Pre-set or off-depth composite plugs can cause significant non-productive time for a well operator. In the past, fracturing operations using a composite frac or bridge plug that has been pre-set or set off depth required a coiled tubing unit or workover rig to drill the plug out. Then, the well operator could resume the fracturing job or access the wellbore below the plug. However, as this paper demonstrates, composite plug milling via wireline using a tractor and a tractor-based milling tool is a faster, safer, and more cost-effective solution. In a shale well located in the northern panhandle of West Virginia, a composite frac plug was set off- depth. Prior to mobilizing the tractor-based solution to location, the operator attempted pumping approximately 60,000 pounds of sand to sand-cut the off-depth frac plug out of the well. The sand cutting, though, did not work because perforations above the frac plug took the sand. Other tubing-based solutions required more mobilization time and complex logistics for rigging down and/or moving equipment on location. Therefore, the operator chose a wireline-based method for ease of operation, reduced HSE risk, and cost savings. The tractor took 50 minutes to drive down 1718 ft in the lateral to the plug. The milling tool milled the top slips on the frac plug in approximately nine hours, and the tractor then pushed the plug 222 ft downhole on top of the previous frac plug. The total time rigged up on the well was 14 hours, and the total time on location was 18 hours. Although this wireline-based plug-milling method takes several hours to mill a plug, the rig-up and execution is simpler than conventional methods, and associated HSE risks on the wellsite are greatly reduced. The ability to effectively release plugs via wireline provides well operators with another option to complete their objectives, especially when tubing-based methods often take many days or weeks to mobilize at substantial cost to operators.

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 field-tests 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.

This paper presents a method for examining the potential of fracture stimulation in horizontal wells targeting unconventional oil plays. The observation of crossflow among fractures has been of great concern as this phenomenon affects the productivity of producing wells. The cause is related to the effectiveness of fracturing stages, which by itself depends on the rock lithology and brittleness. We identified interaction among fractured intervals from diagnostic modeling of performance data that exhibited cross flows in the wellbore. On wells exhibiting the most prolonged duration of crossflow, we noted the disadvantages of equal space fracturing. We then used the drilling parameters from MWD data for individual wells and computed the d-exponent profiles and noted significant differences in rock brittleness as characterized by their d-exponent data. We examined the d-exponent data using the Hurst coefficient. Wells exhibiting a trend with uniform H coefficient showed the least indications of cross flows from performance data while in wells with significant cross flows we see the nonuniformity of the d-exponent profile examined with the H coefficient method. It is our observation that before fracturing, interval selection with GR log can be enhanced if supplemented with the trend analysis of the d-exponent data.

An E&P operator was developing a reservoir and planned a horizontal well in an area where zones above the target cause drilling problems when trying to build angle and land the horizontal lateral. The operator suffered drilling difficulties on offset wells; therefore, it was decided to change the drilling plan for this prospect. The new plan required drilling through the target reservoir, into the formations below and then drill back up dip to the target. After reaching the base at a measured depth of 14,000 ft. the well plan required drilling up at maximum of 114° until reentering the target reservoir. Because of faulting in the area and required well direction, the target reservoir was dipping up at ∼10° laterally in the direction of the horizontal drilling target. To maintain position in the reservoir, the well had to drilled at ∼100° deviation to a measured depth of 21,100 ft. This wellbore trajectory made normal wireline plug and perforating completion operations extremely difficult. The wellbore trajectory meant high frictions on the wireline when coming off bottom. Also, due to the toe-up trajectory there was risk the wireline tools would slide down the inclined casing during and after plug setting and perforating. If the tool position could not be maintained there was risk the wireline cable could be entangled and a stuck tool could result. If the tools overrun the wireline cable the result could be wireline cable next to the perforating guns when detonated and wireline cable severed. The E&P operator needed to know if this challenge could be met. Alternatives to pump down plug and perforating could be very expensive (estimated $millions): Abandon acreage, Continue drilling attempts building angle above the target, Reposition surface location and drill down dip, Reduce angle and shorten lateral in target, or Coiled tubing conveyed plug and perforating completion. To meet the challenge several new methods and technologies developed for extended laterals were utilized. These products and methods included: advanced risk deployment modeling, jacketed wireline cable, addressable separation tool and downhole tension tool.

Underbalanced drilling via air drilling is deeply rooted in the Northeast United States due to its distinct geology, high rates of penetration (ROP) and drilling efficiency, and low cost of circulating material. The active drilling programs of several independent operators in the Marcellus and Utica Basins are well suited for air drilling down to the final kick off point by virtue of competent, stable formations, low static reservoir pressures, and manageable water ingress to the wells. Air drilling provides near-atmospheric pressure at the borehole bottom, since there is no fluid column with resulting hydrostatic pressure. The result is very high ROP with essentially 100% drilling efficiency, allowing the completion of intervals in one or two bit runs. A service company deployed a cross-functional product development team to optimize oilfield air bits for these applications over the last two years, resulting in decreased drilling costs through increased performance and reliability. The oilfield air drilling environment places unique challenges on drill bit design due to the increased risk of downhole vibrations, corrosion, abrasive wear, heat generation, and seal infiltration of very fine cuttings. The application requirements have increased due to deeper intervals requiring passage through multiple high unconfined compressive strength formations, extended tangent angles, and rising input energy levels. Accordingly, enhancements to both the cutting structures and sealed bearing systems were vigorously pursued. Several cutting structure design iterations were evaluated in both laboratory and field tests. A new sealed bearing system was developed and implemented for increased life and reliability. Modifications to the bit body for stability were included, and the bit hydraulics were further optimized. Through an understanding of the objectives and application challenges, unique solutions were developed for Northeast oilfield air drilling applications. The optimization process for the new air bit designs is described, and the resulting positive performance metrics are presented. Improvements were observed in distance drilled, ROP, seal effective rate, and dull condition. Lessons learned were also used to refine the recommended drilling parameters and practices through the challenging formations encountered in these tangent sections, which can span in excess of 7000 feet. These enhancements all contributed to reduced drilling cost and days per well, for increased rig productivity. The natural gas fields throughout the Marcellus and Utica Basins in the Northeast U.S. continue to deliver rising total gas production for the U.S. and the world through increased capacities in pipelines and LNG trains. Improved drilling performance as documented in this paper are driving continuous improvement in the overall upstream drilling economics of the region.

Research and development drives success in shale plays throughout the world, enabling operators to deploy new drilling, completions, and production technologies to reach more reservoir area and extend the life of production wells. This work demonstrates the development, validation, and deployment of an extreme torque casing connection addressing technical challenges of tubulars in unconventionals. Throughout the well lifetime, Oil Country Tubular Goods (OCTG) experience various loads during the installation, stimulation, and production phases. Some of the challenges experienced during the stimulation and production phases relate to internal and external pressure resistance, sealability, corrosion and cracking, erosion, and wear. Furthermore, with the increase in lateral length and the more demanding well geometries, the OCTG capabilities related to high cycle fatigue, connection runability, and torque limits become more important to safely and efficiently reach the total depth of the well and ensure integrity throughout well life. Another scenario in which the torque limit of an OCTG connection is important is rotating while cementing, a practice undertaken to mitigate sustained casing pressure, improve well integrity, and completion efficiency. We present the key elements in the development of a casing connection that overcomes these challenges and the decision process leading to a prototype. To prove the design concept, a fit-for-purpose testing protocol was adopted to validate its performance, replicating the installation, stimulation, and production phases under the expected loads. Once validated, a pilot involving casing installation, rotation while cementing and stimulation was completed in two wells, and its outcomes will be discussed in this work. This novel casing extreme torque connection, designed to overcome the application challenges, enables the installation of casing in longer laterals, together with the improvement of well integrity through rotation while cementing. The performance of the product, tested through a special procedure while ensuring reliability, was confirmed by the case study from the Niobrara shale. A new connection considering the challenges of wells in unconventional plays must account for several aspects from design to installation. We show the process, from the design stage and validation, leading to successful field deployment.

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.

Drilling problems such as stick slip vibration/hole cleaning, pipe failures, loss of circulation, BHA whirl, stuck pipe incidents, excessive torque and drag, low ROP, bit wear, formation damage and borehole instability, and the drilling of highly tortuous wells have only been tackled using physics-based models. Despite the mammoth generation of real-time metadata, there is a tremendous gap between statistical based models and empirical, mathematical, and physical-based models. Data mining techniques have made prominent contributions across a broad spectrum of industries. Its value is widely appreciated in a variety of applications, but its potential has not been fully tapped in the oil and gas industry. This paper presents a review compiling several years of Data Analytics applications in the drilling operations. This review discusses the benefits, deficiencies of the present practices, challenges, and novel applications under development to overcome industry deficiencies. This study encompasses a comprehensive compilation of data mining algorithms and industry applications from a predictive analytics standpoint using supervised and unsupervised advanced analytics algorithms to identify hidden patterns and help mitigate drilling challenges. Traditional data preparation and analysis methods are not sufficiently capable of rapid information extraction and clear visualization of big complicated data sets. Due to the petroleum industry's unfulfilled demand, Machine Learning (ML)-assisted industry workflow in the fields of drilling optimization and real time parameter analysis and mitigation is presented. This paper summarizes data analytics case studies, workflows, and lessons learnt that would allow field personnel, engineers, and management to quickly interpret trends, detect failure patterns in operations, diagnose problems, and execute remedial actions to monitor and safeguard operations. The presence of such a comprehensive workflow can minimize tool failure, save millions in replacement costs and maintenance, NPV, lost production, minimize industry bias, and drive intelligent business decisions. This study will identify areas of improvement and opportunities to mitigate malpractices. Data exploitation via the proposed platform is based on well-established ML and data mining algorithms in computer sciences and statistical literature. This approach enables safe operations and handling of extremely large data bases, hence, facilitating tough decision-making processes.

Recently, the United States (US) oil and gas industry has dramatically increased its production, primarily due to technological advances in horizontal drilling and hydraulic fracturing. Current hydraulic fracturing practices require a significant amount of water. Section 9.2.1 of the API Recommended Practice (2015) states that of development activities including drilling and completion activites, hydraulic fracturing, typically results in the most significant water use. For context, hydraulic fracturing operations in 2000 used approximately 177,000 gallons of water per oil and gas well. According to USGS, hydraulic fracturing requirements increased to over four million gallons of water per oil well and 5.1 million gallons of water per gas well in 2014 ( USGS, 2015 ). The Environmental Protection Agency's multiyear study found an increasing trend in water use per well attributed to growing numbers of wells drilled, with longer laterals and more stages completed ( Dunn-Norman, et al., 2018 ). Many US oil and gas companies’ annual reports and public communications currently feature sustainability and environmentally-responsible development strategies. However, opportunities to minimize negative environmental impact without affecting the value of a large-scale unconventional development is extremely difficult, particularly in the current low oil price market. Operators throughout the industry are developing water management facilities focused on safe, reliable and environmentally friendly water management practices. This paper discusses utilizing in-situ mechanical rock property data to optimize completion strategies, which can help reduce the negative impacts of hydraulic fracturing, while maintaining, and often increasing, production.

"Gas migration" has been the catch phrase of the Appalachian Basin in the northeastern part of the US for years. As demonstrated in a previous study, optimal displacement efficiency can be obtained by rotating casing during the entirety of the cement operation, providing uniform cement coverage and eliminating gas migration. However, while horizontal well lengths continue to increase, the ability to maintain rotation for the entirety of the cement operation can be severely inhibited. Conventional cement slurries are satisfactory for the majority of wells in both the Marcellus and Utica/Point Pleasant. However, while operators are pushing the limit toward a 20,000-ft measured depth, there is a growing need to rely less on industry best practices written at the onset of shale drilling and expand engineering creativity toward implementing new technologies. With rotation off the table, a service company recommended the combined use of two highly enhanced mechanical property cement slurry technologies to bridge the technology gap from a conventional cementing solution to a more "life of the well" solution. Historically, gas migration from either the Upper Devonian and/or the Marcellus Shale has been proven to be troublesome for the northeastern part of Pennsylvania. When the challenge cannot be addressed with historical best practices, deploying new technology on hand is necessary to achieve the goal. With the more robust functionality of a low-Portland cement design and resin composite cement slurry, the service company's design team was able to combine these two technologies to deliver a dependable barrier tailored to achieve zonal isolation. Optimizing the placement of the resin-composite-based cement slurry itself was pivotal; placement across the problem zones and above the landing point of the horizontal section was necessary. Successful elimination of both pre- and post-fracturing gas migration was achieved without casing rotation during cement slurry placement. The wells were put into production, and the operator has not had to perform any costly remediation operations because the reservoir was properly isolated by means of the primary cementing operation. Enhanced mechanical property cements were proven to be vital for alleviating the concerns of gas migration. These cement systems help prevent Upper Devonian and Marcellus wells from being reworked because of primary cement quality post-completion.

A semi-analytical framework for predicting the onset of sand production in a horizontal well is presented. The approach couples the flow in perforation tunnels with flow in the wellbore itself, to obtain a more accurate estimate of maximum sand free production rate in a well. The elastic equations of equilibrium are combined with the Mohr–Coulomb failure criterion to calculate the critical radius. A numerical, iterative solution method is used to compute the location of the elastic-plastic zone during well production. Instead of computing the pressure change in a cavity, which is difficult to characterize and implement in practice, the proposed model integrates the cavity stability criteria into the perforated wellbore inflow model to determine maximum sand-free wellbore flow rate. In addition to the typical perforation tunnel parameters such as cohesive strength, friction angle and perforation radius considered in past efforts, pressure loss effects in a wellbore (wall friction, acceleration, and fluid mixing) are incorporated into the proposed model. A numerical shooting method is then used to iteratively arrive at the maximum sand free rate for a perforated horizontal wellbore in a reservoir of known properties. Results show that without incorporation of the inflow model, the predicted maximum sand-free rates from prevailing approaches can be over-optimistic. The proposed method can be used to optimize perforation parameters to prevent sanding when designing well completions.

In the late summer of 2009 an American oil and gas producer teamed up with a Canadian pumping service company and performed a series of Liquified Petroleum Gas (LPG) fracturing treatments in Pennsylvania's Marcellus Shale. A total of four stages were pumped on three different vertical wells in three different counties Centre, Lycoming, and Indiana. Questions surrounding damage associated with pumping large volumes of fresh water in nano-to-micro Darcy shale along with environmental pressures about water supply and disposal led to consideration of an alternative, non-aqueous fracturing fluid. A hydraulic fracturing process utilizing 100% LPG as a fracturing fluid to carry proppant into shale or a coal seam or other water sensitive pay zone was developed. The new LPG fluid could be easily viscosified with oil gelling chemicals allowing for excellent proppant transport. LPG was an appealing choice of fracturing fluid because its phase behavior in the Marcellus Shale at bottomhole conditions would theoretically render it non-damaging. The fracturing process brought sand into the gelled LPG so that it could be pumped under high pressure and into created fracture geometry in a pay zone. With respect to well cleanup post-frac LPG held the promise of greater cleanup and improved effective fracture half-lengths. This paper will provide details about the LPG fracs and the resulting production response using a mix of readily available public domain information and information obtained by service providers or vendors. Initially, it was author's intention to use only public data but changes in the local market made access to more information available. A comparison of LPG fracturing treatments with slickwater treated wells will be shown for two of the three wells. Concluding remarks will discuss the current state of LPG fracturing in North America and a possible explanation for production results that did not meet expectations.

A new three-dimensional drillstring model has been developed that determines the static and dynamic behavior of bottom hole assemblies (BHAs) in realistic wellbores. The analysis approach has been validated with field data, and shows a strong agreement between observed and calculated BHA behavior. Several case studies are presented that show the practical use and benefit of the advanced model for, among other applications, unconventional horizontal drilling. A framework is also provided to show how the model can be incorporated into automated engineering processes for operations support. Validation tests were conducted using high-frequency down-hole data measured within a motor- assisted rotary-steerable BHA. The gathered data was used to verify the calculated mechanical loads, predicted lateral natural frequencies of the BHA, estimated directional performance of the down-hole assembly, as well as torsional resonance resulting from High-Frequency Torsional Oscillations (HFTO). Using the validated model, various analyses have been conducted for operators around the globe, in a multitude of different drilling environments, to aid in identifying drilling dysfunctions and optimizing BHA performance. Several case studies are presented that highlight the benefit of the modeling techniques in US unconventional shale plays as well as in the Canadian heavy-oil sands, with noticeable improvements in drilling efficiencies, tool design, and reduced non-productive time (NPT). Results from the field tests show a strong correlation between measured and calculated bending moment values, as well as lateral natural frequencies of the BHA with an average of 3% error across all data sets. The primary source of error is thought to be borehole spiraling, which is quantified through analysis of the down-hole bending moment data. In addition, the model is shown to provide close estimates to actual directional performance of both steerable mud motor and Rotary-Steerable BHAs. However, the directional calculation-measurement comparison does reveal a need to incorporate an ROP-dependency within the directional prediction algorithms. Nevertheless, even with these sources of discrepancy, the modeling approach provides a sensible prediction of the BHA's mechanical and dynamic behavior and, as shown through case studies, can be used as a planning tool for BHA design, an investigative tool for root-cause analysis, or potentially as a real-time optimization tool for avoiding harmful operating conditions.

Traditionally, in order to estimate the production potential at a new, prospective field site via simulation or material balance, one needs to collect various forms of expensive field data and/or make assumptions about the nature of the formation at that site. Decline curve analysis would not be applicable in this scenario, as producing wells need to pre-exist in the target field. The objective of our work is to make first-order forecasts of production rates at prospective, undrilled sites using only production data from existing wells in the entire play. This is accomplished through co-kriging of decline curve parameter values, where the parameter values are obtained at each existing well by fitting an appropriate decline model to the production history. Co-kriging gives the best linear unbiased prediction of parameter values at undrilled locations, and also estimates uncertainty in those predictions. Thus, we can obtain production forecasts at P10, P50, and P90, as well as calculate EUR at those same levels, across the spatial domain of the play. To demonstrate the proposed methodology, we used monthly gas flow rates and well locations from the Marcellus shale gas play in this research. Looking only at horizontal and directional wells, the gas production rates at each well were carefully filtered and screened. Also, we normalized the rates by perforation interval length. We kept only production histories of 24 months or longer in duration to ensure good decline curve fits. Ultimately, we were left with 5,637 production records. Here, we chose Duong’s decline model to represent production decline in this shale gas play, and fitting of this decline curve was accomplished through ordinary least square regression. Interpolation was done by universal co-kriging with consideration to correlate the four parameters in Duongs’ model, which also showed a linear trend (the parameters show dependency on the x and y spatial coordinates). Kriging gave us the optimal decline curve coefficients at new locations (P50 curve), as well as the variance in these coefficient estimates (used to establish P10 and P90 curves). We were also able to map EUR across the study area. Finally, the co-kriging model was cross-validated with leave-one-out scheme, which showed significant but not unreasonable error in decline curve coefficient prediction. We forecasted potential gas production in the study area using co-kriging. Heat maps of decline curve parameters as well as EUR were constructed to give operators a big picture of the production potential in the play. The methods proposed are easy to implement and do not require various expensive data like permeability, bottom hole pressure, etc., giving operators a risk-based analysis of prospective sites. We also made this analysis available to the public in a user-friendly web app.

Narrow annulus is frequently encountered in drilling operations as in Casing while Drilling, Liner Drilling etc. Hydraulics of narrow annulus is a relatively new topic of research in drilling. Current analytical solutions have limited applicability for complex flow regimes affected by casing motion, pipe rotation, eccentricity and cuttings. Therefore, the objective of this research is to develop data-driven statistical learning models which can be very effective in making pressure loss predictions for given operating conditions. The data for proposed supervised learning was obtained from large scale experiments conducted on a narrow annulus wellbore configuration on LPAT (Low Pressure Ambient Temperature) flow loop at TUDRP, Tulsa University Research Projects Group. Exploratory visualizations were used to determine the relationship between operational parameters and pressure drop. Resampling methods, such as cross-validation and bootstrapping, were used to split the dataset into training and test data. Shrinkage and Decomposition technique was applied to make multivariate regression more robust. Comparison was made between different algorithms to determine the best model in terms of Least Mean-Squared-Error (MSE) on test data prediction and interpretability. Multivariate exploratory plots were used for data inference. Relationships between different factors and annular pressure drop were mostly linear. As expected, pressure drop increased with increase in flow-rate, inclination angle, ROP and for non-Newtonian polymeric fluids. Principal Component Analysis (PCA) was performed to reduce the dimensionality of the data set. Approximately 98% of variance in data was explained by 5 principal components and the resulting model produced a MSE less than 1% of median pressure drop. Even though PCA regression model performed well on test data, final model was more difficult to interpret because it does not perform feature selection or even produce coefficient estimates. Therefore, Partial Least Squares (PLS) regression was used which gives better model interpretability as it is supervised by feature-outcome relationship. Shrinkage methods-Lasso and Ridge Regression were also used. These methods add an additional penalty term to Least Square Regression to get a bias-variance tradeoff. Cross-validation was used to select the penalty term that gave the lowest MSE. Both methods produced competitive MSE but performed better than PCA and PLS regression. In conclusion, Lasso-Regression performed the best with lowest error and good interpretability.

The development of shale assets has reached a point where operators face the challenge of infill drilling. The scope of this project is to investigate the impact of neighboring well pads on the performance of a newly developed well/pad. This paper highlights the differences in production performance of "old" pads versus "new" well and analyzes how the depletion history of the existing pads affects the performance of new well. The study area covers two pads: Pad A and Pad B which have 10 and 12 wells respectively; these wells have been producing since 2016 from the dry gas region of Marcellus Shale in southwestern Pennsylvania. Pad A and Pad B are more than 9000 ft apart, and the region between these two pads has potential for future development. For this project, a 3-D reservoir simulation model that includes both pads was built and calibrated to match past performance of Pad A and Pad B. The calibrated simulation model then was utilized for developing new wells. The reservoir simulation model was used to perform a sensitivity analysis on reservoir characteristics and the impact of Pad A and Pad B's depletion history on the performance of new well(s). The workflow involves optimizing the well spacing of proposed well(s) with/without considering the depletion history. Usually, with the very low permeability of shale reservoirs, the depletion history of neighboring wells is expected to affect the performance of newly developed wells. The new wells are considered as a different well pad, and their stimulated reservoir volume does not overlap with the Pad A and Pad B. However, the region average reservoir pressure is reduced due to the Pad A and Pad B production history. In most of shale reservoir numeral simulation studies, the reservoir is considered virgin. The average reservoir pressure potentially impacts the well spacing optimization workflow as well as the designing of an effective well completion job. In this study we compare two scenarios. One scenario considers the depletion history of neighboring well pads and the other one does not. The net present value optimization was done with and without considering the impact of depletion history. This project studies the effects of neighboring well pads on production performance of newly developed pad. Compared to the interaction of parent/child well in a single well pad, multi-pad studies are rare primarily because of the high computational cost associated with a multi-pad numerical simulation analysis.

A drilling team has focused on increasing lateral lengths in the Marcellus Shale over the past couple of years. The team reevaluated prior drilling processes that had been in place for 7,000’ to 9,000’ laterals in order to determine what operational practices would need to be revised in order to drill and case laterals in excess of 18,000’. We focused on rig upgrades, directional tools, drilling fluids, casing floatation and other best practices. We even implemented field trials on various lateral lengths in efforts to evaluate extended lateral practices prior to drilling the first 18,000’ lateral. Over the twelve month period of revised processes and upgrades, we drilled thirty-four horizontal wells each exceeding 12,000’ in lateral length – this included two wells in excess of 17,850’ with one exceeding 18,000', which represented the first drilled Marcellus lateral to exceed that length. This paper covers the details of those processes and upgrades that led to dozens of successful Marcellus horizontal wells with extended lateral lengths.

The modern hydraulic fracturing process in unconventional shales has relied mainly on the use of mechanical isolation techniques (frac plugs) for internal isolation in between multi-cluster perforated frac stages. Significant benefits exist if mechanical frac plugs can be successfully eliminated from well completions. Recent trends of increased lateral lengths and decreased stage spacing are driving up the number of stages per well and the desire to decrease cycle time between completion and production operations, drive the effort for finding an alternative to mechanical plugs. This paper presents two case histories of CNX Resources’ wells that utilized various completion techniques to effectively stimulate the laterals without the use of mechanical frac plugs. These ‘plugless’ completions techniques were originally necessitated due to a problem well with a casing patch where standard plug-and-perf completions methods would have required the use of Mechanical Slim Frac Plugs (MSFP) and an undergauge bit for the drillout operation. These MSFPs are designed to pass through internal diameter restrictions and then set and seal properly inside larger diameters. However, after design evaluation, the use of MSFP for internal isolation was found to have some increased challenges associated with the removal of the plug and increased time spent during drillout operations due to the undergauge bit requirement. Three different plugless completions techniques were selected and then evaluated as a replacement for mechanical frac plugs. Two plugless techniques included the use of a particulate diversion material known as polylactic acid (PLA). The other plugless technique required no particulate diversion material. Proppant tracers and gas tracers were used to evaluate the proppant distribution, cluster efficiency, fracture behavior, and gas returns from each of these techniques. Well productivity was compared to offset wells to quantify the overall success of the plugless completions versus standard plug-and-perf completions. Potential for numerous benefits including reductions in completions costs, operational risks, and cycle times exist with the implementation of plugless completions methods. This case study will lay a framework for operators and service companies to practice and/or evaluate different techniques in completing wells without the use of mechanical frac plugs for internal isolation.

With the increase in average lateral length for horizontal wells comes increased challenges for reaching total depth (TD) with the production casing. Any production interval left un-cased will not contribute to initial or ultimate production or be booked as reserves, which can have a major detrimental impact on the financials of these wells. ALTISS Technologies has designed a patent pending aluminum casing concept to facilitate the installation of long cased laterals, and assist with landing casing at the total depth. Due to its low density and low modulus of elasticity, the aluminum casing is about half the buoyed weight and twice as flexible as comparable steel casing. These physical properties help the aluminum casing lighten the toe of the casing string and navigate through micro doglegs and tortuous wellbores. The aluminum casing was designed with a focus on torque and drag reduction, to be used in limited quantities to maximize the benefits and ensure that casing reaches total depth. Analysis showed that 4,000 pounds of hook load could be added, without casing rotation, with as little as 160 feet of aluminum casing installed, in some cases. To ensure proper threaded connections with the low modulus aluminum, ALTISS designed its own 5 ½" premium threaded connection, which exceeded 56,000 ft.-lbs. yield torque in testing. Multiple aluminum tubular specimens were collapsed in a laboratory setting to validate equations which are not covered by API calculations, nor conventional closed form solutions (e.g. Timoshenko, Tamano). An experimental nano-coating is currently being evaluated that will protect the aluminum from potential forms of corrosion, including galvanic reactions and acid programs. The advantages of installing aluminum casing may allow for eliminating expensive premium threaded connections needed for rotating casing, or alternatives such as floating casing. Ensuring the lateral is 100% cased improves initial production, allowable booked reserves, and ultimate hydrocarbon recovery of the well.

Recent drilling and hydraulic fracturing activities in the Utica-Point Pleasant shale play have recorded total measured depth of over 27,000 feet a record for the longest onshore well in the United States ( Nine Energy Service, 2016 ). Drilling wells at 13,000 feet true vertical depth is a common practice in the Appalachian Basin. Wells at this depth comes very costly and challenging. With the current commodity pricing, drilling in such conditions becomes unaffordable. One immediate solution to the current low energy prices is optimizing well spacing to enhance hydrocarbon recovery and, thus, the commercial feasibility of the project. Horizontal well spacing constitutes a fundamental parameter for the success of a shale-drilling venture. Determining the optimum horizontal well spacing in shale reservoirs represents a challenging task because of the complexity of controlling factors. These factors can be categorized into three groups: geological, engineering, and economic. Geological modeling and reservoir simulation are the standard tools utilized in the industry to integrate these controlling factors. In this study, we employed these tools to perform sensitivity analysis of reservoir characteristics and future production optimization for a deep drilling case study in the Utica-Point Pleasant formations. We sought to find the optimum horizontal well spacing scenario as well as hydraulic fracturing design, in order to attain the highest net present value (NPV) for 50 years of gas production. Our reservoir model represented a portion of Utica-Point Pleasant formations at the depth of 13,000 feet and the dry gas window. A commercial reservoir simulator was coupled with an optimization algorithm to reach the best solution with a minimum simulation cost. In addition, we developed a smart proxy based on artificial neural networks (ANNs) for fast analysis of estimated ultimate recovery (EUR) and NPV. Although the outcome of our study is subjective to the chosen asset, the workflow provides a good example of horizontal well spacing and hydraulic fracturing design optimization as well as a simple and fast technology to predict the critical parameters.