Technological advancements have recently been directed toward development and optimization of horizontal completions in unconventional reservoirs, with the ultimate objective of increasing asset performance and value. Unconventional plays are being completed with ever-longer laterals, tighter stage spacing, and high rate slickwater applications designed with increasingly larger volumes of sand to create increased reservoir contact area for greater hydrocarbon recovery. Success is predicated upon overcoming the limited transport capabilities of slickwater. The benefit of higher injection rates employed to enhance proppant transport is soon lost as the lateral velocity declines exponentially with distance from the wellbore, allowing the sand to fall rapidly to the bottom of fractures, resulting in propping only a fraction of the created fracture area. While there are advantages to the use of slickwater and sand for unconventional applications, the transport characteristics inherent to slickwater/sand slurries suggest significant limitations to step-changes in hydrocarbon recovery.
Near-neutrally buoyant, ultra-lightweight proppant is a proven solution to make productive the otherwise non-propped area. Several previous studies in parallel plate slot flow models have shown ULWP-1.05 is transported well in slickwater, whereas sand settles rapidly to form a dune even at high flow rates. Such behavior is intuitive given the near-neutrally buoyant ULWP has an Apparent Specific Gravity of 1.05, in contrast to the 2.65 ASG of sand and the 1.0 ASG of water.
Two new proppant transport models have recently been introduced, including a slot with multiple fracture branches and, a 3D complex network flow model designed to imitate flow through a lateral wellbore into a complex fracture network. In both, the ULWP-1.05 was observed to be transported near-homogeneously with the fluid to the extremities of the apparatus. Conversely, small mesh sand tended to stay in the lower sections of the models and to deposit prior to reaching the extremities.
As a prelude to ULWP-1.05 field application in Permian Basin extended length horizontal wells, proppant transport and fracture conductivity data for the near-neutrally buoyant ULWP-1.05 were used in fracture models to optimize proppant placement for maximizing conductive fracture area, with iterations to optimize well performance in production simulations. A desired outcome of this endeavor is the development and validation of an optimized stimulation design exhibiting materially enhanced well performance.
This paper includes analyses and observations from the proppant transport testing, fracture conductivity testing, discussion of the subsequent fracture designs and production simulations, and comparison of the production simulations with production experienced in field applications. Performance of slickwater fracs with sand alone and, with both sand and near neutrally buoyant ULWP are compared. Lessons learned may be used to substantially increase the conductive fracture area of unconventional wells, optimizing production performance and stimulated reservoir recovery efficiency.
Cha, Minsu (Texas A&M University) | Alqahtani, Naif B. (King Abdulaziz City for Science and Technology) | Yao, Bowen (Colorado School of Mines) | Yin, Xiaolong (Colorado School of Mines) | Kneafsey, Timothy J. (Lawrence Berkeley National Laboratory) | Wang, Lei (Colorado School of Mines) | Wu, Yu-Shu (Colorado School of Mines) | Miskimins, Jennifer L. (Colorado School of Mines)
A laboratory study of cryogenic fracturing was performed to test its ability to improve oil/gas recovery from low-permeability reservoirs. Our objective is to develop well-stimulation technologies using cryogenic fluids [e.g., liquid nitrogen (LN)] to increase permeability in a large reservoir volume surrounding wells. The new technology has the potential to reduce formation damage caused by current stimulation methods and minimize or eliminate water usage.
The concept of cryogenic fracturing is that a sharp thermal gradient (thermal shock) created at the surfaces of formation rocks by applying cryogenic fluid can cause strong local tensile stress and start fractures. We developed a laboratory system for cryogenic fracturing under true-triaxial loading, with LN-delivery/control and -measurement systems. The loading system simulates confining stresses by independently loading each axis up to approximately 5,000 psi on 8x8x8-in. cubes. Temperature in boreholes and at block surfaces and fluid pressure in boreholes were continuously monitored. Acoustic and pressure-decay measurements were obtained before and at various stages of stimulations. Cubic blocks (8x8x8-in.) of Niobrara shale, concrete, and sandstones were tested, and stress levels and anisotropies varied. Three schemes were considered: gas fracturing without cryo-stimulation, gas fracturing after low-pressure cryogen flow-through, and gas fracturing after high-pressure cryogen flow-through.
Results from pressure-decay tests show that LN stimulation clearly increases permeability, and repeated stimulations further increase the permeability. Acoustic velocities and amplitudes decreased significantly after cryo-stimulation, indicating fracture creation. In the gas fracturing without the stimulation, breakdown (complete fracturing) occurs suddenly without any initial leaking, and major fracture planes form along the plane containing principal-stress and intermediate-stress directions, as expected theoretically. However, in the gas fracturing after cryogenic stimulations, breakdown occurred gradually and with massive leaking because of thermal fractures created during stimulation. In addition, the major fracture direction does not necessarily follow the plane containing the principal-stress direction, especially at low confining-stress levels. In tests, we observed that cryogenic stimulation seems to disrupt the internal stress field. The increase in borehole temperature after stimulation affects the permeability of the specimen. When a stimulated specimen is still cold, it maintains high permeability because fractures remain open and local thermal tension is maintained near the borehole. When the rock warms back, fractures close and permeability decreases. In these tests, we have not used proppants. Overall, fractures are clearly generated by low- and high-pressure thermal shocks. The added pressure of the high-pressure thermal shocks helps to further propagate cryogenic fractures generated by thermal shock. Breakdown pressure is significantly lowered by LN stimulation, with observed breakdown-pressure reductions up to approximately 40%.
Alqatahni, Naif B. (Colorado School of Mines) | Cha, Minsu (Colorado School of Mines) | Yao, Bowen (Lawrence Berkeley National Laboratory) | Yin, Xiaolong (Colorado School of Mines) | Kneafsey, Timothy J. (Colorado School of Mines) | Wang, Lei (Colorado School of Mines) | Wu, Yu-Shu | Miskimins, Jennifer L.
We have performed a laboratory study of cryogenic fracturing for improving oil/gas recovery from low-permeability shale and tight reservoirs. Our objective is to develop well stimulation techniques using cryogenic fluids, e.g. liquid nitrogen (LN) to increase permeability in a large reservoir volume surrounding wells. The new technology has the potential to reduce formation damage created by current stimulation methods as well as minimize or eliminate water usage and groundwater contamination.
The concept of cryogenic fracturing is that sharp thermal gradient (thermal shock) created at the rock surface by applying cryogenic fluid can cause strong local tensile stress and initiate fractures. We developed a laboratory system for cryogenic fracturing under true triaxial loading, with a liquid nitrogen delivery/control and measurement system. The loading system simulates confining stresses by independently loading each axis up to about 5000 psi on 8"×8"×8" cubes. Both temperature in boreholes and block surfaces and fluid pressure in boreholes were continuously monitored. Acoustic and pressure-decay measurements are obtained before and at various stages of stimulations. Cubic blocks (8"×8"×8") of Niobrara shale, concrete, and sandstones have been tested, and stress levels and anisotropies are varied. Three schemes are considered: gas fracturing without cryo-stimulation, gas fracturing after low-pressure cryogen flow-through, gas fracturing after high-pressure flow-through.
Pressure decay results show that liquid nitrogen stimulation clearly increases permeability, and repeated stimulations further increase the permeability. Acoustic velocities and amplitudes decreased significantly following cryo-stimulation indicating fracture creation. In the gas fracturing without the stimulation, breakdown (complete fracturing) occurs suddenly without any initial leaking, and major fracture planes form along the plane containing principal stress and intermediate stress directions as expected theoretically. However, in the gas fracturing after cryogenic stimulations, breakdown occurred gradually and with massive leaking due to thermal fractures created during stimulation. In addition, the major fracture direction does not necessarily follow the plane containing principal stress direction, esp. at low confining stress levels. In tests, we have observed that cryogenic stimulation seems to disrupt the internal stress field. The increase of borehole temperature after stimulation affects the permeability of the specimen. While a stimulated specimen is still cold, it keeps high permeability because fractures remain open and local thermal tension is maintained near the borehole. When the rock becomes warm again, fractures close and permeability decreases. In these tests, we have not used proppants. Overall, fractures are clearly generated by low and high-pressure thermal shocks. The added pressure of the high-pressure thermal shocks helps to further propagate cryogenic fractures generated by thermal shock. Breakdown pressure is significantly lowered by LN stimulation with breakdown pressure reductions up to about 40% observed.
Sun, Hong (Baker Hughes) | Zhou, Jia (Baker Hughes) | Brannon, Harold (Baker Hughes) | Satya Gupta, D. V. (Baker Hughes) | Ault, Marshall (Baker Hughes) | Carman, Paul (Baker Hughes) | Wheeler, Richard (Baker Hughes)
The primary objective of hydraulic fracture stimulation is to use "ideal" fracturing fluids to initiate and propagate fractures, transport proppant and place a conductive proppant pack in the created fracture. Resident hydrocarbons may be more easily produced in the created fracture broadways. Thus, optimization of conductive fracture area is perhaps the most critical tenets of fracture stimulation. The effective fracture area is characterized by the conductive fracture height and length, and is often compromised by the inability to place the proppant throughout the created fracture area. Several attempts have been implemented to improve the effective fracture area, such as hybrid fracturing, ultralightweight proppant (ULWP) delivery, channel fracturing, and slug fracturing. The techniques are all based on viscosity-governed proppant transport mechanisms.
This paper proposes a new fluid system for nearly perfect proppant suspension to improve proppant transport and vertical distribution in fractures. It improves effective fracture height by placing proppant across the complete productive interval under downhole conditions when properly applied. This leads to better transverse and vertical placement of proppant in the fracture and significantly increases the fractured surface area. The degradability of the fluid can lead to non-damaged fracture conductivity with time by internal or external stimulus.
Criteria and considerations for successful applying such fluids to optimize proppant placement and maximize fracture conductivity are discussed. Job design is elaborated in terms of fluid mechanics and proppant transportation mechanics differences and benefits over traditional crosslinked gel systems. The execution, experiences, and subsequent well performance of treatment applications results are compared to offsets treated with a traditional crosslinked gel system.
Most of the shale reservoirs in US land are naturally fractured. The fracture intensity and types vary from one shale to another. Even within the same shale in the same field, the heterogeneity of fracture intensity can be often expected to be high in a horizontal well. The current popular geometrical completion design can potentially ignore the existence of natural fractures. Hence, maximizing stimulation efficiency without understanding existing natural fractures can be a challenge. In this paper, study was made of the majority of the published case studies related to natural fractures in the US shales in the last 20 years. The evidence of natural fractures from either outcrops or subsurface data, i.e. core, borehole images, or other data is summarized for each studied shale. The latest studies show that the hydraulic fracture propagation can be strongly influenced by existing natural fractures regardless of whether they are open or closed. The roles of existing fractures in the shales include: 1) providing enhanced reservoir permeability for improved productivity if they are open and effectively connected by hydraulic fractures; 2) promoting much better fracturing network complexity regardless of whether they are open or closed prior to the stimulation; 3) giving possible negative impact sometimes, i.e. high water cut, if they are connected with wet zones below or above the reservoirs. It can be concluded that engineered completion designs that employ accurate knowledge of natural fracture data, in-situ stresses, and other reservoir and completion quality indicators as inputs can provide opportunities for enhancing stimulation efficiency and fracturing network complexity. This in turn can lead to better connectivity to a larger reservoir volume and access to more drainage area in the shales.
The US shale gas story actually featured natural fractures. William Hart, a local gunsmith, drilled the first commercial natural shale gas well in US in Fredonia, Chautauqua County, NY in 1821, in shallow, low-pressure rock with fractures . The well was first dug to a depth of 27ft in a shale which outcropped in the area, then later drilled to a depth of 70ft using 1.5 inch diameter borehole. The produced gas was piped to an innkeeper on a stagecoach route. Then the well was produced without any stimulation for 37 years until 1858 when it supplied enough natural gas for a grist mill and for lighting in four shops. It was a combination of the idea from Mr. Hart to drill the well and the presence of the natural fractures in the gas shale that made the 1st commercial shale gas discovery possible in shale gas history.
In this paper a fast track reservoir modeling and analysis of the Lower Huron Shale in Eastern Kentucky is presented. Unlike conventional reservoir simulation and modeling which is a bottom up approach (geo-cellular model to history matching) this new approach starts by attempting to build a reservoir realization from well production history (Top to Bottom), augmented by core, well-log, well-test and seismic data in order to increase accuracy. This approach requires creation of a large spatial-temporal database that is efficiently handled with state of the art Artificial Intelligence and Data Mining techniques (AI & DM), and therefore it represents an elegant integration of reservoir engineering techniques with Artificial Intelligence and Data Mining. Advantages of this new technique are a) ease of development, b) limited data requirement (as compared to reservoir simulation), and c) speed of analysis.
All of the 77 wells used in this study are completed in the Lower Huron Shale and are a part of the Big Sandy Gas field in Eastern Kentucky. Most of the wells have production profiles for more than twenty years. Porosity and thickness data was acquired from the available well logs, while permeability, natural fracture network properties, and fracture aperture data was acquired through a single well history matching process that uses the FRACGEN/NFFLOW simulator package.
This technology, known as Top-Down Intelligent Reservoir Modeling, starts with performing conventional reservoir engineering analysis on individual wells such as decline curve analysis and volumetric reserves estimation. Statistical techniques along with information generated from the reservoir engineering analysis contribute to an extensive spatio-temporal database of reservoir behavior. The database is used to develop a cohesive model of the field using fuzzy pattern recognition or similar techniques. The reservoir model is calibrated (history matched) with production history from the most recently drilled wells. The calibrated model is then further used for field development strategies to improve and enhance gas recovery.
Lower Huron Shale - Gas production from Devonian Shale in Eastern Kentucky goes all the way back to 1892, when the first well near Pikeville was drilled. Drilling and production reached its peak in the second half of the 20th century when hydraulic fracturing was introduced. And that is when, due to the specific nature of the reservoir, efficient gas production was established. The most prolific horizon of Devonian Shale in Eastern Kentucky is the Lower Huron Shale, which is Ohio Shale member. Over 80% of Devonian gas production comes from the Big Sandy Gas Field with more than 10,000 completed wells. (Figure 1)
Although high gas flow rates from shales are a relatively recent phenomenon, the knowledge bases of shale-specific well completions, fracturing and shale well operations have actually been growing for more than three decades and shale gas production reaches back almost one hundred ninety years. During the last decade of gas shale development, projected recovery of shale gas-in-place has increased from about 2% to estimates of about 50%; mainly through the development and adaptation of technologies to fit shale gas developments. Adapting technologies, including multi-stage fracturing of horizontal wells, slickwater fluids with minimum viscosity and simultaneous fracturing, have evolved to increase formation-face contact of the fracture system into the range of 9.2 million m2 (100 million ft2) in a very localized area of the reservoir by opening natural fractures. These technologies have made possible development of enormous gas reserves that were completely unavailable only a few years ago. Current and next generation technologies promise even more energy availability with advances in hybrid fracs, fracture complexity, fracture flow stability and methods of re-using water used in fracturing. This work surveyed over 350 shale completion, fracturing and operations publications, linking geosciences and engineering information together to relay learnings that will identify both intriguing information on selective opening and stabilizing of micro-fracture systems within the shales and new fields of endeavor needed to achieve the next level of shale development advancement.
Schepers, Karine Chrystel (Advanced Resources International) | Nuttall, Brandon C. (Advanced Resources International) | Oudinot, Anne Yvonne (Advanced Resources International) | Gonzalez, Reinaldo Jose
Shale gas and other unconventional gas plays have become an important factor in the United States energy market and are often referred to as statistical plays due to their high heterogeneity. They present real engineering challenges for characterization and exploitation, and their productivity depends upon an inter-related set of reservoir, completion and production characteristics.
The Devonian Ohio shale of eastern Kentucky is the State's most prolific gas producer. The gas shale underlies approximately two-thirds of the state, cropping out around the Bluegrass Region of central Kentucky and having a sub crop beneath the Mississippi Embayment in western Kentucky.
This paper describes the reservoir modeling and history matching of a Devonian Gas Shale Play, eastern Kentucky, its potential for CO2 enhanced gas recovery and storage.
A geologic model of the shale has been compiled from mineralogical, petrographic, core, production, and wireline data. The COMET3 multi-phase, dual porosity simulator is being used to investigate CO2 injection into the shale for enhanced gas recovery. To accomplish this, a subset of wells surrounding the potential injection site has been selected for further study. These eight wells cover approximately 5,300 acres of productive shale. The reservoir was subdivided into the Upper Ohio and Lower Huron members. To capture geological heterogeneity, gas production rates for these wells served as a proxy to characterize fracture permeability using geostatistical methods. Well production was history matched applying an automated process. Finally, several CO2 injection scenarios spanning huff-n-puff to continuous injection were reviewed to evaluate the enhanced gas recovery potential and assess the CO2 storage capacity of these shale reservoirs.
Increased emissions of carbon dioxide (CO2) are being linked to global climate change and are generating considerable public concern. This concern is driving initiatives to develop carbon management technologies, including the geologic sequestration of CO2. One option for sequestration may be the Appalachian Basin's Devonian black shale, a continuous, low-permeability, fissile, fractured, organic-rich rock that is both the source and trap for natural gas (primarily methane). In gas shales, natural gas occurs as free gas in the fracture system and is adsorbed on clay and kerogen surfaces, very similar to the way methane is stored within coal beds.
Horizontal wells have become the "industry standard?? for unconventional and tight formation gas reservoirs. Because these reservoirs have poorer quality pay it takes a good well planned completion and fracture stimulation(s) to make an economic well. Even in a sweet spot in the unconventional and tight gas reservoir good completion and stimulation practices are required otherwise a marginal or uneconomic well results. But what are good completion and stimulation practices in horizontal wells? What are the objectives of horizontal wells and how do we relate the completion and stimulation(s) to achieving these goals? How many completions/stimulations do we need for best well performance and/or economics? How do we maximize the value from horizontal wells? When should a horizontal well be drilled longitudinally or transverse? These are just a few questions to be addressed in the subsequent paragraphs.
This paper focuses on some of the key elements of well completions and stimulation practices as they apply to horizontal wells. Optimization studies will be shown and used to highlight the importance of lateral length, number of fractures, inter-fracture distance, fracture half-length, and fracture conductivity. These results will be used to discuss the various completion choices such as cased and cemented, open hole with external casing packers, and open hole "pump and pray?? techniques. This paper will also address key risks to horizontal wells and develop risk mitigation strategies so that project economics can be maximized. In addition, a field case study will be shown to illustrate the application of these design, optimization, and risk mitigation strategies for horizontal wells in tight and unconventional gas reservoirs.
This work provides insight for the completion and stimulation design engineers by:
1. Developing well performance and economic objectives for horizontal wells and highlighting the incremental benefits of various completion and stimulation strategies,
2. Establishing well performance and economic based criteria for drilling longitudinal or transverse horizontal wells,
3. Integrating the reservoir objectives and geomechanic limitations into a horizontal well completion and stimulation strategy,
4. Identifying horizontal well completion and stimulation risks and risk mitigation strategies for pre-horizontal well planning purposes.
The Lower Huron Shale can take claim as one of the earliest discovered sources of natural gas. As with all the shales though, extracting its reserves has been the challenge. To start, the physical properties of shale are not the same as typical sandstones, limestone, and siltstones that are targeted to produce natural gas. Along with this, the mechanisms for which the hydrocarbons are stored in place and transported are unique as well.
Shale is notorious for having ultra-low permeability (µD) and because of this, the primary storage and transport of hydrocarbons comes through the series of natural fracture networks within the shale. Fracturing the shale then becomes a search for the natural fracture network that is holding the hydrocarbons.
After drilling is completed, the question becomes exactly how do we fracture this well to achieve the best results? There are several ways to stimulate the wells that have been drilled in the Lower Huron. They range from straight nitrogen stimulation to varying quality foam stimulations. These two main methods of fracturing can then be broken down into many different style stimulations by changing rates, foam qualities, sand volumes and nitrogen volumes.
A couple of things to look at when designing a stimulation job is depth, field of play, thickness of the zone, and its gamma ray reading on the log. This paper will discuss fracture styles and which ones seem to perform better in wells given certain characteristics and what might be changed to produce the best results.