Results

Shale gas plays require technology such as fracture stimulation to increase rock permeability and achieve commercial rates of flow. The brittleness of shales are a major control on the ease of fracture stimulation. The Brittleness Index (BI) is a proxy for rock strength, based on geomechanical parameters, and/or rock mineralogy, and provides an indication of hydraulic stimulation effectiveness. Legacy drill core does not always have the geophysical logs needed for assessment of shale brittleness, therefore mineralogical and geochemical derived proxies for shale brittlenesss are often used with varying success. Shales from the Paleoproterozoic Lawn Hill Platform of north-west Queensland and the Northern Territory are known to contain organic-rich sedimentary units with the potential to host shale-gas plays. The Egilabria 2 DW1 well demonstrated a technical success in flowing gas from the Lawn Supersequence and recent geomechanical logging in the Egilabria prospect have demonstrated the presence of brittle rocks favourable for fracture stimulation with similarities between logged geophysics and X-Ray Diffraction (XRD) derived brittleness (Bailey et al., 2019). In this study we assess the brittleness of shales from twelve wells across the Isa Superbasin that do not have geophysical log data using XRD, major elemental analyses from X-Ray Fluorescence (XRF) and mineral carbon (MinC) techniques. The results of this study demonstrate highly variable mineral components between all analysed supersequences. The brittleness index (BI) of the shales derived from XRD ranges from ductile to brittle with zones of brittle shales present in all supersequences. Shale brittleness is controlled by increasing quartz and decreasing clay content with little influence from carbonates. Major elements based on XRF showed moderate to poor correlations to mineral type and the brittleness index was significantly higher than the results calculated by XRD. XRF analyses are not recommended as a proxy for shale brittleness in the Isa Superbasin region. The MinC parameter was highly effective as a proxy for carbonate based on comparisons with XRD derived carbonate concentrations. An important finding in this study is the variations in BI and TOC between supersequences, and within supersequences. This is evident down-hole and spatially across the area sampled. Future work is needed to investigate sweet spots for shale gas production.

Delineating geometry of natural fractures realistically and understanding fracture stress sensitivity help to optimize well placement and well spacing design in shale gas reservoirs. This paper presents a methodology for building 3D hybrid discrete natural fracture network (DFN) models and using an analytical model to assess reactivation potential of natural fracture in the Longmaxi shale, Sichuan Basin.

Small-throw faults and natural fractures ranging from seismic scale to well scale in shale reservoirs have important effects on the success of horizontal drilling and hydraulic fracturing. Seismic geometric multi-attributes at different resolution scales are used to classify seismic facies according to the degree of fracturing. Small-throw faults are delineated using seismic facies and validated against drilling data. We develop a discrete natural fracture network (DFN) model at the seismic scale by meshing fracture lineaments tracked from an enhanced curvature attribute. Fracture topologies are used for fracture connectivity analysis to build local fracture networks along and around the horizontal wellbores. Diffuse fractures at the small scale are modeled with curvature attributes and well data analysis under the constraint of the seismic facies. The analytical model incorporates fracture properties and geomechanical model to describe the deformation of natural fractures due to hydraulic fracturing. Fracture stress-sensitivity are assessed based on changes of fracture volumes under different stress conditions. Characterized reactivated local fracture networks at different scales along the horizontal wells are used to map out volumetric extent of zones with potential to develop tensile and shear deformation during hydraulic fracturing. Available microseismic data from the hydraulic fracture stimulation of the reservoir is used to validate the fracture models.

Our stress sensitivity analysis indicates that reactivation potential of natural fractures varies considerably, mainly depending on natural fracture size and orientation, rock mechanical properties and anisotropy of horizontal stresses. DFN models reveal that fracture concentrations are correlative with the footprint of observed microseismic events. Comparison of 3D natural fracture models with the microseismic event distribution shows that vertical variation of fracture properties in the laminated shale reservoir adds complexity for fracture propagation.

A case study is used to illustrate the efficiency of the methodology. Fracture models at different scales and associated fracture stress-sensitivity can be used as a predictive tool for locating new wells and completion design in shale gas reservoirs.

Wettability is an important property of shales, yet its determination is quite challenging. There is no consensus as to the most appropriate method of assessing shale wettability. The air-liquid-rock and liquidliquid-rock contact angles (Sessile/Captive) used for finding the wettability of conventional rock samples often give ambiguous/contradictory results for shales, as evident from the published literature showing a broad spectrum of results from water-wet to mixed-wet to oil-wet. In this study, the Drop Shape Analysis (DSA) approach was employed to evaluate the wettability of Eagle Ford and Wolfcamp outcrop shale samples. Both air-liquid and Sessile/Captive drop contact angles were measured. The effects of heterogeneity (location variability), roughness, solvent rinsing, exposure time, and salinity were analyzed and compared with the water-oil contact angles computed by van Dijke and Sorbie's (2002) approach. Due to the transient nature of contact angles on the shale surface, the instantaneous (initial) contact angles change rapidly. Therefore, it is proposed to use the evolution of 3-phase contact line to identify the time at which the contact angle would be unique and stabilized. The wettability of Eagle Ford and Wolfcamp shale samples could not be reliably concluded by the DSA method employed alone without the help of some other auxiliary techniques.

The North American success of unconventional oil development from marine shales has inspired the global liquid-rich shale (LRS) exploration and production trend. Resource evaluation and screening are always important for emerging shale basins. In contrast to North America, 95% of the LRS resources in China are found within lacustrine shales. Songliao, Ordos, Junggar and Bohai Bay basin are the four major lacustrine oil basins in which LRS plays are claimed and considered to be of huge resource in China. Lacustrine system differs from marine systems in many aspects with high impact on the LRS commercial development. Adopted from the classic Darcy’s law, resource potential, flow ability and drive energy are the three key factors influencing estimated ultimate recovery (EUR). Unlike routine in-place volume driven play assessment, this paper presents a multi-component EUR driven evaluation and screening that has been applied to the four major lacustrine basins in China. 1) Compared with ocean, lake usually developed in a confined area which result in the thick shale pack (more than 100m in most cases). However, in some basin, single layers with high total organic content (TOC) is thin and their distribution is disrupted by low TOC mud rocks, which would impact play resource potential. 2) Regarding the difference in kerogen type between marine and lacustrine shales, it was observed that Type I dominated lacustrine shales have a lower HC conversion rate than Type II kerogens for a given maturity, indicating that a higher maturity would be essential to achieving better fluid properties. These higher maturities tend to be found more toward the basin centers, that are often characterized by deeper burial and increased clay content. As deeper burial and higher clay content can lead to increased drilling and completion (fracability) challenges that may be costly, so a careful balance must be achieved when seeking higher maturity. 3) Considering of heterogeneity of lacustrine system, highly frequented alternation among different lithologies were observed in some lacustrine plays. The high stress contrast between different lithologies would consume energy of hydraulic fracture and impact the fracture growth.

Carbonate reservoir rocks of the Najmah formation in Kuwait, with low porosity and low permeability, have been characterized using integrated digital and physical rock analyses methods. High-resolution imaging and analyses determined the microstructural characters of mineral matrix, organic matter (OM) distribution, organic and inorganic pore types, size distribution, and permeability variation within this kerogen-rich Late Jurassic stratigraphic unit.

Considerable heterogeneity of porosity and permeability was observed in the 100-ft studied interval of the Najmah Formation. Two-dimensional scanning electron microscopy (2D-SEM) imaging and three-dimensional focused ion beam SEM (3D-FIB-SEM) imaging highlighted the different types of porosities present within the formation rock. At each depth, several 2D-SEM images were used for characterization and selection of representative locations for extracting 3D FIB-SEM volumes. The 3D volumes were digitally analyzed and volumetric percentages of OM and total porosity were determined. The porosity was further analyzed and quantified as connected, nonconnected, and associated with organic matter. Connected porosity was used to compute absolute permeability in the horizontal and vertical directions in the area of interest.

Porosity associated with OM is an indicator of OM maturity and flow potential. It has been categorized as pendular type, spongy large grain, spongy small grain, fracture porosity within the OM, grain boundary fractures and intergranular porosity covering the entire OM. Permeability is not only influenced by porosity within OM or even apparent transformation ratio (ATR), it is also dependent on pore connectivity, pore sizes, and heterogeneity (e.g., high-permeability streaks). For high porosity samples, almost all pores are connected and contributing to permeability. For low porosity samples with high permeability, the flow is mainly through microfractures. It is possible that intergranular clay pores in highly thermally mature rocks were originally filled with OM and that, during progressive thermal maturation, transformation of OM to hydrocarbon(s) removed much of the pore filling OM.

It has also been observed that, although the total organic carbon (TOC) content of the rocks is significant (up to 18 wt%), and good maturity index (VR0>1), only few examined samples show good connected porosity within the OM. It is essential to evaluate the porosity within the OM thorough high-resolution measurements for pinpointing the prospective layers for future stimulated horizontal wells in this organic-rich source unit. These intervals can be considered as the potential sweet spots after integration with detailed petrophysics and geomechanical parameters for optimized well planning and completion design.

Current global energy needs require best engineering methods to extract hydrocarbon from unconventional resources. Unconventional resources mostly found in highly stressed and deep formations, where the rock strength and integrity both are very high. The pressure at which rock fractures or simply breakdown pressure is directly correlated with the rock tensile strength and the stresses acting on them from surrounding formation. When fracturing these rocks, the hydraulic fracturing operation becomes much challenging and difficult, and in some scenarios reached to the maximum pumping capacity limits. This reduces the operational gap to create hydraulic fractures.

In the present research, a novel thermochemical fracturing approach is proposed to reduce the breakdown pressure of the high-strength rocks. The new approach not only reduces the breakdown pressure but also reduces the breakdown time and makes it possible to fracture the high strength rocks with more conductive fractures. Thermochemical fluids used can create microfractures, improves permeability, porosity, and reduces the elastic strength of the tight rocks. By creating microfractures and improving the injectivity, the required breakdown pressure can be reduced, and fractures width can be enhanced. The fracturing experiments presented in this study were conducted on different cement specimen with different cement and sand ratio mixes, corresponds to the different minerology of the rock. Similar experiments were also conducted on different rocks such as Scioto sandstone, Eagle Ford shale, and calcareous shale. Moreover, the sensitivity of the bore hole diameter in cement block samples is also presented to see the effect of thermochemical on breakdown pressure reduction.

The experiments showed the presence of micro-fractures originated from the pressure pulses raised in the thermochemical fracturing. The proposed thermochemical fracturing method resulted in the reduction of breakdown pressure to 38.5 % in small hole diameter blocks and 60.5 % in large hole diameter blocks. Other minerology rocks also shown the significant reduction in breakdown pressure due to thermochemical treatments.

The optimization of well spacing has become more important in unconventional shale reservoirs to efficiently design infill developments, estimate the Stimulated Reservoir Volume (SRV), and more importantly the estimation of Ultimate Oil Recovery (EUR) from each well. This paper presents a new analytical solution to estimate the start and end of pseudo-transient flow for the data production analysis where boundary-dominated flow exists in the induced fractures hence estimate the SRV for hydraulically fractured horizontal wells for unconventional shale reservoirs.

This paper presents a semi-analytical model to obtain the pressure transient response to characterize the flow and estimate the boundary effect which can be used to analyze the field data in unconventional shale reservoirs. The results from the model are compared and validated against an in-house developed numerical simulation model. The semi-analytical model is based on trilinear model where the SRV is modeled using dual-porosity idealization. The developed model involves the simulation of interference tests for two hydraulically-fractured horizontal well in unconventional shale reservoir using the real-time distributed pressure data. The proposed asymptotic solution evaluates not only the pseudo-transient in induced fractures but also the matrix.

The pressure measurements from real-time distributed pressure sensors and the production measurement using interference test provide a better understanding of the physical phenomena of the interaction between the parent and child wells in shale reservoirs. This paper presents a new model to assess the interference characteristics in horizontal wells to evaluate the optimum well spacing in unconventional shale reservoirs. It is observed that the production from a well is greatly affected by the distance of the wells, the reservoir properties between the wells, and the matrix permeability. It is presented that if the matrix permeability is lower, the start of the pseudo transient flow is sooner; therefore, the drainage volume becomes smaller. This can be observed by comparing the field data from unconventional shale reservoirs in Bakken and Eagle Ford where the matrix permeability in Bakken is higher than that of the Eagle Ford; therefore, the wells observe longer linear flow regime in higher permeability with larger SRV and in-turn larger well-spacing. The proposed asymptotic solution can also be used to analyze the field data in unconventional shale reservoirs to decipher the productivity and economics of horizontal wells.

To effectively produce from unconventional shale reservoirs, an optimum well spacing is required. This paper presents a novel asymptotic solution to characterize the flow regimes and provide a novel formulation in analyzing the pressure and rate variation with time to forecast future performance.

Nowadays, as the worldwide consumption of hydrocarbon increases, while the conventional resources beings depleted, turning point toward unconventional reservoirs is crucial to producing more additional oil and gas from their massive reserves of hydrocarbon. As a result, exploration and operation companies gain attention recently for the investment in unconventional plays, such as shale and tight formations. A recent study by the U.S. Energy Information Administration (EIA) reported that the Middle East (ME) and North Africa (NF) region holds an enormous volume of recoverable oil and gas from unconventional resources. However, the evaluation process is at the early stage, and detailed information is still confidential with a limitation of the publication in terms of unconventional reservoirs potential. The objective of this research is to provide more information and build a comprehensive review of unconventional resources to bring the shale revolution to the ME and NF region. In addition, new opportunities, challenges, and risks will be introduced based on transferring acquiring experiences and technologies that have been applied in North American shale plays to similar formations in the ME and NF region. The workflow begins with reviewing and summarizing more than 100 conference papers, journal papers, and technical reports to gather detailed data on the geological description, reservoir characterization, geomechanical property, and operation history. Furthermore, simulation works, experimental studies, and pilot tests in the United States shale plays are used to build a database using the statistic approach to summarize and identify the range of parameters. The results are compared to similar unconventional plays in the region to establish guidelines for the exploration, development, and operation processes. This paper highlights the potential opportunities to access the unlocked formations in the region that holds substantial hydrocarbon resources.

Hydraulic fracturing is the most prominent technique for increasing well productivity in shale oil and gas reservoirs. Spacing between perforation clusters, with Plug-and-Perf (PnP) fracturing method also believed to be spacing of fractures, is one of the parameters that need to be optimized in fracturing design. This work presents an analytical method to optimize fracture spacing based on the assessment of production data from multi-fractured horizontal wells. Five hydraulically fractured horizontal wells completed in a high clay-content shale formation were considered as examples in this study. Based on the theory of pseudo-steady state (PSS) flow, oil well productivity was investigated with special focus on perforation cluster spacing. Wells exhibiting linear flow in rate transient analyses are believed to have a potential of productivity improvement with shorter fracture spacings. Oil productivity potential with closer fracture spacing was identified for wells in the same reservoir. Result of analyses shows that some wells experienced linear transient flow, indicating significant separation between hydraulic fractures. Use of an analytical well productivity model to simulate pseudo-steady production indicates that fracture spacing could have been reduced to improve well productivity. These wells can be considered as candidates for re-fracturing if possible. Future wells to be drilled in the area nearby should be completed with shorter spacing of perforation clusters. Some wells in the case fields do not show linear transient flow, indicating interferences between either hydraulic fractures and/or natural fractures. These wells should not be refractured. New wells near these wells should not be completed with fracture spacing less than the spacing values used in the existing wells.

The United States hydraulic fracturing and completion activities have seen a paradigm shift in the pumped water and proppant volumes along the increasing completed lateral over time. Hydraulic fracturing has become the most dominant treatment in North America to tap the unconventional resources. Large scale analysis of the completion size in terms of the amount of proppant, water, and lateral length trends over the period of 2011 and 2018 is presented in this paper. The objective of this study is to elucida te the completion trends over time and to summarize the average values of the completion and stimulation parameters. It will put the readers’ mind in perspective of how much proppant and water have been utilized over the years and shine a light on the progression of the industry growing demand on water and proppant.

Data from FracFocus website, which serves as an official chemical disclosure registry for many of the oil and gas states, were utilized in this study. For each stimulated well, it reports water volume and mass percentage of proppant and all other chemical ingredients. The raw data were scraped, parsed, and cleaned using advanced statistical and validation approaches to extract useful information out of the noisy data. A database of more than 80,000 wells was built and integrated into this study. Proppant total mass and the concentration of other chemical ingredients were calculated. The obtained new variables were coupled with other completion parameters such as the horizontal length, perforated l ateral length, and well types.

The data of each parameter were subjected to rigorous quality control and inspected for outliers. After passing all the data quality and validation procedures, an advanced data visualization technique was selected to reflect the trends over time. The overall trends of the whole aggregated United States are presented in this paper. Investigating the created visualizations showed that there is an undeniable increasing trend in the amount of the proppant and water being consumed over the investigated period.

This paper exploits a large number of wells and their associated parameters. Such a large dataset will provide a comprehensive and practical representation of the completion and stimulation trends. It will also establish a baseline and reference values for the investigated parameters by benchmarking the mean, median, and other statistical expressions for each time period.