Optimization of conductive fracture area is perhaps the most critical tenets of fracture stimulation. Several attempts have been implemented to improve the effective fracture area, such as hybrid fracturing, ultra-lightweight proppant (ULWP) delivery, channel fracturing, and slug fracturing. The techniques are all based on viscosity-governed proppant transport mechanisms. This paper presents a new fluid system, based on packing of soft particles, for nearly perfect proppant suspension to improve proppant transport and vertical distribution in fractures. Proppant particles are trapped in the "void" space created by particles packing against each other, and the mechanism is completely different from that of conventional fracturing fluids. It improves effective fracture height by placing proppant across the complete productive interval under downhole conditions when properly applied. This leads to better transverse and vertical placement of proppant in the fracture and significantly increases the fractured surface area. The fluid was tested extensively in conventional fracturing fluid protocols to confirm its feasibility because, mechanistically, it works completely different from conventional fluids. Hydration tests show that the hydration rate can be tuned to maintain the particle integrity during fracturing treatment. HPHT rheology tests show that the fluid is compatible with conventional fluid additives. Static proppant settling tests show superior proppant suspension capabilities. The fluid can be decomposed with live and encapsulated oxidizer breakers to meet treatment design requirement. The fluid can be completely cleaned up and regained proppant pack conductivity was close to unity. Interesting fluid behavior was observed during large scale slot cell testing at room temperature. The fluid was successfully applied in the Cotton Valley and it was confirmed that the novel fluid can be smoothly pumped through fracturing equipment and it also offers several operational benefits. Criteria and considerations for successful application of such fluids to optimize proppant placement and maximize fracture conductivity are discussed. Job design is elaborated in terms of fluid mechanics and proppant transportation mechanics differences and benefits over traditional crosslinked gel systems. The execution, experiences, and subsequent well performance of treatment applications results are compared to offsets treated with a traditional crosslinked gel system.

Non-uniform fracture aperture not only might affect initial reservoir fluids in place, but also production behavior. In addition, previous lab experiment has already demonstrated the importance of nonuniform aperture on permeability and residual oil distribution. This study investigates the impact of aperture averaging techniques on production performance of complex fracture networks in unconventional liquid reservoirs through fracture generation, unstructured gridding and reservoir simulation of hydraulically fractured horizontal wells. First, complex fracture networks are generated from microseismic-constrained stochastic algorithms. We reduce uncertainties of natural fracture length, center, and strike distributions by incorporating outcrop analysis and microseismic event locations. Hydraulic fractures are generated by randomly connecting natural fractures and by honoring material balance equations. Then, stress-dependent nonuniform fracture aperture distributions were taken from previously CT-scanning experiment. Moreover, in order to evaluate production performance, nonuniform apertures are sampled from the lab-measured lognormal distributions and then populated along complex fracture networks. Nonuniform aperture is explicitly gridded up and discretized using unstructured grids for reservoir simulations. Finally, numerous aperture-averaging techniques are investigated considering whether or not to honor input fracture conductivity distributions. Numerical simulations show that the same aperture distribution yields similar cumulative oil curves. With the increase of overburden stresses, the lab measured lognormal aperture peaks shift to the left. Correspondingly, it is observed decreased cumulative oil production. In addition, if fracture conductivity remains the same, the cubic law–based averaging approach yields the best production performance. If the fracture conductivity is not kept the same, the arithmetic averaging method provides us with the best production performance, which is followed by the base, geometric and harmonic cases. This paper demonstrated how to simulate production performance of stress-dependent nonuniform aperture in complex fracture networks. The crucial impact of nonuniform fracture aperture and averaging techniques are highlighted through comparison with the uniform fracture aperture.

Stimulated reservoir volume (SRV) has become the key means to the development of shale gas, and the natural fractures influence the complex of fracture network of SRV, significantly. However, currently, the researches on natural fractures are still focus on the geological description and the reservoir simulation, theoretically. Also, on the shale core experiment study, the influence between natural fractures, shale fracture characteristics and the change of the permeability is still unclear. In this paper, the Wufeng (O 3 w)-Longmaxi(S 1 l) shale crop was taken to experimental study, which belongs to the Ordovician-Silurian formation in Fuling, Chongqing City, China. After the standard cylinder specimens were prepared, the natural fractured shale specimens were selected for the experiments by using the acoustic wave velocity test and manual evaluation. And then the CO 2 steady-state method was used to measure the permeability of shale specimens under the triaxial compression condition until the specimen was damaged. At the same time, acoustic emission was monitored to measure the generation of fractures. After the experiments, the failure modes and the fragment distribution were studied, systematically. The results reveal that: (1) the natural fractures reduce compression strength of the shale by 26.1% to 46.6%, and piercing cracks influence that significantly. (2) During the triaxial stress loading, different distributions of natural fractures affect the permeability of shale, obviously, and the effect trends are divided into the following three groups. In Group 1 (with a long piercing fracture), the initial permeability is high (0.7 mD), then decreases to 0.12 mD, due to the macro fracture is compressed; but when the specimen breaks, it increases to 2.0 mD. In Group 2 (with some small natural fractures), the permeability decreases and then increases, due to the compression and newly-generate of fractures; when the long piercing crack appears, the permeability increases to above 0.7 mD like that in Group 3. In Group 3 (without macro natural fractures), the permeability is too low to measure (nD) before the specimen damaged; but when the specimen damages and forms a long piercing crack, the permeability increases like that in Group 2. (3) There is a close relationship between natural fractures and fracture morphology: in Group 1, the specimen is broken into several larger pieces along the piercing natural fracture. in Group 2, the specimen is broken into many (more than 50) small and uniform pieces; in Group 3, the specimen isn’t broken completely and the scale of pieces is non-uniform. Based on the triaxial compression experiment and permeability measurement, the change of mechanical characteristics and permeability are studied in the triaxial compression process of shale; that offer relative experimental basis and required parameters for the studies of fracture propagation mechanism, flow mechanism and the fracturing design program in the natural fractured shale gas reservoirs.

Up to 2014, low production wells of CNPC oil fields account for 10%~30% in all the production wells, the number of old wells is huge. How to develop the low production wells effectively is one of the key research aspects under such low international oil price, and old wells re-fracturing is an important mean to improve single well recovery and reduce the cost. In this paper, we took tight oil wells for example; stress distribution of more than 100 wells was studied. Finite element analysis software COMSOL was used to simulate the in-situ stress and induced stress distribution by production effect. The equations of induced stress distribution by fracture net pressure were derived, stress distribution by production effect and induced stress distribution by fracture net pressure was coupled, and the re-fracturing stress distribution software was programmed. The calculation results show that: in-situ stress distribution will be changed by production effect as wells produce, but for tight oil formation, stress change by production effect is little because seepage flow rate is very slow. Stress change becomes large at first and then becomes small; so there is a change extreme point - optimum re-fracturing opportunity. Re-fracturing has a critical re-orientation fracture net pressure, the stress variation locates in the weak stress reversal region under the critical pressure, it is difficult for re-orientation; above the critical pressure, the stress variation lies in the strong stress reversal region, re-orientation could occur. Taking x well for example, after 10 years production, Stress change is small when fracture net pressure is under 3.5MPa, it locates in the weak stress reversal region. Stress change increases as fracture net pressure increases when net pressure is above 3.5MPa, but the increase amplitude stress change is reduced, and the re-orientation radius is 53m when fracture net pressure is 3.5MPa. Stress distribution with time at critical re-orientation fracture net pressure shows that: Stress change becomes large at first and then becomes small, the change extreme point- optimum re-fracturing time is 1-5 year, the re-orientation radius is 63-78m under optimum re-fracturing time, the stress distribution locates in the weak stress reversal region after 10 years production and re-orientation becomes difficult. The critical re-orientation fracture net pressure drops dramatically under optimum re-fracturing time, and the re-orientation radius under same fracture net pressure is obviously longer than that of non-optimum time. Furthermore, re-fracturing candidates under optimum time were screened, temporary plugging agents improving fracture net pressure were selected preferably, and 15 wells stimulation were guided based on the simulation results, 25-100Kg temporary plugging agents were added for each candidate. The treatment pressure was improved by 4.0-10.0MPa, fluid production was improved by 2.15 times and oil production was improved by 3.5 times. The re-fracturing stress distribution software can provide basis data for re-fracturing candidates screening and temporary plugging agents selection, and it is beneficial for old well re-fracturing and new technologies exploration under low oil price.

Proppants are placed in fractures to provide highly conductive paths for hydrocarbons to flow from the reservoir to the wellbore. Hydraulic fracturing technology is constantly improving to achieve better production performance. Ultra-lightweight (ULW) proppants are one of the technologies introduced to improve fracturing effectiveness. Compared to sand, ULW proppants can be carried farther and distributed more evenly within fractures, resulting in more propped fracture area. This paper evaluates the impact of ULW proppants on production performance in tight reservoirs and examines characteristics of formations where ULW proppants are most beneficial. To explore the advantages of ULW, hydraulic fracture models are developed. These models help in understanding the fracture geometric properties. This information is then incorporated into reservoir production models to evaluate the impact on production performance. Fractures using ULW proppants and the resulting well productivity are compared to those using sand. No technology provides a solution for all situations, and neither do ULW proppants. To better understand if ULW proppants bring the most benefit for production performance, data-mining techniques were used to identify ULW proppant field applications. Results showed that ULW proppants had better vertical distribution within the fractures than sand (sand had a tendency to settle to the lower part of fractures, leaving the upper part unpropped). In a thick reservoir formation with insufficient vertical conductivity, fractures created by ULW proppants connected larger volumes of rock, leading to higher well productivity and increased EUR. This study discusses the benefits that ULW proppants can bring to unconventional producers and identifies potential candidate formations where ULW proppant may be very effective. Field cases are included to show the benefits of ULW and the circumstances where they can bring the most value.

Multi-stage fracturing is currently the most effective method to exploit tight sand reservoirs. Various analytical models have been proposed to fast and accurately investigate post-fracturing pressure- and rate-transient behaviors, and hence, estimate key parameters that affect well performance. However, these models mainly consider 2D flow, neglecting fluids flow from upper/lower reservoir when vertical fractures partially penetrate the reservoir. Although for linear flow model, Olarewaju et al. (1989) and Azari et al. (1990 , 1991 ) have studied the effects of fracture height, they merely used a skin factor. Moreover, reservoir heterogeneity is seldom included. This paper presents an analytical model for multi-stage fractured horizontal wells (MFHWs) in tight sand reservoirs, accounting for upper/lower reservoir contributions, reservoir heterogeneity and threshold-pressure gradient (TPG). The model is extended from "five flow region" model and subdivides the reservoir into seven parts including two upper/lower flow regions, two outer flow regions, two inner flow regions and hydraulic fracture flow region. Reservoir heterogeneity along the horizontal wellbore is considered, thus, the fracture distribution can be various, and fracture pattern optimization strategies are documented. Fracture interference is simulated by locating a no-flow boundary between two adjacent fractures. The exact locations of no-flow boundaries are determined based on boundary's pressure which is a function of time and space. Thus, the no-flow boundary has minimum pressure difference between its two sides during the well production, making the no-flow assumption reasonable. The experimentally observed TPG and pressure drop within the horizontal wellbore are included. Modeling results are compared with those from well-testing software KAPPA Ecrin, obtaining a good match in most flow regimes. Specifically, the effects of upper/lower reservoir contributions and TPG are studied under constant-rate and constant-pressure conditions respectively. Log-log dimensionless pressure, pressure-derivative and production type curves are generated. Results suggest that fracture penetration ratio dominates the early-middle time pressure response. The start time of boundary-dominate flow are significantly influenced by penetration ratio. The larger the penetration ratio is, the earlier boundary-dominate flow regime will arrive. As for production response, with penetration ratio increases, the early dimensionless rate becomes larger, indicating higher flow rate, however, the late-time (t D >10) production becomes smaller, that is, the production declines quicker when penetration ratio is large. When TPG is considered, differences in both pressure and production response mainly appear in middle-late time. Greater TPG results in higher pressure drop and accelerates production decline. But this influence is marginal when TPG is small (TPG<0.4psi/ft). Effects of other relative parameters, such as formation permeability, heterogeneity, fracture length, conductivity, and wellbore storage are systematically investigated. Besides, field data are analyzed and compared graphically, using type curve matching, and reliable results are obtained. Low CPU demands and minimal data requirement of this model enable the operators to predict well testing results under different fracture patterns in a simple but effective way.

Hydraulic fracturing and horizontal well drilling technologies have enabled the oil and gas industry to safely unlock large reserves of oil and gas in unconventional resources, especially in shale gas and oil, and tight gas and tight oil reservoirs. However, there is an ongoing debate on whether "the best practice" is to drill a horizontal well in the direction of minimum horizontal stress, which would create transversely fractured well or to drill the well in the direction of maximum horizontal stress, which would create longitudinally fractured well. Additionally, little work has been done to understand the complex relationship that exist between principal stresses, well azimuth and/or lateral direction. This paper presents the results of a comprehensive multiphase flow study that investigated the relationship between the principal stresses and lateral direction in hydraulically fractured horizontal wells, and its impact on well performance. Secondly, the study also incorporated previous studies, where applicable, of a single phase flow study that was conducted by the co-authors of this paper. Both studies focused on transversely fractured wells versus longitudinally fractured wells, and how well azimuth affects productivity, reserves and economics of horizontal wells. The previous study primarily focused on wells that produced single phase fluids, and used single phase reservoir numerical models to study well performance. The study investigated the importance of lateral direction as a function of reservoir permeability, lateral length, fracture-half length, number of fracture stages, fracture conductivity, and well completion type (open-hole vs cased-hole). The Single phase study also included a number of actual field cases where the results were compared to actual wells in both oil and gas reservoirs that had transversely fractured or longitudinally fractured horizontal wells. This study would extend the findings of the single phase flow study by adding multiphase flow dimensions such as effects of relative permeability, non-Darcy flow, adsorption gas, stress dependent permeability on induced fractures and conductivity changes in the fracture from the tip to the wellbore. The study used black oil reservoir simulator to study two phase flow mechanisms such as gas-water (dry gas reservoir) and under-saturated oil reservoir (oil-water), and compositional reservoir simulator to model three-phase flow (oil-gas-water) to investigate each parameters' impact on well performance. This study is unique as it examines the permeability ranges from wells with 1 Nano-Darcy (0.000001 md) to 10.0 milli-Darcy in a multiphase flow reservoir simulation. Additionally, this paper presents the first multiphase flow study that thoroughly compared the performance of transversely fractured versus longitudinally fractured horizontal wells. Key features of the study that would benefit the petroleum industry are; Methodologies for modeling shale gas and shale oil wells with stress dependent permeability, adsorption gas and non-Darcy flow effect using black oil models and compositional reservoir simulators. Reservoir permeability based cut-off criterion that can be used as guide when selecting whether to drill transversely fractured vs longitudinally fractured horizontal wells. Integrating the reservoir objectives and geo-mechanical limitations into horizontal well completions and stimulation strategies. Incorporate the effect of reservoir fluid type and fluid properties such as oil composition and density (API) into the decision analysis when comparing transverse horizontal wells to longitudinal horizontal wells. Stimulation optimization strategies focused on well recovery, productivity and EUR as function of hydraulic fracture spacing (or number of fracture stages) and reservoir permeability

For the oil reservoirs with permeability less than 10×10 -3 μm 2 , the recovery rate is unsatisfactory because of poor reserve abundance, low pressure, low injection rate and high initial water saturation. This paper discusses the necessity and rationality of injection well fracturing, and optimizes the well spacing and fracture length of the production and injection well in extra low-permeability oilfields. The production wells are usually fractured for higher yield, however, injection wells are rarely fractured. Mass data from field practice are analyzed in this paper. Changqing, Daqing and Jilin oilfield have all witnessed the journey of square inverted nine-spot well pattern, diamond shaped inverted nine-spot well pattern, square five-spot well pattern, rectangular well pattern, and linear injection pattern. The sweep efficiency and water flow direction are confirmed by core data in lab from 9 infill wells in a square inverted nine-spot well group in Changqing oilfield. Good agreement is obtained with field observations and lab. Using oil reservoir engineering method and numerical simulation with the Non-Darcy flow, this paper describes the optimization well pattern with injection and production wells fracturing. After water flooding in the conventional areal well pattern, the injection water will flow toward the direction of the maximum principle stress, and finally forms the linear water injection, resulting in the low oil recovery due to the heterogeneous lateral water flooding. After a near 30-year water flooding development, the core data from 9 infill wells have proved the vertical sweep efficiency achieved only 50%, while the plane sweep efficiency 60%. Both water injection rate and oil production decrease with the increase of water cut. However, as water injection channel is formed with injection well fracturing, lateral water flood will displace homogeneously from the row of water wells to the row of oil wells. The injection wells fracturing increase the perforation and the injecting efficiency. Through the optimization of wells and the fracture length with the numerical simulation, an effective displacement pressure system is established for extra low-permeability oilfields. Compared with the adjacent area, Zhaozhou oilfield pilot tests were carried out according to the simulation studies and have achieved encouraging results in Daqing oilfield. The novelty of injection well fracturing is in the ability to improve the injection efficiency and displace homogeneously toward the channel designed. The higher injecting efficiency is, the less injectors, well spacing density, and cost will be required, which properly serves the situation of low oil price.

Shell and PetroChina are partnering in a pioneering Joint Cooperation Project in the Sichuan Basin targeting the Lower Silurian Longmaxi shale gas play. Since 2010, over 20 wells, including both verticals and horizontals, have been drilled and completed with various hydraulic fracturing technologies. Unlike most of the North American shale plays, the Sichuan Longmaxi shale play is characterized by abnormal formation pressure, closure pressure close to overburden, low stress anisotropy, and regionally active tectonics, all of which contribute unique challenges to hydraulic fracturing stimulation. The combination of these geological challenges results in high treating pressures, difficulty in proppant placement, constrained fracture height growth and complex fracture geometry. Under such subsurface complexity, an optimal completion design requires insightful understanding of the geological settings and reservoir characteristics, as well as a large number of wells for technology trials in a "trial and error" approach, which often results in a large capital investment and a long value realization cycle time. To meet these challenges, an advanced workflow that integrates geomechanics modelling for hydraulic fracture simulation and 3D reservoir modelling for well performance using reservoir simulator is developed in collaboration with Shell global experts in unconventional resources. This workflow provided a much more economical and efficient solution in understanding the reservoir responses to hydraulic fracturing, quantification of estimated ultimate recovery (EUR) ranges, and potential maximum EUR uplift by increasing completion intensity or technical limit EUR. The geomechanics modeling workflow ( Bai et al. 2016 ) is a truly 3-D hydraulic fracture simulation platform that integrates structural framework, stress setting, formation characterization, flow dynamics, hydraulic fracturing monitoring, and well completion parameters into a finite-element based modeling environment. Key capabilities that distinguish this platform from conventional hydraulic fracture simulators are the ability to model complex fracture initiation and propagation as a consequence of natural fracture systems, hybrid stress regimes, and formation heterogeneity. Once calibrated with hydraulic fracturing field diagnostics, the model performs hundreds of numerical runs accounting for multiple subsurface realizations and well completion design scenarios. The optimized well completion design is selected based on the modelled Stimulated Rock Volume (SRV) that corresponds to increased EUR at optimized costs. Two suites of models were built for this study, each of which represents key play segment in the concession block in terms of profitability and materiality. EUR uplift potential is identified through optimizing well placement and completion design, such as well orientation, landing interval, pump rate and job volume, perforation spacing, and stage spacing. With the hydraulic fracture or SRV geometries derived from the geomechanics modelling, the reservoir simulation workflow was then performed to evaluate EUR uncertainty and estimate the EUR uplift based on geomechanics modeling results hydraulic fracture or SRV geometries from both the reference and optimized cases. These derived hydraulic fracture geometries and their corresponding SRVs were built in the reservoir simulation model and history matched to generate EUR ranges through multiple-realizations.

With the recent development on several shale gas plays in the Sichuan Basin, shale gas has emerged as one of the viable and economical energy options in China. The drilling and completion practices are mostly echoed the success of shale gas developments in US, and hydraulic fracturing treatments are primarily dominated by slickwater owing to its low cost and benefit in maximizing the stimulated reservoir volume (SRV). However, these shale plays are usually in high tectonic stress environment, complex in geological structures and usually with rich natural fractures, which are quite different from most of the plays in US with relatively simple structure and more relaxed stress environment. Thus, critical design parameters for hydraulic fracturing that drive the production performance still remain unclear with the lack of integrated production evaluation. Although microseismic mapping results were widely collected and used for the SRV estimation and post treatment evaluations, it cannot provide the insight of effective SRV or underlying production mechanisms because of the uncertainty in correlating micro-seismicity with hydraulic fracture propagation and proppant placement. A direct production comparison with different treatment types and design strategy would often lead to inappropriate conclusions due to too many variables involved in reservoir quality, stresses, completion design and flowback practices. Thus it is necessary to apply an integrated approach to obtain a thorough understanding of production performance in relation to fracturing design and flowback management. This paper discusses an integrated workflow that incorporates all the valuable data into production evaluation, and presents the detailed analysis on the horizontal wells in Longmaxi shale gas reservoirs in Huangjinba block. The workflow starts with the use of 3D geological models to build numerical reservoir models that honor key features of reservoir heterogeneity, and advanced fracture modeling to integrate 3D geomechanics and microseismic results into fracture simulations and provide inputs to reservoir models for production history matching. The study revealed the stress sensitivity in all the wells in which the fracture system starts to deteriorate when the effective stress reaches the critical value, resulted in many perforation clusters not contributing to production due to the loss of connectivity to wellbore. This leads to an important conclusion that fracture conductivity is equally important as the SRV for such a high stress shale gas play, and the treatment strategy shall be recalibrated from current slickwater treatments that do not provide sufficient fracture conductivity due to low proppant concentration as well as challenges of proppant placement experienced in many stages. This study has provided a much better understanding of production mechanism and effectiveness of stimulation treatments, as well as a list of design changes and actions on the flowback management to overcome current production challenges.

Low to ultra-low permeability tight oil reservoirs have recently become a significant source of hydrocarbon supply in North America, Production and pressure transient analysis of tight oil reservoirs is one of the most difficult problems facing a reservoir researcher because of the extreme complexity inherent in tight formations, To produce oil and gas commercially from tight formations, naturally completed (open-holed) or cased horizontal wells with multi-stage hydraulic fractures are the most popular implementation for completion, and such kind of application is expected to create a complex sequence of flow regimes ( Chen and Raghavan, 1997 ; Clarkson and Pederson, 2010). The proper analysis and identification of presence of flow regimes and sequence of emerging flow regimes are essential for obtaining efficient information about hydraulic fracturing optimization and the tight formation characterization. This paper provides a detailed discussion of numerical method of pressure transient and rate responses for hydraulically fractured horizontal wells in tight formation and compared with analytical (semi-analytical) methods based on the Bakken and Viking Formation in Western Saskatchewan. For Numerical simulated pressure transient responses, a naturally-completed (open-hole) and cased horizontal well with multiple transverse hydraulic fractures in a homogeneous or a sizable natural fracture system are considered. Numerical method for pressure and rate transient analysis is generated by employing a commercial reservoir simulator, CMG IMEX, a 3D finite-difference reservoir simulation package which is widely and popularly accepted by petroleum industry. As noted by many findings, it is shown that fully-filled and regional natural fractures would display various pressure transient characteristics and, hence, considerably affects well production performance. In addition, these conductive, interconnected natural fractures dominate the pressure transient performances of horizontal wells in tight formations even with the presence of hydraulic fractures. Additionally, the simulation runs also indicate that if the reservoir is naturally fractured to some extent, hydraulic fracturing stimulation might not improve productivity significantly, unless a large amount of hydraulic fractures and infinite conductivities can be achieved. To demonstrate the feasibility of numerical simulation models, there is a representative contrast between numerical and analytical (semi-analytical) methods. To demonstrate the feasibility of numerical simulation models, there is a representative contrast between numerical and analytical (semi-analytical) methods.

Chemical tracer is an alternative technique for hydraulic fracture diagnosis other than tiltmeter and microseismic mapping. Fracture volume is an essential parameter for stimulation optimization and production forecast. In our previous work, we proposed a simple, cost-effective method to assess the fracture volume using partitioning chemical tracer. In the hydraulic fracturing stage, a partitioning chemical tracer slug is injected along with the fracking fluid. In the created hydraulic fracture, the tracer partitions in both vapor and liquid phases and flow back in the production stage. By analyzing the tracer production data, we could estimate fracture volume and leak-off volume. This work will first investigate chemical tracer selection criteria for the purpose of fracture volume diagnosis. Tracer partition coefficient and tracer adsorption are the main considerations. Our results suggest a careful section is needed for partition coefficient, balancing the estimation accuracy and investigation area. In addition, the selected tracer should have negligible adsorption. Numerical simulation is another way to interpret tracer test. In the second part of this paper, we propose a modified Random Walk Particle Tracking (RWPT) algorithm to simulate the partitioning chemical tracer transport with multiple mobile phases. Output obtained through the RWPT is identical with analytical solution and its tracer critical breakthrough time is more accurate than the result from the finite-difference based simulations.

Low permeability oil and gas-bearing carbonate formations are routinely completed with open hole horizontal laterals and multistage fracturing treatments to achieve maximum reservoir contact and enhance production of the formations. This completion technique has been successfully used in previously non-economical reservoirs — in North America and around the globe — to make them commercial. Open hole multistage fracturing technologies have been deployed in tight gas carbonate reservoirs to improve well productivity while using reservoir simulations to optimize the fracture design. When applying multi-stage fracturing one of the key aspects is to assure the isolation between the stages to induce independent fractures. This goal becomes even more challenging to achieve when the process is an acid fracturing treatment. Hydraulic communication between the fracture stages has been previously observed, which has prevented the creation of separate fractures transverse to the wellbore, thereby resulting in fewer and shorter fractures, mostly created along the wellbore plane. In many cases, new fractures could not even initiate and only matrix acid treatments could be conducted. To overcome the isolation challenge during an acid treatment, a multistage completion assembly based on sliding sleeves and swellable packers has been devised and implemented to conduct selective acid fracturing in low permeability carbonate reservoirs. This combined system has mechanically simplified the multistage fracturing job, reducing costs and complexity compared with traditional cement and perforating methods. The system provides excellent isolation between consecutive treatments by providing positive annular barriers. The technology ensures that the entire lateral is treated uniformly and according to the design, enhances proper fracture placement, increases reservoir contact area, and improves well productivity. This paper describes and addresses the successful deployment of this completion and fracturing technology. The success resulted from careful planning, fluid testing, and a comprehensive completion design that was fit-for-purpose to provide optimal stimulation treatment and productivity enhancement.

The Lower Triassic Montney Formation produces from the Western Canadian Sedimentary Basin. This shale play is extensive as it covers nearly 57,000 square miles. The play consists of landing intervals in the Lower, Middle, and Upper Montney Formation for which the oil and gas industry uses multiple fractured horizontal well completions to recover natural gas. Both cased and open hole completions are utilized in the Montney Formation. Identifying the key drivers for success of multiple fractured horizontal wells is not straightforward, especially in unconventional reservoirs like the Montney. One study by Christie et al investigated the completion trends of four Montney operators since 2005 and showed the average completion interval length, the average number of fracture stages, and the volume of proppant used per fracture all increased over time. Al-Alwani et al, provided a statistical analysis of both open and cased hole Montney completions based on publically available data. The authors showed that for the entire well population, cumulative gas recovery per stage declines as the number of completed stages increased. It was also shown that cased hole wells performed much better than open hole wells although the completion costs were at least 50% greater. However, this statistical analysis did not differentiate between completions in the Upper, Middle, or Lower Montney nor did it include perforation cluster data. This work documents the statistical analysis of 296 cased-hole horizontal gas well completions in the Upper and Lower Montney. The work extends the previous statistical study of Montney completions by focusing on cased hole completions, including completion cluster information, and examining the performance of Upper and Lower Montney completions separately. Results of this analysis show that cumulative gas production per cluster decreases as more perforation clusters are placed in both the Upper and Lower Montney. The study demonstrates that the cumulative gas production per cluster and initial gas production (IP) is higher for the Upper Montney Formation than the Lower Montney Formation. This work benefits the industry by: Providing a more focused statistical analysis of horizontal gas well cased hole completion performance in the Montney, compared to recent literature documenting industry practices. Identifying a maximum recommended liquid per cluster amount for completions in the Montney Formation. Providing a comparison of Upper and Lower Montney cased hole completion performance.

Natural fractures are widely observed in unconventional reservoirs and their presence could lead to complex fracture network and a higher production rate by intersection with hydraulic fracture treatments. Focusing on various fractures categories, the objective of this paper is to build and verify various fracture modeling corresponding to different fracture categories depending on their effects on production and pressure, which in return provides the most effective fracture modeling approach for unconventional fractured reservoirs. A micro-scale model was firstly built to simulate fluid flow in fractured porous mediums. Equivalent permeability is computed and compared on some synthetic numerical cases, where different sensitivity parameters including isolated fracture and connected fracture are considered. Next, a reservoir-scale model including stimulated reservoir volume (SRV) and the un-fractured matrix was established. The quantitative analysis focusing on fracture aperture, matrix permeability, and the connectivity of fractures in & outside of the SRV, are conducted to evaluate the effects of different fracture categories on the production rate of fracture models. The micro model reveals that equivalent permeability is highly sensitive to whether the fracture is directly or indirectly connected to the outlet boundary. Based on the reservoir model, a production comparison chart including three categories is given, where fracture aperture varies from 100nm to 1000µm and matrix permeability varies from 100nD to 0.1mD. If the fracture aperture is narrower than 1µm and the matrix permeability is between 0.01mD and 0.1mD, or the fracture aperture is narrower than 10µm and the matrix permeability is larger than 0.1mD, the effect of isolated and connected fractures could be described simply by analytical apparent permeability model instead of the numerical models which characterize fractures explicitly, because the production error is lower than 5.00%. However, if the fractures aperture is larger than 100µm, both the connected fractures and isolated fractures must be explicitly considered to analysis the contributions. As for the reservoirs with SRV, when the fracture aperture is between 100nm and 1000µm and matrix permeability varies from 100nD to 0.1mD, we only need to explicitly handle the fractures directly or indirectly connected to the wellbore, because the disparity caused by fractures isolated from wellbore inside & outside of the SRV is less than 5.00%. This paper quantitatively classifies fractures into several categories and it evaluates the influence of isolated and connected fractures on production and pressure of fracture models, where isolated natural fractures are particularly analyzed. The results provide valuable guidance to optimize fracture modeling for unconventional fractured reservoirs.

Hydraulic fracturing is an effective approach to bring economic productions for unconventional gas reservoirs. A numerical model is developed to model the complex fracture network after hydraulic fracturing. Particular treatments for full-tensor effects and fractures of different scales are integrated in the method to deliver fast evaluating the effect of hydraulic fracturing on recovery of unconventional gas reservoirs. A discrete fracture model of the complex fracture network is firstly built up as the high-resolution reference model. Then numerical simulation grids are determined according to the fracture scales, fracture distribution and well locations. During numerical simulation, primary hydraulic fractures are treated explicit as the reference model, while relatively small-scale hydraulic fractures and natural fractures are upscaled into dual porosity grids by global upscaling procedures under multipoint flux approximation scheme. An integrated output least squares method, which aims to minimize the total bias of simulation results, is adopted to obtain the optimal transmissibility connection list of the simulation model. An application case is designed to validate the proposed method. The results show that the proposed model can improve the computational efficiency for predicting the effect of hydraulic fracturing, and can maintain an equivalent numerical precision at the same time. This model can serve as a reliable tool for fast evaluating of different plans in hydraulic fracturing of unconventional gas reservoirs.

The ongoing low oil price environment has profound impact on all the operators and service providers. Efficiency improvements and cost reductions are two key strategies to capture the opportunities in current situation. It is now imperative for engineers to improve engineering practices to gain efficiency and drive down the cost. However, in well stimulation practices, it is vital to all stakeholders to obtain fracturing fluids with desirable fluid viscosity, and thermal and chemical properties with cost as low as reasonably possible. Preparing fracturing fluids with high-hardness produced water is one option to drive down cost. Such a practice eliminates the need to transport fresh water and dispose wastewater. However, it may not be possible because of the reaction tendencies between cations and functioning polymers within fracturing fluids. Although combinations of chemicals including polymers, chemical additives, stabilizers, and buffers can be added to prevent such reactions, the dosages of each component are often hard to quantify and often dependent on the experience of field engineers. A fast prognosis tool has been developed to facilitate such a decision-making process by identifying the lowest possible dosages of chemicals dependent on produced water hardness. With such a prognosis tool, it is now possible to make more educated and cost-effective plans to optimize the engineering practice. In this work, the underlying physics of hard water damage to fracturing fluids is discussed, followed by a demonstration of the simulations that reproduced the lab rheology experiment results. The viscosity profiles of a number of rheology experiments were first matched as model calibrations. The effects of different stabilizers were then discussed by parametric comparison of different cases. With the predictive model successfully capturing the reaction system, a dynamic algorithm was built to compute the lowest cost possible solution of functioning fracturing fluids in a given system. Due to the non-linear nature of the chemical reaction system, a searching algorithm was implemented to minimize the cost of fracturing fluids as functions of local produced water hardness, cost of each chemical component and operational expenses. This work demonstrates that good engineering practices are achieved through carefully understanding and modeling a working system, and through dynamic planning of the overall workflow with cost optimization as a target. All in the form of a prognosis tool that could be easily implemented in the current fracturing fluid preparation work flow.