Unconventional Tight Gas Reservoirs Research Articles

Experimental study on equilibrium initiation and extension of multiple clusters of fractures based on true triaxial physical simulation

In the context of tight sandstone reservoirs in the Ordos Basin characterized by compact and heterogeneous rock formations, conventional fracturing techniques yield monolithic fracture shapes, rendering 3D reservoir reconstruction unattainable. This study investigates the principles governing balanced initiation and propagation of fractures in multi-cluster fracturing within unconventional fracturing technology. Employing a large-scale true triaxial simulation experiment system, we utilize the dimensional analysis method (π theorem) to design a physical simulation experiment similarity criterion. Through various experimental adjustments involving proportioning, curing, and mechanical testing, we generate an artificially cured rock mass with mechanical parameters akin to the target layer. The rock mass is maintained at a size of 30 cm × 30 cm × 30 cm. Systematic physical simulation experiments on unconventional volume fracturing are carried out using the 30 cm-sized dense sandstone outcrop rock mass. Taking the conventional fracturing technology as a reference and manipulating experimental conditions and design parameters, we simulate the non-equilibrium initiation and extension behaviors of fracturing fractures under five unconventional volume fracturing technologies, namely hydraulic pulse pretreatment, temporary plugging between clusters, flow-limiting method, cyclic loading and unloading, and pulse intermittent fracturing. Through this, we elucidate the non-equilibrium initiation and extension laws governing multi-cluster fractures. Comparative analysis with conventional fracturing, known for inducing stress interference on fractures and inhibiting their expansion, revels that the five unconventional volume fracturing techniques mitigate stress interference in multi-cluster fracturing. This promotes uniform fracture initiation and expansion, facilitating the creation of complex fractures and larger reconstructed volumes. Among these techniques, inter-cluster block fracturing stands out for its exceptional ability to generate complex fracture networks. The research culminates in the development and refinement of a balanced fracture and extension control technique tailored for multiple cluster fractures in bulk fracturing. This technique significantly contributes to enhancing the degree of 3D reconstruction achievable in unconventional tight oil and gas reservoirs.

Effect of well scheduling and pattern on project development management in unconventional tight gas reservoirs

Effect of well scheduling and pattern on project development management in unconventional tight gas reservoirs

Investigation of pore structure alteration and permeability enhancement of shale matrix by supercritical water treatment after hydraulic fracturing

Shale gas reservoirs are unconventional tight gas reservoirs, in which horizontal wells and hydraulic fracturing are required to achieve commercial development. The fracture networks created by hydraulic fracturing can increase the drainage area extensively to enhance shale gas recovery. However, large volumes of fracturing fluid that is difficult to flow back to the surface and remained in the shale formation, will inevitably lead to damages of the shale formations and limit the effectiveness of stimulation. Supercritical water (SCW) treatment after hydraulic fracturing is a new method to enhance shale gas recovery by using appropriate heat treatment methods to the specific formation to convert the retained fracturing fluid into a supercritical state (at temperatures in excess of 373.946°C and pressures in excess of 22.064 MPa). An experiment was conducted to simulate the reaction between shale and SCW, and the capacity of SCW treatment to enhance the permeability of the shale was evaluated by measuring the response of the shale porosity and permeability on SCW treatment. The experimental results show that the shale porosity and permeability increase by 213.43% and 2198.37%, respectively. The pore structure alteration and permeability enhancement of the shale matrix were determined by analyzing the changes in pore structure and mineral composition after SCW treatment. The mechanisms that affect pore structure and mineral composition include oxidative catalysis decomposition of organic matters and reducing minerals, acid-catalyzed decomposition of carbonate minerals and feldspar minerals, hydrothermal catalysis induced fracture extension and cementation weakening induced fracture extension. SCW treatment converts harm into a benefit by reducing the intrusion of harmful substances into the shale formation, which will broaden the scope and scale of shale formation stimulation.

Experimental evaluation of liquid nitrogen fracturing on the development of tight gas carbonate rocks in the Lower Indus Basin, Pakistan

Tight gas carbonate formations have enormous potential to meet the supply and demand of the ever-growing population. However, it is impossible to produce from these formations due to the reduced permeability and lower marginal porosity. Several methods have been used to extract unconventional tight gas from these reservoirs, including hydraulic fracturing and acidizing. However, field studies have demonstrated that these methods have environmental flaws and technical problems. Liquid nitrogen (LN2) fracturing is an effective stimulation technique that provides sudden thermal stress in the rock matrix, creating vivid fractures and improving the petro-physical potential. In this study, we acquired tight gas carbonate samples and thin sections of rock from the Laki limestone formation in the Lower Indus Basin, Pakistan, to experimentally quantify the effects of LN2 fracturing. Initially, these samples were characterized based on mineralogical (X-ray diffraction), petrography, and petro-physical (permeability and porosity) properties. Additionally, LK-18-06 Laki limestone rock samples were exposed to LN2 for different time intervals (30, 60, and 90 mins), and various techniques were applied to comprehend the effects of the LN2 before and after treatment, such as atomic force microscopy, scanning electron microscopy, energy-dispersive spectroscopy, nano-indentation, and petro-physical characterization. Our results reveal that the LN2 treatment was very effective and induced vivid fractures of up to 38 µm. The surface roughness increased from 275to 946 nm, and indentation moduli significantly decreased due to the decreased compressibility of the rock matrix. Petro-physical measurements revealed that the porosity increased by 47% and that the permeability increased by 67% at an optimum LN2 treatment interval of 90 mins. This data can aid in an accurate assessment of LN2 fracturing for the better development of unconventional tight gas reservoirs.

Impact of clays on CO2 adsorption and enhanced gas recovery in sandstone reservoirs

Carbon dioxide enhanced gas recovery (EGR) is a promising technique to sequester CO2 and boost natural gas recovery from conventional depleted and unconventional tight gas reservoirs. Clay minerals are usually present in sandstone reservoirs and their influence on the efficiency of CO2-EGR is yet to be examined. In this study, the impact of clays on CO2 adsorption was evaluated for different sandstone rocks with various amounts and types of clays in the temperature range from 50–100 °C and pressures up 20 bars. The results showed that the adsorption of CO2 on sandstone rocks depends on the clay type, amount, and distribution. Clay-rich sandstone rocks, which have swellable clays such as illite, showed the highest CO2 uptake at a temperature of 50 °C and a pressure of 20 bars with total CO2 uptake of 4.6 and 2.6 mg/g for Kentucky and Scioto rocks, respectively. In contrast, sandstone samples with low clay content and a considerable percentage of carbonates showed CO2 uptake just above 1.5 mg/g for Bandera sandstone and 1.1 mg/ gm for Berea sandstone at similar conditions. Moreover, raising the temperature to 75 °C decreased the CO2 uptake on sandstones. However, the alteration of clays crystallinity at a temperature of 100 °C improves the CO2 adsorption. Adsorption isotherm analysis revealed that at the CO2 adsorption is monolayer at low temperature (50 °C) and pressure of 20 bars; whereas multilayer adsorption at 75 and 100 °C is predicted by Freundlich isotherm model. The thermodynamic analysis illustrated that the adsorption of CO2 on sandstone rocks is physisorption and exothermic on Kentucky, Scioto, and Berea sandstones and endothermic on Bandera sandstone. Core flooding experiments at 100 °C revealed the potential of CO2-EGR for clay-rich sandstone and highlighted the role of clays distribution.

Advanced Hydraulic Fracture Characterization Using Pulse Testing Analysis

Effective hydraulic fracture characterization is important for successful reservoir stimulation. This represents one of the primary challenges for completion engineers in the oil and gas industry, especially for unconventional tight gas reservoirs which are important sources of gas production in the US. Multi-stage hydraulic fracturing in horizontal wells is the most popular completion method for these types of reservoirs. An advanced methodology has been developed to characterize hydraulic fractures via pulse testing analysis. This technique combines analytical solutions and numerical modeling based on the pressure pulse response recorded at offset wells before, during, and after horizontal well fracture operations to characterize fracture orientation, height, and length. Different conceptual models were tested for random well pair spacing and orientations to generate correlations and families of type curves for a single-stage vertical fracture characterization. The methodology was then expanded to be implemented in more complex cases of multi-stage fractures. For validation and calibration purposes, a case study for a single fracture characterization was presented to match the numerical results with the field data. A good agreement in fracture orientation, height, and length was obtained with this reasonably cost-effective technique.

A review of the current status of induced seismicity monitoring for hydraulic fracturing in unconventional tight oil and gas reservoirs

During the past decades, significant progress has been made in the development of induced seismicity monitoring for related human activities. Hydraulic fracturing and induced seismicity monitoring are operating procedures for safe and effective production of oil and gas from unconventional resources, particularly shales. Hydraulic fracturing can induce seismicity through fluid injection and disturbance of subsurface stress in tight reservoirs. Most seismic events associated with hydraulic fracturing exhibit magnitude of Mw ≤ 3 and are referred to as microseismicity, while a few larger-magnitude earthquakes (e.g. Mw > 3) could also be induced by reactivating pre-existing faults. Here, we review the current status of research concerning induced seismicity monitoring for shale hydraulic fracturing. Induced seismicity contains information relating to important subsurface characteristics, e.g. rock failure potential and seismogenic zones. Microseismic monitoring is essential for reservoir characterization, e.g. fracture geometry delineation and reservoir geomechanical analysis. It is carried out with advanced acquisition, processing, and interpretation techniques, while larger-magnitude earthquakes are mainly exploited for potential geohazard management and mitigation. Challenges and prospects associated with multi-disciplines for future research and applications of induced seismicity monitoring are identified, and it contributes to achieve safe and efficient unconventional (tight) oil and gas resource exploitation.

Finite Element Investigation of Flow Field Below Asymmetric Drill Bits for Reverse Circulation in Drilling Tight Oil and Gas Reservoirs

Development of unconventional tight oil and gas reservoirs such as shale pays presents a huge challenge to the petroleum industry due to the naturally low permeability of shale formations and thus low productivity of oil and ... | Find, read and cite all the research you need on Tech Science Press

Effect of gas compressibility on permeability measurement in coalbed methane formations: Experimental investigation and flow modeling

The pressure transient technique, such as pulse decay method (PDM), has been considered an advanced approach to measure the permeability of the coalbed methane(CBM) and shale gas formations as such approach is more efficient, accurate and effective compared to that of the conventional flowrate measurement method. A constant isothermal gas compressibility factor is assumed over the testing pressure range in the experimental studies when using the PDM, which could lead to an inaccurate measured permeability. In this study, a nonlinear parabolic partial differential equation (PDE) model, taking the isothermal gas compressibility factor (gas compressibility) as a pressure dependent variable, was established to examine how pressure responses are affected by the gas compressibility variation. A novel and practical finite difference scheme was then proposed to efficiently and accurately solve the nonlinear PDE model, providing a powerful tool to numerically investigate the gas flow behavior in the CBM and shale rocks. Analytical solution for the PDE model was derived rigorously to investigate the influence of gas compressibility on the calculated permeability. Laboratory experiments were also conducted on coal permeability measurement and characteristics of the pressure pulse decay plots verified the effect of the gas compressibility on the pressure responses, especially under low pressures. Both numerical and experimental results demonstrated that the gas compressibility is a crucial parameter that should be considered for the permeability calculations in CBM and shale reservoirs. It is found that the difference in the pressure response that is predicted between the nonlinear model and the linear model with a constant gas compressibility can reach up to 41.1% at the testing pressure of 0.7 MPa. In addition, the difference in the measured permeability obtained from the two models increases as gas depletion proceeds. And also, it is suggested that both pressure changes in the upstream and downstream reservoirs should be used for permeability calculation to minimize the influence of gas compressibility on calculated permeability. This study extends the applicability of the pressure transient technique and provides an effective way to accurately measure permeability of unconventional tight gas reservoirs.

Well Testing Model of Multiple Fractured Horizontal Well with Consideration of Stress-Sensitivity and Variable Conductivity in Tight Gas Reservoirs

Multiple fractured horizontal wells have been widely used to develop unconventional tight gas reservoirs. Currently, many well testing models were established to study the performance of fractured horizontal wells in tight gas reservoirs. However, none of these models thoroughly takes stress-sensitivity of natural fractures and variable conductivity of artificial fractures into consideration. Based on the consideration of stress-sensitivity of natural fractures and variable conductivity of artificial fractures, a novel well testing model for fractured horizontal well in tight gas reservoirs is proposed. And the semianalytical solution of this new model is obtained by dividing the artificial fracture into different segments under the integrative methods of Laplace transformation, point source function, perturbation theory, superposition principle, and Stehfest numerical inversion. After validation, the semianalytical solution is consistent with that of Zerzar’s model (2004). Also, typical pressure and pressure derivative curves are plotted. According to typical curves, seven regimes can be derived, namely, bilinear flow, linear flow, early-time pseudoradial flow, biradial flow, intermediate-time pseudoradial flow, and pseudo-steady state interporosity flow, and late-time pseudoradial flow can be identified. In addition, this paper analyzes the impact on pressure and pressure derivative curves exerted by variable conductivity and stress-sensibility. The results show that variable conductivity mainly affects the early flow regimes, including bilinear flow, linear flow, and early-time radial flow, while the stress-sensitivity mainly affects the later flow regimes, including intermediate-time pseudoradial flow, pseudo-steady state interporosity flow, and late-time pseudoradial flow. The typical curves will ascend with the increasing of stress-sensitivity coefficient. The research provides a method for precise prediction of formation parameters and has a significant impact on the tight gas reservoir development.

A Semianalytical Productivity Model for a Vertically Fractured Well With Arbitrary Fracture Length Under Complex Boundary Conditions

Summary Vertically fractured wells are used widely to achieve efficient development of low-permeability reservoirs and unconventional tight reservoirs. Currently, there are some commonly adopted productivity models for a fractured vertical well, including the Giger (1985) model, the Economides model (Economides et al. 1989), the Joshi (1991) model, the Guo model (Guo and Evans 1993), the Zhang (1999) model, and others. However, these models are only suitable for either short fractures or long fractures, and thus cannot satisfy the need for arbitrary-length fracture selection. In addition, these models have certain requirements for boundary conditions, and few models consider the nonuniform flow in actual hydraulic factures. Therefore, it is desirable to establish a productivity model for vertically fractured wells with arbitrary fracture length under complex boundary conditions. In this paper, first, we evaluate the existing fractured-vertical-well productivity models in detail. After that, on the basis of the potential superposition principle and mirror-image method, we develop the productivity model for a fractured vertical well with arbitrary fracture length under different boundary conditions. Grounded in this model, further considering the frictional pressure drop caused by fracture-flow nonuniformity, we establish the productivity equation of a finite-conductivity-fracture vertical well with nonuniform flow in the fracture. Finally, after comparing with the existing model under certain conditions, the reliability of the proposed model is verified successfully. Results show that the Giger model assumes that the boundary in the fracture-extension direction is impermeable, and the pressure wave reaches the boundary earlier than the constant-pressure boundary, which is perpendicular to the extension direction of the fracture, whereas both the Economides model and the Joshi model assume that the boundary in the fracture-extension direction is far, and is always farther than the boundary perpendicular to the direction of the fracture extension. The results forecast by the previous models will deviate greatly from actual well-production performance, if the real field case cannot meet the requirements of these models. The proposed model is not only in good agreement with the previous models at given conditions, but is also suitable for fractured vertical wells under arbitrary-length fractures and complex boundary conditions. Compared with the existing models, the correctness and reasonableness of the model are shown, and the application of the proposed model is broadened. For the development of low-permeability and unconventional tight oil and gas reservoirs with fractured vertical wells or fractured horizontal wells, the establishment and application of this model have great theoretical significance and application value for production prediction. This model can be a foundation or reference for productivity prediction of low-permeability and unconventional tight oil and gas reservoirs with fractured vertical wells or fractured horizontal wells.

A study of the effect of brittleness on hydraulic fracture complexity using a flow-coupled discrete element method

In recent years, hydraulic fracturing has emerged as an important technique for the development of unconventional tight gas and oil reservoirs, particularly shale reservoirs. Production from a tight reservoir requires hydraulic creation of a highly fractured network for significantly improving the hydraulic conductivity of the reservoir. Field observations have empirically indicated that fracture complexity tends to be higher in the case of higher rock brittleness which is defined as the combination of the Young's modulus and Poisson's ratio of a rock. The brittleness is considered as one of the most important mechanical rock properties of unconventional tight reservoirs. However, the physical relationship between fracture complexity and the brittleness remains unclear. In this study, a series of hydraulic fracturing simulations were performed using a flow-coupled discrete element method to gain insights into the effect of the brittleness on fracture propagation. The brittleness was adjusted under different combinations of Young's modulus and Poisson's ratio for four rock models. Considering mechanical rock properties and pre-existing fractures, the effective stress in the case of lower brittleness reduced to the tension only around the tip of the hydraulic and pre-existing fractures. On the contrary, the tensile region was more widely distributed along the pre-existing fracture in the case of higher brittleness. The effective tensile stress in a wider region should induce more microcracks, thereby enhancing the possibility of the hydraulic fracture branching off from the pre-existing fracture. These considerations indicate a positive correlation between the brittleness and the complexity of a hydraulically induced fracture system.

A feasibility study of gas-lift drilling in unconventional tight oil and gas reservoirs

Development of unconventional tight oil and gas reservoirs is an unsolved problem in the energy industry due to the low productivity of oil and gas wells. The reason is the low permeability of reservoir rocks that are very vulnerable to the contamination of the water in the drilling and fracturing fluids. Although gas-drilling (drilling with gas) has shown to be promising to solve the problem, several problems hinder its application. These problems include formation water influx, wellbore collapse, excessive gas volume requirement, and hole cleaning in horizontal drilling. A new technique called gas-lift drilling has been proposed to solve these problems. A technical assessment of gas-lift drilling was carried out in this study to determine the feasibility of the newly proposed drilling technique. It is found that, compared to conventional (positive circulation) gas drilling, gas-lift drilling can reduce gas injection rate required for hole cleaning by at least 70%. The kick-off pressure for unloading the well depends on water zone pressure and valve setting depth, and can be lowered by reducing valve spacing. The gas injection pressure in gas-lift drilling will be in the same level as in the conventional gas drilling. Mathematical modeling shows that the temperature profiles in the annulus and inside the drill string will be significantly higher than the geo-temperature profile. The gas-lift valve can be designed to open and close automatically depending upon the water-induced pressure inside the drill string. The gas-lift valve design experience gained from gas-lift operations in oil production can be employed in gas-lift drilling. In this paper, it is concluded that gas-lift drilling has the potential to become a viable and feasible technique for development of unconventional tight oil and gas reservoirs with improved performance and reduced cost.

Chemostratigraphic and sedimentologic evolution of Wajid Group (Wajid Sandstone): An outcrop analog study from the Cambrian to Permian, SW Saudi Arabia

The Paleozoic age succession in Saudi Arabia represents one of the most prolific petroleum producing systems in the Arabian Peninsula. This succession is also considered important for unconventional tight gas and shale gas reservoirs. The Wajid Group (Wajid Sandstone) in SW Saudi Arabia consists of four formations, namely, Dibsiyah (Lower and Upper), Sanamah, Khusayyayn and Juwayl from bottom to top. This study investigates the major oxides, trace and rare earth elements for the Wajid Group formations in southwestern Saudi Arabia. We characterize and compare the sandstone types, provenance, tectonic setting, and climate. Moreover, we applied the chemostratigraphic technique for stratigraphic differentiation. Concentrations of certain elements indicate that Wajid Group was deposited in a passive continental margin. The geochemical analysis reveals that Wajid Group sediments were likely derived from the upper and bulk continental crust and mafic igneous provenance. The elemental geochemical data has been applied in this study to improve the stratigraphic subdivision and correlation. Using selected elements, geochemical vertical profiles, binary, and ternary diagrams allow clearly distinguishing between Wajid Group formations. Thus supports the established formation boundaries that constructed using lithostratigraphy and sedimentology. The geochemical elements variation between formations can be related to differences in rock-forming minerals, facies change, climate, and provenance. The results of this study may help in constraining and correlating complex facies strata and can be used as a guide for stratigraphic correlations in the subsurface within the Wajid basin and other equivalent stratigraphic successions within Saudi Arabia.

A simulation method for modified isochronal well testing to determine shale gas well productivity

A simulation method to determine shale gas well productivity is developed based on modified isochronal well testing. The method is reliable and accurate and reduces the well testing time. First, the physical properties and wellbore parameters of the reservoir are obtained using the production data analysis method or well testing method. Then the production sequence and time sequence are determined. The production sequence is estimated by the production data analysis method, which can calculate gas well production under different pressures. The testing time interval and duration are determined by using the time value of the inflection points on the curve of the productivity coefficient and the time sequence. A modified isochronal well testing simulation model is developed based on the dynamic change patterns of the reservoir and well tubing, the production sequence, and time sequence. Finally, the simulation model is solved by the conventional production well test regression method, and the well productivity and open flow potential are calculated. Using a shale gas well in the Changqing oilfield, China, as a case study, field test results and simulation result are analyzed and compared. The results confirm the reliability of the new method in a shale gas reservoir; the precision of the shale gas productivity evaluation improved and the cost and duration of the test were reduced. This method can be expanded to other unconventional tight gas reservoirs.

Oil well perforation technology: Status and prospects

Abstract Perforation is a key link in well completion. To meet the development requirements of different types of oil and gas fields, after over ten years of research and development, a series of perforation methods and matching processes have been established, such as deep penetration shaped perforation, composite perforation, directional perforation etc, which on the one hand improve the result and efficiency of perforation completion and stimulation, on the other hand prolong the service life of reservoir by protecting the reservoir. Meanwhile, the optimization of perforation design and the improvement of perforation check method further enhance the safety and success rate of perforation, and make the perforation test process and field application more standardized. For unconventional tight oil and gas reservoirs, deep−ultra-deep reservoirs, thin and poor reservoirs, reservoirs with edge or bottom water, staged fracturing of horizontal wells, and re-perforating of old wells, perforation techniques such as 3D perforation, ultra-deep penetration perforation, and high temperature high pressure perforation, and supplement perforation etc should be studied according to the features of the specific oil and gas reservoir and well.

Integrated Well-Test Strategy in Unconventional Tight Gas Reservoirs

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 16950, ’Integrated Well-Test Strategy in Unconventional Tight Gas Reservoirs: Learning and Experiences From an Actual Field Project,’ by Minquan Jin, SPE, Shell Exploration & Production; Wenxia Zhang, SPE, Shell China Exploration and Production; and Hongli Zhang, PetroChina Southwest, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed. Copyright 2013 International Petroleum Technology Conference. Reproduced by permission. Tight gas reservoirs and shale gas reservoirs are economically viable hydrocarbon prospects that have proved to be successful in North America. In such reservoirs, established methods of well testing and data analysis are often impractical. This paper presents an integrated well-test program developed for a tight gas reservoir in southwestern China. The program, designed and modified from conventional methods to meet the project-delivery timeline and cost constraints, makes use of a combination of various formation-evaluation techniques. Introduction The northwestern and central areas of the Sichuan basin have been identified as having basin-centered gas potential. In particular, there are several blocky sand intervals in the Late Triassic Xujiahe formation that contain a relatively immature, continuous gas accumulation. The tight-gas-reservoir project described in this paper is located in the central uplift area of this basin and is operated by Shell and PetroChina as a joint venture. In this tight gas block, the Xujiahe formation has a gross thickness of greater than 500 m and is found at 3000- to 4000-m drilling depth. The hydrocarbon system in the block is an overpressured section of tight gas sands that are sourced by imbedded and surrounding shales and coals. Gas and condensate can be produced from this objective section through massive multistage hydraulic-fracturing treatments. As with the exploration and development of any tight gas reservoir, the economic delivery of this project requires the integration of various well-testing methodologies to identify the economic feasibility of the reservoir. Well tests are normally conducted during various stages of the well life (Fig. 1). The objectives of well tests include the following: Identifying the hydrocarbon-bearing horizon Characterizing reservoir parameters Obtaining initial reservoir pressure Characterizing well damage and the extent of the damage Determining well deliverability and drainage area Evaluating well-completion efficiency Evaluating reservoir heterogeneities Estimating recoverable reserves Unlike conventional hydrocarbon prospects, however, the formation permeability in a tight gas reservoir is extremely low, and commercial production generally requires stimulation through extensive hydraulic fracturing. The mature and well-defined methods of well testing and data analysis, although applicable, are often impractical because of excessive test duration. Therefore, the true potential in tight gas reservoirs can be established only when well tests are combined with a well-hydraulic-fracturing program. We present an integrated well-test program developed and implemented for reservoir characterization and formation evaluation of this particular tight gas reservoir. The program makes use of a combination of various formation-evaluation techniques that include diagnostic fracture- injection tests (DFITs), perforation-inflow tests (PITs), pressure-buildup (PBU) tests, rate-transient analysis, and production logging.

The effect of hydraulic-fracture parameters on the welltest response of multi-fractured tight-gas reservoirs

With the reduction of conventional reserves, the demand and exploration of unconventional sources becomes increasingly important in the energy supply system. Low permeability, low porosity, and the complexities of rock formation in unconventional gas reservoirs make it difficult to extract commercially viable gas resources. Hydraulic fracture is the most common technique used for commercial production of hydrocarbon resources from unconventional tight-gas reservoirs. Due to the existence of an extremely long transient-flow period in tight-gas reservoirs, the interpretation of welltest data based on conventional welltest analysis is quite challenging, and could potentially lead to misleading results. This peer-reviewed paper presents a new approach based on a log-log reciprocal rate derivative plot. Emphases are given on the identification of factors affecting the welltest response in multiple hydraulic-fractured wells in unconventional gas reservoirs based on numerical simulation. The objective is to investigate the sensitivity of various reservoir and hydraulic-fracture parameters, such as multiple hydraulic-fracture size, fracture number and fracture orientation on welltest response, and the effect of the pressure derivative curve on the slopes of welltest diagnostic plots, as well as on well productivity performance. The results can be used to understand the welltest response for different hydraulic-fracturing scenarios for the efficiency and characteristics of hydraulic fractures.

Observations From a Tight-Gas-Reservoir Stimulation

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 117570, "Observations From Tight-Gas-Reservoir Stimulations in the Rocky Mountain Region," by Erik Borchardt, SPE, Schlumberger; Jessica Cavens and Craig Wieland, SPE, EnCana Oil and Gas; and Brian Pluemer, SPE, Don Graham, Abdunnaser Erwemi, Alexei Kazantsev, SPE, and Joel Le Calvez, SPE, Schlumberger, originally prepared for the 2008 SPE Tight Gas Completions Conference, San Antonio, Texas, 9-11 June. The paper has not been peer reviewed. Unconventional tight gas reservoirs are made economical through effective stimulation techniques. Hydraulic-fracture mapping combined with an in-depth knowledge of reservoir geology and geomechanics can provide a better understanding of the effectiveness of reservoir stimulation. Massive hydraulic fractures from two wells in the Rocky Mountain region were mapped in real time with a 3D stimulation-viewer soft-ware package. One well used techniques standard to the area, while some experimental fracture techniques were tested on the other. Regional Background The area of study included 3,000 vertical ft of fluvial and marine sands in the Rocky Mountain region of the US. The formation contains natural fractures, laterally restricted lenticular sandstones, and tight brittle sands. The main natural-gas reservoir interval is from 5,000 to 8,500 ft. The productive sands have an average porosity of approximately 7%, and permeability is in the µd range. The first well was drilled in this region in 1955. In the late 1990s, the discovery of increased production resulting from fracturing lenticular sands made this a profitable area. Wells currently are drilled on 10-acre density. Much of the area uses directional drilling from well pads to reduce surface damage. Pad Layout On the study pad, there are four S-shaped wells (Fig. 1). The middle well (Well A) was used as the monitoring well, and the wells directly north (Well B) and directly east (Well C) were stimulated. Wells B and C are approximately 1,200 ft from the monitor well in the vertical section that was stimulated. Well C was considered the control well, while some experimental fracture techniques were used in Well B. Offset to the south of the monitor well (Well A), a series of openhole (OH) logs was run to help understand formation characteristics. A pulsed-neutron tool was run in all four wells so that geological modeling from OH logging on Well D could be projected to all wells on the pad by means of a neural network. The two treatment wells (Wells B and C) had 11 and 12 stages stimulated, respectively. Perforations were designed as 10 sets of perforations per fracture stage. The fracture stages ranged from 180 to 350 ft of net pay.

The Importance of Initial Reservoir Pressure for Tight Gas Completions and Long-Term Production Forecasting

Abstract Flow and buildup testing of gas wells in Alberta is common practice for the determination of reservoir pressure, permeability and wellbore skin. Post-frac welltesting is still regarded as the preferred welltesting method, due in part to current government regulations for initial testing requirements. With the maturing of the Western Canadian Sedimentary Basin (WCSB) in recent years, the development of unconventional gas reservoirs has significantly increased. Deep tight gas reservoirs have become an important part of unconventional gas resources and this paper will address several issues and pitfalls related to the welltesting of tight gas. Initial reservoir pressure is probably one of the most important ‘data points’ for reservoir engineering and completion design and yet one of the most abused and assumed parameters. Field examples will highlight major errors that are likely to occur when post-frac flow and buildup tests are analyzed for tight gas reservoirs without precise knowledge of the initial reservoir pressure. This paper will demonstrate that errors of reservoir pressure as small as 2% can lead to significant overestimates of the well 's recoverable reserves. Introduction The strong commodity prices in the energy sector experienced in recent years have resulted in an increased activity level for the development of unconventional tight gas reservoirs. Natural gas price is the major factor that will determine the economic viability of tight gas reservoirs. However, there are additional factors that should be taken into consideration, such as original-gas-in-place, completion efficiency, well spacing and the ultimate recoverable reserves. Unlike conventional gas reservoirs where proven reservoir engineering techniques are easily applied, the predictability of deep tight gas reservoirs is much more difficult to achieve. Too often the post-frac welltest results from wells completed in tight gas reservoirs are used to establish initial pressure, completion effectiveness and reservoir permeability for production forecasting for economic decisions. The flow behaviour of hydraulically fractured tight gas reservoirs is very complex and significant errors in the determination of matrix permeability and fracture parameters often occur. These errors can have a significant impact on predicting gas production and total cumulative gas recovery. Discussion With the maturing of the WCSB and high natural gas prices, the activity levels in the oil and gas industry have increased to record levels. So has an increased number of tight gas well completions. Generally speaking, performance evaluation of tight gas wells reveals a trend where the production performance of the wells is much less than what was initially predicted. These errors are considered the result of overestimating reservoir parameters such as the reservoir flow capacity (kh). Short references will be made to some of the factors determining the success of developing a tight gas resource:Original-gas-in-place (OGIP) is usually determined by the volumetric method and requires knowledge of reservoir pressure, mapping and petrophysical parameters. One equation used for estimating OGIP is:Equation (1) (Available In Full Paper)Hydraulic fracturing is a necessary step in the completion process in tight gas reservoirs in order to achieve commercial production.