This article focuses on interpretation of well test data from wells completed in naturally fractured reservoirs. Because of the presence of two distinct types of porous media, the assumption of homogeneous behavior is no longer valid in naturally fractured reservoirs. This article discusses two naturally fractured reservoir models, the physics governing fluid flow in these reservoirs and semilog and type curve analysis techniques for well tests in these reservoirs. Naturally fractured reservoirs are characterized by the presence of two distinct types of porous media: matrix and fracture. Because of the different fluid storage and conductivity characteristics of the matrix and fractures, these reservoirs often are called dual-porosity reservoirs.

A number of early successful and unsuccessful gas injection projects are summarized by Muskat in his 1949 classic book Physical Principles of Oil Production.[1] Immiscible gas injection has been used in oil fields with a wide range of characteristics. Two of these projects were termed successes, and two were viewed as having poor response. This 1,400-acre anticlinal 31 to 36 API oil field had a maximum closure of 75 ft and 53 producing wells. The reservoir is an oolitic limestone and had an initial gas cap.

Mass-transport deposits are sedimentary, stratigraphic successions that were remobilized after initial deposition but prior to substantial lithification and transported downslope by gravitational processes as non-Newtonian rheological units (Bingham plastics or dilatant fluids). The deposits are not associated with a specific stratigraphic position. Mass transport complex (MTC) reservoirs currently under study in Colombia, consist of complex mixtures of metamorphic and igneous rocks with matrix porosities in the 3%-6% range, complex mineralogy, strong localized mylonitization effect and naturally fractured. The reservoirs are in the Lower Magdalena Valley hydrocarbon province in northern Colombia. In this context, the objective is to achieve an accurate porosity determination, water, gas, oil saturation computation and natural fracture assessment in an exploration phase, with scarce background on electrical logs response and petrophysical models in these types of environments.

In wildcat conditions, the lack of formation properties knowledge is detrimental to achieve a representative formation evaluation and reservoir potential understanding. While this is true even in relatively known geological environments (siliciclastics, carbonates, for instance), in Mass Transports deposits the complexity is even higher, given the mineral mixtures, heterogeneities, poor rock quality, complex tortuosity and complex natural fractures networks, among other challenges.

In this paper, we present an open hole advanced formation evaluation approach that enable to assess the tight matrix and the natural fractures systems, at a level not previously accomplished in these types of geological formations. At the matrix, advanced nuclear spectroscopy that does simultaneous time and energy domain measurements was integrated with a high-resolution magnetic resonance with improved sensitivity at short relaxation times. This allowed an archie-independent methodology for assessing gas from a new Fast Neutron Cross Section measurement, followed by liquid hydrocarbon fraction from the total organic carbon log and matrix-corrected porosity from combining hydrogen index and dry weight elemental concentrations. For natural fractures, the integration of borehole images with radial sonic-based dispersion and stoneley analysis, was carried out.

The main advantages of the new method for obtaining porosity, mineralogy, archie-independent hydrocarbon saturation in tight matrix and natural fracture assessment are: 1) conversion of fast neutron cross section to gas saturation and dry weight total carbon to oil saturation, done through a simultaneous inversion by solving matrix-porosity-fluids volumes into an elemental analysis, proven to work at low porosities; 2) reservoir quality assessment from a high sensitive and high resolution NMR T2 relaxation; 3) independency of archie equation parameters, typically unknow in wildcat environments; 4) reservoir potential uncertainty reduction; 5) identification of the natural fracture systems that can contribute to fluids production.

The study of pressure transient behavior in fractured-vuggy reservoirs has recently received considerable attention because a number of such reservoirs have been found worldwide with significant oil and gas production and reserves. In recent years, the use of highly deviated wells (HDW) is considered an effective means for developing this type of gas reservoir. However, in many fractured-vuggy reservoirs unexpected high gas production have been observed which cannot be identified with pressure transient models of horizontal well with pseudo state triple-porosity interporosity flow. This paper presents a semi-analytical model that analyzed the pressure transient behavior of HDW in triple-porosity continuum medium which consist of fractures, vugs and matrix. Introducing pseudo-pressure, Laplace transformation and Fourier transformation were employed to establish a point source and line source pseudo-pressure solutions in Laplace space. Then the pseudo-pressure transient curve was got by numerical inversion. Furthermore, the flow characteristics were analyzed thoroughly by examining the curve which is mainly affected by inclination angle of HDW and interporosity flow coefficients between different pore media. Sensitivity analysis on the pressure transient behavior was performed by varying some important parameters such as the inclination angle, fracture storativity ratio and interporosity flow coefficients. Finally, a field case was successfully used to show the application of the presented semi-analytical model. With its high efficiency, this approach will serve as a reliable tool to evaluate the pressure behavior of HDW in fractured-vuggy carbonate gas reservoirs.

A large amount of fracturing fluid in fracking is imbibed into the shale fracture/matrix system, which leads to a significant uncertainty in gas recovery evaluation. The mechanism of imbibition impact on the gas–water two-phase flow is not well understood. In this study, systematic comparative experiments are carried out to simulate imbibition in fractured shale samples obtained from the Wufeng-Longmaxi Formation in China and the imbibition effect in the fracture–matrix system is qualitatively and quantitatively investigated. Nine shale samples are collected to measure their porosity and permeability using a helium porosimeter and nitrogen pulse–decay tests. Gas/liquid single-phase flow experiments are then carried out on three dry and saturated fractured samples using methane and KCl solution, respectively. Subsequently, dynamic imbibition experiments are carried out on three samples in a visualization container. The gas–water interfacial tension, water imbibition amount, and displacement velocity are recorded. A single-phase gas/liquid flow test shows a high linear correlation between the fluid displacement velocity and pressure gradient in the fractured samples as the fracture is the main flow channel, dominantly determining the flow behavior. Moreover, we introduce the capillary force in the cross flow term of the triple-medium model to characterize the imbibition effect, develop a two-phase flow simulation model of shale gas considering the fracturing fluid imbibition retention, and analyze the two-phase flow behavior by considering the imbibition effect of the fracturing fluid retention in the shale gas reservoir. The impacts of the fracturing fluid imbibition and complexity of the fracture system on the two-phase flow are still unclear. We propose systematic experiments to overcome this difficulty, which could provide valuable indicative information on the two-phase flow. Valuable experiment data are provided, which can be used to validate analytical equations for gas/water flow in the shale fracture–matrix system.

This paper assesses the effectiveness of combining hydraulic fracture monitoring (performed using borehole pressure-wave readings) with facies analysis based on mechanical specific energy (MSE) measurements. Beneficial applications include: 1) evaluation and optimization of completion designs, 2) design and measurement of diversion effectiveness and 3) placement of the frac as designed – while avoiding offset well communication – to increase estimated ultimate recovery (EUR). The evaluation was performed on a four-well dataset in the Eagle Ford shale.

For each well, facies analysis directed pre-job planning, resulting in various frac stage designs that were based on variations in MSE. The stages were monitored during the job, and, based on results, frac stage designs were modified in real time to optimize the next geomechanically similar stage. Far-field diversion was used on targeted stages to limit half-length growth in select wells. On all the wells, the number of clusters per stage was varied and the impact was monitored.

The first well was used as a baseline to provide direct, quantifiable correlations between the facies MSE and the measured fracture half-lengths. On subsequent wells, different treatment designs were executed, based on the varying MSE measurements, to obtain the desired half-length. The design changes included variations in the number of clusters per stage, far-field diversion strategies, pump rates, and proppant concentrations and quantities. Throughout the operation, frac performance was monitored continuously and pumping designs were optimized by varying parameters such as perforation clusters spacing, pump rate, diverter, acid volume, pad volume, slurry/proppant design, and volume per linear foot. The completion design of every stage was modified in real time, based on the performance of the fracture system. In each well, the first stages in each rock type served as control stages for calibration purposes. The result was the development of a uniform fracture system, in terms of both its extension as well as its near- and far-field conductivity. In a series of 204 stages across all four wells, the integration of MSE facies with fracture performance enabled real-time optimization of the fracture system, which delivered significant improvements in production performance, reservoir development, and reduced rate of depletion.

The combination of MSE analysis with borehole pressure-wave-based hydraulic fracture monitoring is a paradigm shift that has the potential to revolutionize how horizontal plays are developed. Employing these combined technologies can be used to drive each frac stage to meet frac half-length, height, and conductivity goals. The fit-for-purpose, noninvasive and scalable qualities of both technologies deliver strong cost efficiencies and can significantly increase EUR from the project acreage. At both the well and field levels, this combination of cost efficiency and customizability is critical to optimizing recovery from the field and increasing the economic life of industrialized shale completions.

The multistage hydraulic fracturing process is the main stimulation technique to develop tight gas and shale formations. Estimating fracture geometry and stimulated reservoir volume (SRV) is a focal parameter to judge the fracture operation and predict the well performance. RTA and PTA techniques usually assume uniform fracture half-length; however, the fracture length varies from cluster to another due to reservoir properties and stress shadow effect.

This paper presents the performance of single-stage fracture systems with simple bi-wing fractures for all clusters and complex fractures systems which could be close to real fracture network with fixed SRV value. Numerical simulation is used to generate the production and shut-in data from the complex and simple fracture stage models. The production rates and shut-in pressure results from the simulation are then analyzed by RTA and PTA to estimate the stimulated area.

The preliminary results showed that the complex system yields the same or better performance compared to the simple fractures system scenario depending on the formation properties. Generally, the estimated area from RTA and PTA (production surface area PSA) was less than the fracture surface area (FSA) that was used in the numerical simulation. A possible reason for this behavior is the interference between the created fracture on each cluster. As a result, the effective flow area was less than the actual fracture system area. In the case of slightly high permeability formations, the SRV parameter estimated from linear flow analysis in both RTA and PTA was higher in the complex fracture well. Besides, PTA diagnostic plots show a lower estimated skin factor (the difference between the pressure and its derivative curves) in the complex system. While in the case of lower permeability formations, the performance was the same in both scenarios.

This study differentiates between the production surface area and the fracture surface area, and its behavior in complex and simple fracture systems. Therefore, the difference in production performance between wells with different hydraulic fracture systems could be used in understanding the spacing performance.

This paper extends the single well reservoir modeling concepts documented in Raterman et al. 2019 to a multiwell pilot. The analysis integrates multiple data sources to provide a holistic view of spatial drainage and interwell interference in a multiwell context. The pilot employed a four well staggered high-low configuration. All wells were kitted with bottom hole pressure and fiber optics. A vertical well was employed to monitor microseismic and pressure during the completion and production phases of the pilot. In-well and cross-well DAS, DTS and pressure data were integrated in a full pattern reservoir model to history match production, interwell interference and far field pressure data. The history matched model indicates that spatial drainage remains somewhat localized and patchy in the interwell context given the pilot spacing and completion designs. Interference between wells is significant and is largely mediated through high conductivity, limited volume conduits between wells. Although these conduits facilitate interference, a strong competitive drainage scenario between wells is not concluded. These insights are invaluable in determining the efficacy of the employed completion and spacing design; and suggest further improvements for future designs. Finally, the model was extended to analyze a Pump-into-Parent (PIP) test conducted in a partially depleted pilot producer. Fracture dilation was evidenced.

Relatively, the gas production is low for fractured horizontal wells in normal pressure shale gas plays with a quick production decrease, resulting in larger difficulty for commercial breakthrough and economic development. Accordingly fracturing technology is under study urgently.

On condition that production increased and engineering cost decreased, together with feasible and practical fracturing technology, the production potential is studied to put forward several hydraulic fracturing treatment. Firstly, cluster spacing is decreased, while increasing cluster number per stage, thus, there are more total clusters for one well with less stages, the influence of induced stress could be strengthened especially using plane perforation. Secondly, using high viscosity gel as pre fluid or flushing fluid among injecting period, to extend fracture through layers vertically. Thirdly, by use of ultra-low density small mesh proppant, increasing net pressure sharply by plugging the front of fracture. Fourthly, increasing ratio of lower viscosity slick water, small mesh proppant and higher viscosity gel, to improve hydraulic fracturing pumping pattern and technological parameter by varying viscosity, varying displacement, varying mesh proppant, so multiscale fracture propagate and propped with corresponding size of proppant. Fifthly, deminishing lower effective and non-effective clusters through studying geological and engineering sweetness.

Aiming at production increased and engineering cost decreased, the production potential is studied to put forward several hydraulic fracturing treatment, which is feasible and practical. Good result was observed in pilot application of D well and L well, providing theoretical support for developing effectively and economically in similar shale gas play.

Previous studies have concluded that classical poroelasticity-based permeability models cannot explain why coal permeability changes under the condition of both variable and constant effective stresses. There are two effective stress systems, one for the fracture system and the other for the matrix system. When coal permeability is measured, the effective stress in fractures is thought as constant while that in coal matrices remains changing with time. When gas is injected and reaches a steady state in fractures, the gas diffuses from the fracture wall into the matrix. During this diffusion process, the gas adsorbs onto coal grains. This adsorption results in coal matrix swelling. In this study, we introduce a novel concept of the volumetric ratio, the ratio of the gas-invaded area to the whole matrix area, to quantify the impact of matrix swelling area expansion on the evolution of coal permeability. The gradual matrix pressure increase near fracture walls enhances local swelling. Meanwhile, because the matrix near fracture walls contributes most to local effects, expanding of the gas invaded zone continuously weakens the matrix-fracture unequilibrium and local effects. Finally, the matrix is completely invaded by the injected gas with a new equilibrium state and local effects end. The effective stress in our model can be either constant or time-dependent. A fracture pressure loading function is applied to depict gas injection with time-dependent effective stresses. The modeling results are verified against various experimental data. We find that the evolution of coal permeability from the initial state to the final equilibrium state is a result of the propagation of gas invaded areas from the fracture wall into the matrix. Our model can be utilized to generate a series of coal permeability maps that explain a variety of lab and field observations.