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.
Al-Nakhli, Ayman (Saudi Aramco) | Tariq, Zeeshan (King Fahd University of Petroleum and Minerals) | Mahmoud, Mohamed (King Fahd University of Petroleum and Minerals) | Abdulraheem, Abdulazeez (King Fahd University of Petroleum and Minerals) | Al-Shehri, Dhafer (King Fahd University of Petroleum and Minerals)
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.
Ba Geri, Mohammed (Missouri University of Science and Technology) | Ellafi, Abdulaziz (University of North Dakota) | Flori, Ralph (Missouri University of Science and Technology) | Belhaij, Azmi (Saudi Metal Coating Company) | Alkamil, Ethar H. K. (University of Basrah)
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.
Al-Alwani, Mustafa A. (Missouri University of Science and Technology) | Britt, Larry K. (NSI Fracturing) | Dunn-Norman, Shari (Missouri University of Science and Technology) | Alkinani, Husam H. (Missouri University of Science and Technology) | Al-Hameedi, Abo Taleb T. (Missouri University of Science and Technology) | Al-Attar, Atheer M. (Enterprise Products) | Al-Bazzaz, Waleed H. (Kuwait Institute For Scientific Research)
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.
Current industry trend of "manufacturing" approach to develop unconventional shale reservoirs would make the journey to reach an optimized solution long by considering the historical deployment of current and emerging technologies in the last decade in North America. The basic premise is that "
The Current work is based on the utilization of Kinetix-Intersect; modeling results were compared to Stimplan for a selected stage and rate transient analytical results. Highly complex heterogeneous hydraulic fractures are created during the first dynamic process resulting in variable areal and vertical pressure distribution and flow anisotropy occurred during the second dynamic process or production phase. Kinetix-Intersect model results indicated a variable recovery factor distribution after 30 years of production, 8.9% in the near-wellbore dynamic nano-darcy region, 2% and 1.7 % for the inter-hydraulic fracture and external feeder regions respectively for the shale oil producer evaluated. Kinetix-Intersect model results indicated that about 2/3 of total hydrocarbons produced are contributed by the near-wellbore dynamic nano-darcy and inter-hydraulic fracture regions and the remaining 1/3 by the external feeder region. Acknowledging the variability of recovery factor distribution and pressure depletion associated to the producer drainage area should be the basis for the potential implementation of Enhanced Oil Recovery (EOR) techniques.
For the shale oil producer analyzed in this study, current model results indicate an asymmetrical shape drainage area and a variable well spacing in the range of 350 to 400 meters based on displacement efficiency and non-uniform recovery factor distribution. From a pressure depletion perspective, the estimated well spacing should be at least 400 meters. However, an optimum full field development would require the consideration to implement variable well spacing and tailoring completion and fracture treatment designs based on timely identification of areal and vertical heterogeneity of static/dynamic reservoir and geomechanical drivers to optimize project economics. Streamlines were used as a drainage qualitative indicator tool to help defining well spacing criteria. In summary, the route to attain better recovery factors for unconventional shale oil reservoirs commence with the understanding and quantification of the areal and vertical pressure depletion distribution along the horizontal section of the parent wells based on both dynamic processes; this is a vital input to define a suitable well spacing and effectively deploy adaptable drilling, completion and fracture treatment designs to reduce the occurrence of detrimental ‘Frac –Hits’ and improve oil recovery for future parent-child wells. The current expected recovery factors for unconventional shale producers are suboptimal with natural depletion and the need to increase the recovery factor with the deployment of EOR technology is paramount.
The investigation of the effect of hydration swelling on induced fracture generation and the resulted permeability in shale has considerably expanded in recent years. However, only a few experiments under anisotropic compressive stress conditions have been done in this area. The experiment methodology that was presented in this paper can be used to study the effect of hydration swelling on fracture initiation and propagation, and the change of shale permeability under anisotropic compressive stress conditions. An artificial fracture through a core was created before the test to simulate the hydraulic fracture generated during the fracturing process. Distilled water was used to simulate the hydraulic fracturing fluid. A CT scanner was used to collect the CT images of fracture development. A digital pressure transducer was used to monitor the upstream pressure change, and the downstream pressure was kept at atmosphere pressure. We, for the first time, combined water adsorption, stress anisotropy conditions, and shale permeability change into one test. Five tests were conducted: three tests underwent stress anisotropy, and the other two tests employed stress isotropy. These tests were continuously exposed to working fluids at a constant flow rate. From the results, the increase in the apparent weight of cores showed that water could be adsorbed into shale samples during the tests. In shale samples with stress anisotropy conditions, fractures through the core were generated. More fractures were created under larger differential stress conditions. The upstream pressure decreased when fractures through the core were generated or particle detachment happened. The decrease in pressure indicates that hydration may be beneficial to shale permeability recovery. To differentiate the effect of hydration and stress anisotropy on fracture generation, one sequential imbibition test was conducted (oil, then water). Fractures can be generated if the imbibition fluid changed from oil to water. The results supported the previous result that hydration may induce fractures (
A major outstanding challenge in developing unconventional wells is determining the optimal cluster spacing. The spacing between perforation clusters influences hydraulic fracture geometry, drainage volume, production rates, and the estimated ultimate recovery (EUR) of a well. This paper systematically examines the impact of cluster spacing in the Eagle Ford shale wells by calibrating fracture geometry and fracture/reservoir properties using field injection and production data and evaluating the optimal cluster spacing under different reservoir conditions.
We explore a sequential technique to evaluate and optimize cluster spacing using a controlled field test at the Eagle Ford field. This study first identifies the fracture geometry by history matching the field injection treatment pressure. Using the rapid Fast Marching Method based flow simulation and Pareto-based multi-objective history matching, we match the well drainage volume and the cumulative production to calibrate the fracture and SRV properties. The impact of cluster spacing on the EUR are examined using the calibrated models. We run injection and production forecasts for various cluster spacing to investigate optimal completion under different reservoir conditions.
The unique set of injection and production data used for this study includes two horizontal wells completed side by side. The well with tighter cluster spacing has larger drainage volume and better production performance. This is because of the increased fracture complexity in spite of the impact of stress shadow effects leading to shorter fractures. The calibrated models suggest that most of the fractures are planar in the Eagle Ford shale. The well with wider cluster spacing tends to develop longer fractures but the well with tighter cluster spacing has better stimulated reservoir volume with enhanced permeability, thus resulting in better drainage volume and production performance. From the optimization runs under different reservoir conditions, our results seem to indicate that when natural fractures are present or when stress anisotropy is high with no natural fractures, the wells with tighter cluster spacing tend to outperform the wells with wider cluster spacing. However, severe stress shadow effect is observed when stress anisotropy is low with no natural fractures, likely making tighter cluster spacing wells less favorable.
The calibrated fracture geometries and properties with a unique set of Eagle Ford field data explain the performance variation for completions using different cluster spacing within the reservoir and provides insight into optimal cluster spacing under different reservoir conditions (low vs high stress anisotropy and with/without natural fractures).
Production data and analytical models derived from coupling the linear flow in the reservoir and the linear flow in hydraulic fractures were used in this study to optimize fracture spacing for maximizing productivity of shale oil and gas wells through refracturing. This study concludes that productivity of multi-fractured horizontal wells is inversely proportional to the fracture spacing. The shortest possible fracture spacing should be used to maximize well productivity through refracturing. This supports the practice of massive volume fracturing where as many as perforation clusters with the shortest possible spacing are used for pumping massive proppant into the created hydraulic fractures. Production data analysis indicates that the multi-fractured horizontal oil and gas wells could have higher productivity if they were fractured with less perforation cluster spacing. Mathematical model analysis implies that reducing the cluster spacing from 70 f t t o 15 f t t h r o u g h r e f r a c t u r i n g c a n d o u b l e d w e l l p r o d u c t i v i t y, w i t h t h e M i n i m u m Re q u i r e d C l u s t e r S p a c i n g (MRCS) determined by well completion constraints (packers, perforation clusters, and casing couplings). Result can be checked for fracture trend interference on the basis of analyses of pressure transient data or production data.