Perforating (TCP) guns, which were used to selectively perforate multiple zones. Using wireless acoustic technology the temperature data were transmitted to surface to enable real time feedback during the DST. A novel thermal heat exchange model was built that could take advantage of the high resolution temperature array data acquired during the entire test. The results of the model were compared to the real data to validate the results and provide accurate flow rate measurements of the flow behind the liner in real time during the test. A sensitivity study on the various model input parameters was also carried out to reduce the uncertainty in the thermal model, the results of which are detailed within the paper. Being able to quantify the flow behind the liner allowed the operator to adjust their PTA results and provided a more robust reservoir model. Typical thermal models in the industry are unable to quantify flow behind the liner in this environment. A new thermal model had to be developed that could take into account the complex heat transfer processes and take advantage of the high resolution thermal array data acquired during the DST. Despite the challenging wellbore environment during the test, the high resolution temperature data were used to provide a robust zonal flow confirmation and rate allocation during the flow periods. Whilst Distributed Temperature Systems (DTS) are gaining popularity in the oil and gas industry, typically the current technology does not provide the high resolution required to be able to quantify flow behind the casing. This new model, when combined with high resolution thermal array data, has wide ranging applications not only during the DST but also in long term completions where monitoring well integrity is a real industry challenge.

Excessive greenhouse gas emission and natural gas shortage need to be tackled urgently nationally and globally. In this context, Carbon Capture Storage and Utilization (CCUS) has been proposed to: (1) mitigate the global warming by removing carbon from the atmosphere and, at the same time, (2) create value/reduce the cost by utilizing them for production. CO 2 Storage with Enhanced Gas Recovery (CS-EGR) is well fit for the purpose of CCUS. This paper analyses the feasibility of CS-EGR in Australia by characterizing reservoir rock and fluid properties from both conventional and unconventional gas reservoirs, and by modelling the process of CO 2 injection, gas production, and CO 2 storage. This paper discusses technical aspects of injection and storage of CO 2 and the behaviours of CO 2 and methane together with enhancement of gas production. Although both conventional and unconventional gas reservoirs are covered, the emphasis is given to the unconventional gas. CO 2 is more preferentially adsorbed to shale or coal than CH 4 , so the injected CO 2 will displace CH 4 which then can be recovered. It is also miscible with natural gas and is good for re-pressurizing reservoir. However, these processes are highly influenced by many factors, such as reservoir temperature and pressure, total organic content (TOC), porosity, permeability, pore size (distribution), injection operation, mineralogy, fracture, fluids and so on. Numerical simulation is a perfect tool to study how different parameters interact with each other and eventually affect the efficiency of CS-EGR. The authors undertake geological and petrophysical characterization of target formations in Australia. It is then followed by numerical modelling which takes consideration of reservoir characterization data and interaction between CO 2 , CH 4 , H2O and rock. The sensitivity analysis investigates the performance of CS-EGR at different scenarios and identifies the critical factors. It is worthwhile to mention that two gas injection methods, gas flooding, huff'n'puff, (or cyclic gas injection), are studied and compared. Based on previous studies, this paper moves a step further by: (1) incorporating reservoir characterization data from Australia gas field in numerical modelling and exploring the feasibility of CO 2 Storage with Enhanced Gas Recovery in Australia; (2) investigating both unconventional gas reservoirs and conventional reservoirs and makes a comparison between them; (3) comparing two injection methods for all different reservoirs; (4) performing sensitive analysis of multiple parameters identified from analysis and literature. CS-EGR is promising in achieving "net-zero emission" for Australia.

The first hydraulic-jet-fracturing multizone completion application was performed in an offshore high-permeability oil well located in the Bozhong oil field in Bohai Bay, China. A detailed case study is presented, highlighting operational challenges and lessons learned from the offshore multizone completion in the Bozhong field. Most offshore high-permeability oilwell completions in the Bozhong field employ tubing conveyed perforation (TCP) followed by frac-packing as multi-zone completions, which is practical in this field. Unlike conventional multizone frac-pack completions, to run perforation guns, the perforating must be completed first, followed by running isolation packers to complete the multizone frac-packing treatments. For hydraulic-jet-fracturing multizone completions, the hydraulic jetting tools are delivered to the target depth using drill pipe; following that, slurry fluid is pumped through the drill pipe to cut through the casing to create fluid flowing channels, which communicate with the pay zone formation. Lastly, the fracturing operation is completed by pumping both proppant slurry through the drill pipe and cleaning fluid through the annulus simultaneously, which creates dynamic hydraulic diversion as functions of isolation between zones. After completing one treatment zone, the tools are pulled to the next target depth, repeating the procedures, until the entire well is complete. After the fracturing treatment, the operator runs production tubing and other accessories, putting the well into production as usual. A detailed completion design and step-by-step operational procedures were prepared based on well data and work conditions to help ensure the effectiveness and safety of the offshore operation. Although some challenges were encountered during the operation, it was overall successfully performed, and significant performance improvement was achieved. After being in production for months, the candidate well has maintained a longer high-production-rate period than the offset wells completed using conventional multizone frac-pack completions. This hydraulic-jet-fracturing multizone completion has proven successful in the Bozhong oil field. The experiences and lessons learned can help benefit future multizone completion optimization for other similar offshore high-permeability oil wells.

Propellant enhancement is a method of increasing permeability through the application of a transient high pressure event to the target formation. As distinct from hydraulic fracturing, propellant enhancement does not involve the application of chemicals or water and consequently does not present the potential for legacy environmental issues. This paper compares the regulatory aspects of propellant enhancement within the states of Australia and also the differences between environmental impacts. A series of propellant enhancements were undertaken for a suite of gas wells in the Surat Basin, Queensland. Propellant charges in the range 18-30 kg were initiated, with deflagration times in the range 500-1,000 milliseconds. The compliance regime for the transport, storage and use of propellant is established under the state’s Explosives Act 1999 as well as the Petroleum and Gas (Production and Safety) Act 2004 and the Environmental Protection Act 1994 . There are three categories of fracturing used to increase permeability: explosive fracturing; hydraulic fracturing; and propellant enhancement. Explosive fracturing applies a very high pressure transient over a period of a few microseconds and can cause local, radial fracturing but with less desired compaction; hydraulic fracturing applies a lower pressure but over a longer period and with greater surface power, resulting in fractures that can extend 200-300 m, largely in the vertical plane; and propellant enhancement, which applies a mid-range pressure over a period of 10-1,000 milliseconds, resulting in fractures extending tens of metres but with random distribution. Residuals from the deflagration process are nitrogen, hydrogen chloride, water and carbon dioxide. There are no precursors for the BTEX suite and no conditions arising that could produce BTEX. A prime question was to determine whether propellant enhancement is captured under the term ‘hydraulic fracturing’ in states’ regulations across Australia. Propellant enhancement is a technology with very few environmental impacts. Vehicular movements to support propellant enhancement are less than five percent of those to undertake hydraulic fracturing on the same formation. There is no requirement for waste water treatment.

The aim of this work is to study shale gas production subject to water blocking in compressible shale. Water blocking is a capillary pressure end-effect causing the wetting phase (e.g. water) to accumulate near the transition from a porous medium to an open medium; in this context, a transition from shale matrix to a hydraulic fracture. Shale is considered a tight porous medium with ultralow permeability, and hydraulic fracturing is essential to obtain economical production. Water is frequently used as a fracturing fluid, but its accumulation at the matrix end-face reduces the gas mobility and can lead to rapid decline of gas production rate. The tight nature of the shale as a porous medium also introduces non-standard flow and storage mechanisms. This work develops a mathematical model that accounts for apparent permeability, compressibility of gas and shale, gas adsorption, Forchheimer gas flow, and multiphase flow parameters like relative permeability and capillary pressure, which depend on wettability. The behavior of the model at steady state production is explored to understand the impact of the various mechanisms.

The fiber-optic distributed temperatrue sensor (DTS) has been used for flow profiling in horizontal multi-stage fractured wells, and there were some reservoir/wellbore coupled thermal models presented by researchers. Although current theoretical models are developed for some certain application scenarios, the industry have realized the great potential of DTS for production prediction in unconventional resources. This paper presents a DTS flow profiling case for a horizontal multi-stage fractured well in tight gas reservoirs with open-hole packer completion scenarios by applying a newly improved theoretical model. In this paper, we started with the conventional semi-analytical wellbore-fracture-reservoir coupled flow/thermal model which have been developed for cased, perforated, and multi-stage fractured wells, and revised it to consider the special feature of openhole packer completion scenario. Since the formation fluid firstly flows through the fracture into the open-hole annular space between formation and the packer liner, then flow along the annular space until meet the frac port on the production pipe, we add a simulation sub-region representing open-hole annular which helps to understand the flow and heat transfer inside it. The presented model successfully simulated the two-fold flow regime caused by the simultaneous flow and heat transmission in the annular space and the production pipe. In each stage, the DTS temperature data possibly show double drops due to Joule-Thompson cooling effects at the fracture and frac port locations if they are not consistent. With the improved mathematical model, DTS monitoring data during a three-rate production test in a horizontal multi-stage fractured well in Erdos Basin of China was simulated and analyzed. The improved model with open-hole packer completion was applied and then the gas rate prediction was accomplished.

It has been reported that hydraulic fracturing treatments with smaller cluster spacing and larger fracturing fluids volumes yield better production performance in Permian Basin, Bakken, and Eagle Ford. Degradable diverting agents can play an important role as temporary plugging materials for multiple, tightly-spaced fracturing operations. However, applications of degradable diverting agents are often limited to moderate to high reservoir temperatures. In this study, a new degradable diverting agent is developed for use in low temperature reservoir applications. Butane-diol vinyl alcohol co-polymer (BVOH) which has controllable water solubility is evaluated as diverting agents for hydraulic fracturing treatments. Using a high pressure-high temperature filtration apparatus, filtration properties of BVOH diverting agents are measured for various powder-to-pellet ratios under a range of temperature conditions. Filter media with 1 to 3 mm width slots, that simulate fracture openings, are used for the filtration test. The filtrate properties are evaluated based on spurt losses and filtration coefficients for quantitative evaluation. An analytical diverting agent model that considers swelling of the polymer in water is also developed for evaluating the filtration process of multimodal particles. The experimental results presented in this work indicate that the degradable BVOH materials can be used as effective plugging agents for fracture-like narrow slits. Based on spurt losses and leakoff coefficients obtained under different powder-to-pellet ratios and temperature conditions, the performance of the diverting agents is quantitatively evaluated. The optimum powder-to-pellet ratio for BVOH materials are determined to be 80 to 20. The experimental results also reveal that the degree of BVOH crystallinity provides a dominant effect on the solubility of BVOH powder. The test results also indicate that the diverting agent plug properties started degrading under the temperature greater than 140°F as designed. The BVOH diverting agent developed in this work provides effective diversion effects under low to moderate temperature conditions (e.g., 80 to 100°F). The analytical plugging and bridging model developed in this work, which takes into account swelling properties of the polymer, show very good matches to the experimental results. The degradable diverting agent developed for low temperature applications improve operational efficiency and economics of multistage hydraulic fracturing treatments in shallow reservoirs and operations where immediate fracturing fluid flowback is required. The plugging and bridging model with bimodal particle system developed in this study helps stimulation engineers select and optimize diverting agent material types, particle size distribution, and diverting agent concentration for various well, stimulation, and reservoir conditions.

Initial hydraulic fracturing of shale oil reservoirs has often resulted in disappointing results, with low connected volumes and productivity degradation with depletion. To improve the single well production and oil recovery, re-fracturing techniques have received increased attention, but face the challenges of economy, applicability and feasibility. In this paper, the propagation mechanism during re-fracturing operations is explored through laboratory experiments. Firstly, mechanical analysis and fracturing simulation experiments were performed using the formation cores. After the fracturing simulation experiment, the fractured core was soaked in supercritical CO 2 to enhance the re-fracturing effect. Then a re-fracturing simulation experiment was performed to analyze the fracturing propagation mechanism. Meanwhile, some new cores are soaked into supercritical CO 2 to explore the changes of mechanical properties under different soak time. The mechanical analysis experiment showed that supercritical CO 2 soak has a strong influence on the uniaxial compressive and tensile strength of shale. With an increase of soak time, both the compressive and tensile strength clearly decreased. During the first fracturing operation, fractures propagated only along the horizontal bedding and could not open the rock matrix. After supercritical CO 2 soak, re-fracturing could open the horizontal bedding more easily as well as extend to the rock matrix, creating a more complex fractured system, enhancing oil recovery.

Pressure transient analysis in fractured horizontal wells in unconventional reservoirs has received much attention in last two decades. A large number of microseismic data showed that many hydraulic fractures do not actually penetrate the entire formation, which means that 3D flow into the hydraulic fractures should be considered. However, there is limited work on analytical method based well-testing models for fractured horizontal wells with 3D flow. To improve this situation, a semi-analytical model for the horizontal well with partly-penetrated multi-state fractures are developed with considering 3D flow, based on fracture discretization. The new model proposed in this paper can describe more complex 3D flows in the multiple hydraulic fractures. With flow regimes analysis and field application, it is found that the pressure derivative curves of fractured horizontal wells with 3D flow are complex. The most obvious feature of the flow regimes is that the curve appears to drop after the linear flow. It behaves like a second "hump" occurs in the pressure derivative curve. This is due to the fact that fractures do not penetrate the formation completely, and a pseudo-spherical flow occurs at this stage. The pseudo-spherical flow is more obvious when the fracture height is small or the fracture is short. Evaluated results from field application are basically consistent with the overall understanding of the MH shale oil reservoirs, which demonstrates the reliability and practicability of the proposed model. The evaluated fracture conductivity is less than an ideal value, because the fracture conductivity declines rapidly with the high reservoir pressure. This work helps to better understand the pressure transient behavior and to facilitate fracture evaluation in the unconventional reservoirs.

Staged hydraulic fracturing in horizontal wells is one of the most popular techniques in developing conventional and unconventional reservoirs, where multiple fractures initiate and propagate simultaneously and then interact with each other. It is shown in hydraulic fracturing practices that these interactions lead to unsatisfactory production performance in many fractures. It is of great importance to develop a reliable hydraulic fracturing simulator that can completely effectively take these interactions into account and predict fracture behavior accurately. We develop a fully coupled 3D hydraulic fracturing simulator with the finite element method, where the interaction between fractures is completely taken into account. We develop a finite element equation to describe fracturing deformation and propagation based on linear elastic fracture mechanics, another one to describe fluid flow and leak-off within fractures, and friction equations to describe the effects of the perforations and tortuosity. We solve these three equations in a fully coupled and implicit way, and obtain fluid pressure, fracture width, and injection allocations between fractures in every step simultaneously. Followed by the method’s verification with experiments, we simulated staged hydraulic fracturing with the coupled finite element simulator and investigated the interactions’ effects. It was found in the simulation that the perforations have the ability to make the injection allocated very even. However, fractures propagate and evolve in very different manners due to the interaction between fractures. Some fractures are far longer than others, while their fracture widths close to the wellbore are far smaller. Due to the stress shadows arising from the fracture interactions, some wellbore zones in the longer fractures never break, and in these fractures their widths around the tip zones are larger than those around the wellbore zones. Insights from the simulations are helpful to understand the mechanisms leading to the unsatisfactory production performance of the fractures, and the simulator can therefore be used to optimize staged hydraulic fracturing.

Lost circulation material (LCM) is commonly used to stabilize formations and inhibit fluid losses from the wellbore during drilling. Mud loss records and wellbore downhole image logs often reveal existence of multiple natural and drilling-induced fractures in the wellbore vicinity. Appropriate particle size distribution (PSD) for the LCM blend should be designed so that lost circulation from all near-wellbore fractures is contained. This paper presents a novel design scheme for multi-modal PSD of LCM blends applicable to the likely cases of lost circulation from multiple near-wellbore fractures. The design scheme takes advantage of an analytical solution which estimates the fracture widths of an arbitrary number of fractures around inclined wellbores when subjected to the three principal stresses of the subsurface. The LCM blend design involves dividing the blend into subcategories of various sub-blends sizes. Each sub-blend has distinct particle size distribution, when combined, satisfying the size distribution criteria on the quantile distribution basis. The fractures apertures widths, which are a crucial input for LCM blend selection, are determined from an analytical solution of the related wellbore geomechanics problem. The solution is derived from the dislocation-based formulation of fracture opening profile in an infinite poroelastic medium. The effects of overburden stress, anisotropic horizontal stresses, wellbore inclination and azimuth as well as the mechanical interaction between the cracks are incorporated in the analysis. Further, a systematic method to characterize mud cake parameter is employed. Mud cake efficiency is shown to cause considerable influence on fractures aperture width and consequent composition of the LCM blend. A synthetic study case mimicking typical depleted sand drilling environments is used to determine the optimal LCM blend design. The poroelastic back-stress effect is considered in the test cases, suggesting substantial changes in fracture initiation pressure and fractures apertures compared to the corresponding elastic solution. Furthermore, the sensitivity of fractures widths to geomechanical parameters is analyzed. The results indicate an interesting interaction between fractures as they induce a compressive hoop stress on one another, limiting the width growth of other fractures. Consequently, the multi-fracture wellbore problem introduces a variation in fraction width, thus causes different LCM sub-blend recommendations tailored to individual fractures. A combination of these sub-blends, each of which only covering a narrow range of fracture width, suggest a novel treatment of fluid loss in multi-fractured wellbore by forming a super-blend which covers the whole range of width distributions.

Defining pressure dependent permeability (PDP) behaviour in coalbed methane (CBM) or coal seam gas (CSG) reservoirs using reservoir simulation is non-unique based on the uncertainty in coal properties and input parameters. A diagnostic fracture injection test (DFIT) can be used to investigate bulk permeability at a reservoir level and at lowered net effective stress conditions. As coal has minimal matrix porosity and under DFIT conditions cleat porosity is fluid saturated with reasonably definable total compressibility values, the DFIT data can provide insight into PDP parameters. At pressures above the fissure opening pressure, pressure dependent leak off (PDL) behaviour increases exponentially with increasing pressure. Many authors have noted that with decreasing pressure PDP declines exponentially with increasing net effective stress. Thus, PDP behaviour can be defined by PDL. In this paper, we show how combined analyses, using typically collected field data, can be used to better define and constrain the modelling of PDP. We illustrate this process based on a well case study that includes the following data: fracture fabric and porosity reasonably defined from image log and areal core studies; DFIT data acquired under initial saturation conditions; hydraulic fracturing data; and longer term production data. These analyses will be integrated and used to constrain the parameters required to obtain a rate and pressure history-match from the post-frac well production data. This workflow has application in other coal seam gas cases by identifying key variables where hydraulic fracturing performance has been unable to overcome limitations based on pressure or stress dependent behaviours and often accompanied by low reservoir permeability values. While this is purposely targeting areas where only typically collected field data is available, this workflow can include coal testing data for matrix swelling/shrinkage properties or other production data analysis techniques.

Channel fracturing becomes more popular as novel method of hydraulic fracturing, with increasingly successful in its implementation. This new method of fracturing, is pulsing proppant into formation instead of just continous pumping as in conventional fracturing. The proppant is mixed with fibrous material, which enables formation to sustain the closing pressure, even with the conductive channel within the fracture; it functions as the pillars of the fracture. The stimulated well is penetrated and producing from poorly sorting conglomeratic reservoir with secondary porosity and muddy micro-porosity; hinderes hydrocarbon flow to reservoir. A well was selected as a pilot well candidate, after reviewing the well test, it reached 230 BOPD. The permeability of the well is 1.78 mD with reservoir pressure of 1188 Psi. Recently, the well produces intermittently 9 to 20 BOPD, assisted by sucker rod pump artificial lift. Initial step is to evaluate the well by using Candidate Selective Factor (CSF), which is based on rock mechanics parameters and stresses within the formation. Afterward, initial design is constructed based on well parameter and its surrounding wells. After the pre-fracturing treatment, which consists of breakdown test, step rate test, and minifrac test, the fracuring operation is re-designed. The re-design includes the special pulsing pumping technique, and then followed by the mainfrac operation. In the actual operation, the proppant was pulsing into formation for eleven times. After channel fracturing, the productivity index of the well increased significantly by 10.3 times with an oil rate of 155 BOPD. Channel Fracturing; a novel technology of hydraulic fracturing; is not only increasingly succesful in its application for giving well production increase, but it also it uses materials that will give less probable of screen out. This method will be implemented in the whole field.

Out-Of-Sequence Pinpoint Fracturing is a conceptual way of maximizing reservoir contact by creating fracture complexity via reducing or neutralizing the stress anisotropy to improve fracture conductivity and connectivity. A complex fracture network is formed by activating planes of weakness present in the form of natural fractures, fissures, faults, joints, and cleats. Branch fractures are created due to the induced stress-relief fractures where they can be connected to the main bi-wing hydraulic fractures to improve fracture network connectivity. Out-Of-Sequence Fracturing is initiated by fracturing Stage 1 (at the toe) and then fracturing Stage 3 toward the heel. Once a desired degree of stress interference between the Stages 1 and 3 (Outside Fracs) is established, Stage 2 (Centre Frac) is placed between the Outside Fracs. The Centre Frac enhances fracture network connectivity and conductivity by connecting to stress-relief fractures from the outside Fracs, taking advantage of the altered stress state. Out-Of-Sequence Fracturing has successfully been tested in Western Siberia (by LUKOIL) and Western Canada in 2014 and 2017, respectively. A fracture model is calibrated using treatment pressures and instantaneous shut-in pressures (ISIP) from the Out-Of-Sequence Pinpoint Fracturing in Western Canada. The fracture model is coupled with reservoir simulation and RTA to evaluate the production potential in Out-Of-Sequence Pinpoint Fracturing and to conduct an extensive sensitivity analysis on petrophysical/geomechanical properties (stress anisotropy, Young's modulus, Poisson's ratio, process zone stress (PZS)/net extension pressure, fracturing gradient, and matrix permeability) and treatment variables (stage spacing, treatment fluid volume/viscosity/rate, and proppant tonnage/size/concentration) to identify the factors that are most critical to optimizing the treatment. The results reveal noticeable production uplift from a carefully designed Out-Of-Sequence Pinpoint Fracturing, which avoids excessive fracture complexity that impedes fracture growth due to pressureout and screenout. Out-Of-Sequence Pinpoint Fracturing is most sensitive to stage spacing, treatment rate, proppant and fluid intensity for the Centre Frac, stress anisotropy, PZS, and brittleness factor (combination of Young's modulus and Poisson's ratio). Screening of these parameters helps identifying well candidates and treatment strategies to avoid both insufficient fracture complexity and excessive fracture complexity, where higher-than-anticipated treatment pressures are observed as an evidence of shear fractures being filled with treatment fluid, causing an additional component of stress that must be opposed by treatment fluid, realizing that higher pressures are only a risk when they are higher than surface pressure constraints. This is the first attempt in pressure history-matching and screening for formation properties and treatment strategies for maximizing Out-Of-Sequence Pinpoint Fracturing benefits. The learnings from this multi-faceted study guide future successful designs of the Out-Of-Sequence Fracturing for completion optimization in unconventional and conventional reservoirs. Rendering a full-length interference effect is possible by conducting an optimized Out-Of-Sequence Fracturing in multiple wells (as part of large-scale field developments) to ensure optimizing the stress shadowing while reducing the risk of well bashing.

Choosing an appropriate technique for upscaling the permeability of the discreet fracture network (DFN) model is vital for maximizing recovery from naturally fractured reservoirs (NFR). Flow -based upscaling is accurate, yet it is computationally expensive. Analytical (i.e. Oda method) upscaling is computationally efficient; however, it is only accurate for well-connected fractures. The objective of this paper is to analyze the performance of the newly developed Oda corrected method which addresses issues associated with previous upscaling methods. This research was executed by using a commercial numerical simulator and by using data set from the Teapot Dome Reservoir. Furthermore, DFN modeling was used to generate different realizations for the fracture network. Consequently, sensitivity analysis was performed through a realisti c uncertainty quantification to generate a base case and 6 different DFN realizations. The main parameters used for this study are fracture length and intensity. Afterwards, the fracture permeability corresponding to each DFN realization was upscaled using the above-mentioned methods. Finally, differences between the upscaling methods were evaluated and analyzed using flow-based upscaling as the criterion. Indeed, the analysis revealed that the new Oda corrected method can calculate the equivalent permeability tensor with adequate accuracy. However, it overestimates the permeability when fracture networks are below the percolation threshold and/or when fractures length is large. Hence, this method is recommended for networks with moderate to high intensity. Furthermore, it has been deduced that fracture length has a great impact on the connectivity of fractures, albeit its effect on permeability is limited by fracturing density. Additionally, it has been found that the length of fractures has an immense impact on the anisotropy ratio and control the occurrence of water bypassing, which were not captured by the Oda method.

Complex reservoirs can be located within clastic and carbonate type environments. This paper reflects the complexity within such and in particular of the clastic family, i.e. sandstones, siltstones. These reservoirs can, on occasion, be associated with limited matrix permeabilities. These permeabilities can be in the range of microdarcies and even as low as nanodarcies with natural fractures (NF) or fissures within the framework which significantly enhance the production levels via secondary porosity mechanisms. In general, the production capability from matrix permeability as identified on their own do not possess sufficient conductivity to keep the reservoir at viable long-term commercial levels of production. Under the conditions where natural fissures/fractures prevail, a situation arises where the induced hydraulic fractures may promote interaction with the natural fracture/fissure resulting in an enhanced fluid leak off, which consequently can arrest the induced fracture and can lead to negative early job screen out. The propagation of the induced fracture will be dependent on the magnitude of stress on the rock itself and the four (4) listed typical types of natural fracture/fissure interactions. Type 1 fractures provide reservoir storage capacity and permeability. Type 2 fractures provide the permeability and the matrix provides porosity. In Type 3, the matrix permeability already provides sufficient primary permeability with the fractures adding additional flow capacity, and Type 4 natural fractures are filled with minerals and provide neither additional porosity nor permeability. The paper will present alternative options to keep these natural fractures/fissures open after frac. Common practice in this environment has included the use of 100-mesh sand pumped ahead of the planned hydraulic fracture to minimize the effect of fluid loss. Typically, this methodology has relative success from the viewpoint of job execution and leak-off control; however, this can reduce the conductivity of vugular spaces within the natural fracture/fissure and rock matrix conductivity, and therefore may influence potential production from the reservoir. It is expected that dilation of the natural fracture and subsequent propping with the placed 100-mesh natural sand is evident for existing open natural fractures. Consequently, there will be losses to the secondary porosity conductivity and the potential ultimate reduction of production of the reservoir. To minimize this effect, a fully self-degrading particulate derived from a natural polylactide polymer (PLA) was used to control the natural fissure interactions and subsequently minimize fluid loss during the induced hydraulic fracturing operation. Since the fully self-degrading particulate-derived PLA technology can control fluid loss into naturally fractured reservoirs while ultimately keeping clean and open fractures without losses in permeability post-induced frac operation, the paper documents the use of three fixed numbers of PLA slugs, pumped ahead of a fracturing stimulation alternating among 1) biodegradable particulates, 2) mixing in defined proportions of 100-mesh proppant particulates, and 3) biodegradable particulates, to allow temporarily plugging the natural fracture spaces without conductivity loss when the fracturing operation is complete. Author informs that the 3 steps of slugs can be reaped with the same fluids anytime that magnitude of Natural Fissures "NF" shows as high density and dips, it is possible increase and or decrease the PLA and natural sand concentrations and volume. The biodegradable particulates completely degrade within a few hours and subsequently leave the natural fracture with fully open, clean pathways for optimum hydrocarbon production potential.

Even with the current development of unconventional reservoirs in the United States, where tens of thousands of wells have been drilled and completed, there is not enough understanding of the production and successful completion drivers in unconventional plays. The Marcellus shale is a naturally fractured formation, and it is vital to account for the natural fractures during a simulation study. A discrete fracture network (DFN) model and a 3D mechanical earth model (3D MEM) were created and used to determine the complexity of the hydraulic fracture geometry. The microseismic data obtained during the hydraulic fracture simulations served to constrain the hydraulic fracture footprint. The proposed workflow uses unconventional fracture modeling (UFM) to predict the propagation of complex hydraulic fracture networks with pre-existing natural fractures and model the stress shadow effect and the lamination effect considering different proppant placement by type within the fracture. Propped and unpropped fracture half-lengths obtained during history matching provide calibration for the UFM. Based on the calibrated model, an analysis of the current perforation efficiency was performed, which showed that almost half of the perforations do not contribute to the production. Optimization of well spacing and cluster spacing was performed on a two-well pad to account for well interference such as fracture hits, stress shadow, and depletion after 30 years of production. The recommended well spacing and completion design improved production by up to 20% per well compared to the initial development plan. The complex approach is becoming a new norm for the successful development of unconventional reservoirs because simple analytical models cannot address well interference issues and account for heterogeneity in the rock properties. The presented workflow can be consistently applied to evaluate well spacing and interference in time for the subsequent wells completed in the Marcellus to help achieve maximum recovery.