Maryland

Drilling in the Appalachian basin in Pennsylvania has evolved since its inception. Operators have shifted their focus from mere wellbore delivery to delivering wells in the shortest amount of time to reduce risks and costs, as well as drive efficiency. This paper presents a case study in which offline cementing helped improve operation efficiency by reducing drilling times and provided significant cost savings.

Offline cementing is not a new concept. In Q4 2015, an operator drilling in the Eagle Ford shale began the movement of their program toward offline cementing of both the surface and production casings. The operator determined that reducing flat time was crucial to create a cost savings (Hsieh 2018). When another operator began their 2018 drilling program in northeastern Pennsylvania, improving efficiencies was discussed with the service company. After quantifying the experience obtained during a previous project, the service company proposed offline cementing because of the economic benefits it could provide.

The service company was able to cement both the surface and intermediate casing strings offline while the operator skidded to the next well to begin rigging up. All surface casings were drilled and cemented offline and the rig skidded back to drill for the intermediate casings, which were also cemented offline. Approximately 15 hours was saved by skidding between surface strings, and another 16 hours was saved between intermediate casings.

This paper discusses the successful use of offline cementing during drilling operations in northeastern Pennsylvania. The flat time reduction achieved during this drilling program can be quantified into a cost savings of approximately USD 80,000 per well.

Operators continue their quest to better understand and design completion strategies to maximize reservoir contact and optimize well spacing. This paper presents a case study that analyzes completion design effectiveness, using pressure data acquired from isolated monitor stages on offset wells during treatment of adjacent wells. The method was employed on three wells of a seven-well pad in the Marcellus, to assess fracture growth and evaluate the performance of employing intra-stage and inter-stage diversion.

Poromechanically-induced pressure responses on isolated monitor stages on offset wells during treatment of an adjacent well, are compared to a fully coupled, three-dimensional, finite element effective stress model, to calculate dominant fracture geometries that correspond to the pressure response induced in the rock. The initiation points and ascending magnitudes of the responses approaching the isolated monitor stage qualify the performance of inter-stage diversion, whereas the fracture growth trends and geometries speak for the efficacy of the intra-stage diversion and overall stage design.

The first well utilized inter-stage diversion and dissolvable plugs to isolate stages; the second well utilized intra-stage diversion to improve cluster efficiency with regular frac plugs for zonal isolation; and, the third well employed regular frac plugs with no use of diversion. This presented a unique opportunity to compare and analyze the fracture growth rates, trends, and geometries, while applying inter-stage diversion and frac plug completion designs for zonal isolation on the same pad.

This paper is a comparative study to understand the value of using inter-stage diversion, along with dissolvable plugs in place of composite frac plugs, after every stage to attain zonal isolation. In addition, completed stages utilized different fluid designs, providing the opportunity to analyze the impact of fluid design on fracture growth trends and diverter performance. The results are interpreted using pressure data-derived fracture maps with production data, which point to the performance of various completion strategies, using an entirely new diagnostic method.

The artificial lift system (AL) is the most efficient production technique in optimizing production from unconventional horizontal oil and gas wells. Nonetheless, due to declining reservoir pressure during the production life of a well, artificial lifting of oil and gas remains a critical issue. Notwithstanding the attempt by several studies in the past few decades to understand and develop cutting-edge technologies to optimize the application of artificial lift in tight formations, there remains differing assessments of the best approach, AL type, optimum time and conditions to install artificial lift during the life of a well. This report presents a comprehensive review of artificial lift systems application with specific focus on tight oil and gas formations across the world. The review focuses on thirty-three (33) successful and unsuccessful fieldtests in unconventional horizontal wells over the past few decades. The purpose is to apprise the industry and academic researchers on the various AL optimization approaches that have been used and suggest AL optimization areas where new technologies can be developed.

In the past ten years, hydraulic fracturing technology and strategies have made major improvements in the operational efficiency and economic performance of shale well completions. Much of this advancement was derived in the past three years as a response to the global downturn in oil and gas commodity pricing. Mature shale plays across the United States have a surplus inventory of horizontal wells employing highly inefficient completions styles. Amid the low oil pricing environment, operators in the Bakken and Eagle Ford were capable of revitalizing these prior generation wells with great success through re-fracturing programs. In many cases, production of these re-fractured wells rivaled the production of newly drilled and completed shale wells both in terms of initial production post re-fracture as well as extended interval cumulative production. These re-fracturing programs allowed producers to achieve tremendous gains in production while minimizing drilling activity. Although re-fracturing began as a highly economical method to improve production during a time of depressed oil pricing, it is still being used today to improve the production of additional wells recognized as top-tier candidates.

By developing a specific set of criteria to select wells for re-fracturing, these programs can be successfully employed in the Appalachian Basin to improve the economics of gas wells, mitigating the effects of highly discounted natural gas pricing. After the explanation of well candidacy, an economic sensitivity analysis was implemented to illustrate the impacts a strong re-fracturing program could make for operators in the Northeast through a comparison of public data showing production and total reserves for both in and out-of-basin re-fracturing programs. Additionally, while this paper focuses on re-fracturing as it relates to shale formations it also includes information as to how re-fracturing relates to conventional formations.

After looking at the incremental economics of re-fracturing programs implemented in shale plays across the United States and in-basin data, the impacts of gas well re-completion can be fully quantified and understood through the application of probabilistic modeling. Additionally, this modeling further delineates re-completion candidacy by identifying which wells pose higher risks in economic metrics.

Very little information has been published regarding the impacts a re-fracturing program could have in the Appalachian Basin. As the field matures, the topic of re-completions will become increasingly important, and this analysis will allow operators to have a greater understanding of the impacts of refracturing shale gas wells in the Northeast.

The Marcellus formation has begun to attract more attention from the oil and gas industry. Despite being the largest shale formation and biggest source of natural gas in the United States, it has been the subject of little research. To fill this gap, this study experimentally examined the rock properties of twenty core samples from the formation.

Five tests were performed on the core samples: X-ray computerized tomography (CT) scan, porosity, permeability, ultrasonic velocity, and X-ray diffraction (XRD). CT-scans were performed to identify the presence of any existing fracture(s). Additionally, helium was injected into the core samples at four different pressures (100 psi, 200 psi, 300 psi, and 400 psi) to determine the optimal pressure for porosity measurements. Complex Transient Method was employed to measure the permeabilities of the core samples. Ultrasonic velocity tests were conducted to calculate the dynamic Young's moduli (E) and the Poisson's ratios (ν) of the core samples at various confining pressures (in increments of 750 psi between 750 psi and 4,240 psi). Finally, the mineralogical compositions of the core samples were determined using the XRD test.

The results of the CT-scan experiments revealed that seven core samples contained fractures. The porosity tests yielded an optimal pressure of 200 psi for porosity measurement. The measured porosities of the samples were between 6.43% and 13.85%. The permeabilities of the samples were between 5 nD and 153 nD. The results of the ultrasonic velocity tests revealed that at the confining pressure of 750 psi, the compressional velocity (V_p) ranged from 18,411 ft/s to 19,128 ft/s and the average shear velocities (V_s1 and V_s2) ranged from 10,413 ft/s to 11,034 ft/s. At the same confining pressure, the Young's modulus and Poisson's ratio ranged from 9.8 to 10.8 million psi and 0.25 to 0.28, respectively. Increase in the confining pressure resulted in increases in the V_p, V_s, Young's moduli, and Poisson's ratios of the samples. The results of the XRD test revealed that the samples were composed of calcite, quartz, and dolomite.

This study is one of the first to characterize core samples obtained from the formation outcrop by performing five tests: CT-scan, porosity, permeability, ultrasonic velocity, and XRD. The results provide detailed insights to researchers working on the formation rock properties.

In shale formations, operators are constantly seeking new technologies to improve proppant transport and conductivity in order to boost production. A novel technique known as surface modified proppant (SMP) has been pumped in more than a dozen wells in the United States, with proven results of increased production. This paper demonstrates and analyzes a case study for a Marcellus shale development where two wells are presented. Well A applied the SMP technique while the offset, Well B, was stimulated without the technology. After three years, Well A yielded an 18% increase in normalized cumulative gas production over the offset Well B.

In presenting the benefits of this technique, the paper provides a brief overview of the development of the conductivity enhancer; the case study; 3D reservoir and hydraulic fracturing simulator selection; model setup and simulation results. SMP is a chemical additive that, when pumped, creates a buoyancy effect of proppant particles upon entering the fracture network. This dynamic SMP application also propels proppant transportation, prevents proppant settling and enhances the fracture network conductivity by increasing the volume by which sand inhabits the fracture network. Increasing the proppant pack height enables deeper penetration into the fracture network, allowing for an increase in proppant distribution and ultimately enhancing the stimulated rock volume (SRV). We have been able to prove the application in both the lab and field scale tests. The impact of the SMP proppant is investigated by performing numerical simulations of hydraulic fracturing and subsequent production.

Along with clear results showing better proppant placement using the simulator with the conducted study, we further explain the completion effectiveness. We outline advantages and the ease of pumping the SMP, including design optimization, thus making this technology cost beneficial.

Hydraulic fracturing is a typical and vital technique applied in shale gas reservoir development. Numerical simulation used to be a common tool to optimize the parameters in hydraulic fracturing design determining the stage numbers, injection pressure, proppant amount, etc. However, the current understanding of shale gas storage and transport mechanism (e.g. adsorption/desorption, diffusion) is basically adopted from the lessons learned from coal seams through past experience, which might not help an efficient numerical simulation development.

In this study, how artificial intelligence assisted data driven models assist the hydraulic fracturing design in shale gas reservoir is discussed. It starts by collecting field data and generate a spatial-temporal database including reservoir characteristics, operational/production information, completion/stimulation data and other variables, Neural Network models are then developed to study the impacts of all parameters on gas production as well as perform history matching of the field history. The AI assisted model with acceptable matching of field data can be used to model different hydraulic fracturing design scenarios and provide predictions on well production.

Molecular diffusion plays an important role in oil and gas migration and transport in tight shale formations. However, there are insufficient reference data in the literature to specify the diffusion coefficients within a porous media. This study aims at calculating diffusion coefficients of shale gas, shale condensate, and shale oil at reservoir conditions with CO₂ injection for EOR/EGR. The large nano-confinement effects including large gas-oil capillary pressure and critical property shifts on diffusion coefficient are examined. An effective diffusion coefficient that describes the diffusion behavior in a tight porous solid is estimated by using tortuosity-porosity relations as well as the measured shale tortuosity from 3D imaging techniques. The results indicated that nano-confinement could affect the diffusion behavior through altering the phase properties, such as phase compositions and densities. Compared to bulk phase diffusivity, the effective diffusion coefficient in a porous shale rock is reduce by 10² to 10⁴ times as porosity decreases from 0.1 to 0.03.

The density distribution of hydrocarbon molecules in Nano-pore media affects the storage of gas, particular for shale reservoir which contains rich organic matters. The density distribution can reveal the adsorption effect which is related to the gas storage mechanism. In literature, researchers proposed using local density theory such as Lennard Jones Potential in lieu of molecular dynamics (MD) simulation and laboratory measurement because of its high computation performance. Core sample study shows that many pores in organic matter have cylindrical shape, but the curvature effect on gas storage has not been studied. Therefore, the thorough validation of this approximation needs to be done for different pore geometries, particularly for a multiple components system. In this study, we propose to study the shale gas storage under the reservoir conditions by a thorough comparison between the Lennard Jones Potential with Peng-Robinson EoS (LJ-PREOS) and equilibrium molecular dynamics simulation for cylindrical pores. We first compare the LJ-PREOS for a single component, and then extend the study to a binary system. The purpose of this comparison to quantify the boundaries under which the LJ-PREOS can be used as a proxy to study the gas storage and adsorption effect in shale formation. After Comparing the results from equilibrium MD simulation with new SLD-PR model, for the single component system, the density on the both sides (close to the pore wall) is much higher than the density on the center, which means the cylindrical wall has a significant adsorption effect on methane molecule. For the binary component system, the mixture density distribution is similar to the single component system, which is higher density closer to the wall and lower density on the center. Furthermore, from the MD simulation results, for the density distribution of each single component in binary system, it is clearly show that both components are still under adsorption effect from the wall, but the butane molecule largely concentrate close to the edge of pore, which means the cylindrical wall has larger impact on butane molecule than methane molecule. With the validated model, we developed a framework to estimate the gas storage capacity of the organic matters in shale formation with different pore size distributions (PSD). Neglecting PSD may lead to 30% under estimation of gas storage in shale gas formation.

To our knowledge, this is first validation of cylindrical pore adsorption for a multiple components system using MD modeling even though many researchers have used this hypothesis in their studies. We also proposed a new framework of estimating gas storage capacity in shale formation without distinguishing the adsorption and free gases in the organic pores with the effect of pore size distribution.

North American market with growing trend of unconventional shale gas reservoirs has warranted rapid development in hydraulic fracturing technology. The long horizontal wells are completed using multi zone plug and perf method that requires multiple zones to be fracked optimally to minimize nonproductive time (NPT). Frac plugs plays vital role in hydraulic fracturing in isolating the multiple zones of the wellbore for operations up to 10,000 psi pressure and 250°F temperature. In this paper advanced computational analysis is conducted to optimize the composite frac plug design for successful operations. Comprehensive laboratory testing is conducted, and digital solutions are compared against the test data to validate the new composite frac plug design. The traditional frac plug design requires effort in milling out the plug and further flushing out the cuttings that adds to the operational time. An alternative is to utilize composite plug that allows ease in milling and reduction in cuttings than traditional design. Numerical analysis is conducted to evaluate the feasibility of composite frac plug design utilizing three-dimensional finite element analysis (FEA) simulations to predict the slip holding capacity. Extensive laboratory testing is conducted for the composite frac plug to validate the digital analysis results. FEA simulations are performed for different configurations of frac plug design by varying number of slip buttons and composite material for slips. FEA results underscored best possible slip button configuration that can successfully work at desired pressure and temperature. Laboratory testing corroborated with digital analysis results and indicated as efficient design that reduced NPT and ensured successful hydraulic fracturing operations. This work assisted in optimizing design quickly and reduced time and cost associated with laboratory testing. This work elucidates use of digital solutions along with laboratory testing for design optimization of composite frac plug. This frac plug has been successfully utilized for several jobs in Marcellus shale play.