Severe fracturing interference in multi-well pads has been identified in shale gas reservoirs. The gas production of affected multi-fractured horizontal wells (MFHWs) decrease a lot and is hard to restore for most wells even after fracturing fluid flowback. Currently, well interference caused by fracturing operations has become the most important factor affecting the shale gas production. However, the mechanism of fracturing interference and its quantitative impact on gas production in shale gas reservoir are not clear. The aim of this work is to assess the mechanism and dominated factors of fracturing interference of multi-well pads in shale gas reservoirs, and evaluate the impact of interwell fracturing interference on shale gas production. Firstly, field data in WY Basin are applied to calculate the ratio of impacted wells to newly fractured wells and understand the influencing degree and recovering degree of gas production. The main controlling factors of fracturing interference are determined and the interwell fracturing interacting types are presented. Furthermore, the production recovering potential for impacted wells are analyzed. Finally, some suggestions for mitigating fracturing interference are provided. The impact degree and recovering degree of gas production are divided into three categories. The dominated factors of fracturing interference include well spacing, pressure of the affected wells before interference, gas production before interference, and flowback ratio of fracturing fluid. The influencing degree of gas production can be estimated by using the generated equations of impact degree of gas production per well spacing (IDGPs) or impact degree of gas production per flowback ratio (IDGPf) Another novel finding is that 70% of affected parent wells belong to adjacent well pad compared with the newly fractured child well. The interwell fracturing interference is divided into four types, including pressure interference without direct communications between two MFHWs (Type I), fracturing interference through natural fracture/secondary fractures (Type II), fracturing interference through hydraulic fractures (Type III), and direct communication between hydraulic fractures and wellbore of adjacent well (Type IV). Fracturing communication through hydraulic fractures or secondary/natural fractures are more common, and the impact on well safety and production performance increases from Type I to Type IV. Therefore, the fracturing parameters need to be optimized to reduce the fracturing interference. This study can provide reasonable suggestions for infill well optimization, fracturing design, and interwell fracturing interference mitigation to achieve the highest gas recovery of all multi-well pads in shale gas reservoirs.

In response to the borehole instability problems such as wellbore collapse and sand production, which often occur in drilling and completion, a thermosensitive screen technology that can expand spontaneously at a specific temperature has been developed. The radial expansion of the screen allows for annulus filling and borehole strengthening. This paper provides a theoretical evaluation of the comprehensive performance of the thermosensitive screen on wellbore collapse. The results show that the thermosensitive screen barely expands before reaching the conversion temperature, which facilitates the screen's descent into the target depth. After reaching the destination depth, it can be stimulated to expand under the influence of conditions such as formation temperature. The extruding stress after screen expansion contacting the wellbore wall can effectively improve the stress distribution around the near-wellbore and reduce the shear instability caused by the difference between the maximum and minimum principal stress of the formation, while at the completion stage of production, it can effectively improve the flowing downhole pressure, thus increasing the drawdown pressure.

An operator and rig contractor implemented new drilling operation automation (DOA) on two rigs in North Dakota’s Bakken field. A set of DOA projects were selected to promote alignment and deliver valuable tools to improve operational performance based on a collaborative technology agreement to develop innovative DOA process solutions to reduce operational variation. The first sprint of project work focused on delivering a system that automatically carries out recurring drilling activities previously completed manually by a driller interfacing with drilling rig controls. Collaboration between the operator and rig contractor has been vital in developing technical workflows for automation that deliver value to all stakeholders. The operator and rig contractor developed, field tested, and proved the value of the implemented devices and systems. The project development process is described along with the methods used to overcome the challenges encountered during the first project sprint. Developing and deploying repetitive process automation has enabled greater control and driven operational consistency for repetitive drilling practices. The process will be shared to manage, design, and implement automated sequences to the field. The first project sprint delivered a valuable drilling system which executes automated drilling operations. This tool will act as a platform for the next stages of project work to improve management of a drilling automation plan and operations at the rig site. The results described in this paper were outlined as future steps in SPE 195818. The operator and rig contractor overcame some of the traditional cultural and technical barriers to efficiently develop DOA through technology collaboration. The project team used the operators’ standard well delivery processes to deliver a valuable tool to aid the driller’s workflow while standardizing repetitive and recurring steps in drilling operation activities. Engaging and collaborating with field personnel drove improvements to the automated processes and enhanced the value-adding tools to impact operations at a field level.

As major oil and gas companies have been investing in greener energy resources, even though has been part of the oil and gas industry for long time, it has gained its popularity back. Oil and gas industry has adapted to the wind of change and has started investing in and utilizing the technologies significantly. In this perspective, this study investigates and outlines the latest advances, technologies in artificial lift methods as it is applied to unconventionals in a comprehensive manner to serve as an industry-reference for petroleum industry. In order to optimize production of oil and gas from unconventional wells, artificial lift (AL) is found to be the most effective method of production. However, as the well passes through its production lifespan, the reservoir pressure declines and artificial lifting of hydrocarbon fluids remains a serious problem. Identifying the best approach, the kind of AL, ideal time and settings to mount the AL as the well passes through its production lifespan is a major challenge. Several investigations have been carried out in the past to identify and establish ground-breaking techniques to improve the application of AL in tight reservoirs. The aim of this study is to conduct a comprehensive review of recent developments in the field of AL and its applications. A review of the application of machine learning (ML) is also presented in this study. A comprehensive literature review focusing on the recent developments and findings in artificial lift along with the availability and locations are outlined and discussed under the current dynamics of the oil and gas developments. Literature review includes a broad spectrum that spans from technical petroleum literature with very comprehensive research using onepetro and other databases to other renowned resources including journals and other publications. The information and data are summarized and outlined. This study also provides the techniques on optimziation of artificial lift methods in addition to their comprehensive details with a comparative approach. Aritifical lift is a critical component of any oil and gas well especially in unconventionals. The key artificial lift selection and optimziation is through a robust design and established reservoir and well management practices and reflecting the production physics and well dynamics in all aspects. This study outlines the key criteria in the success of aritifical lift applications in individual examples using different methods that will serve for the future decisions as a comprehensive and collective review of all the aspects of the employed techniques and their usability in specific cases. Among the few existing studies that explain the methods of aritficial lift are up-to-date and the existing studies within SPE domain focus on certain methods. This study closes the gap and aims to serve as a comprehensive single-source reference for artificial lift and its optimization in unconventionals including all traditional and relatively-new methods.

The pressure decline data after the end of a hydraulic fracture stage is sometimes monitored for an extended period of time (30 minutes to hours). However, this data is not analyzed and often ignored or underappreciated due to a lack of suitable models for closure of propped fractures. In this study, we present a new approach to model and analyze pressure decline data that is available at the end of each plug and perf stage in horizontal wells. The new model, interpretation method and specialized plots presented in this study allow us to quantify closure stress, average pore pressure inside the stimulated reservoir volume (SRV) and normalized fracture stiffness/compliance evolution along the entire horizontal wellbore without additional data acquisition costs. Analysis of field stage-by-stage pressure decline data shows that the interpreted results are consistent with the analysis of DFIT data from an offset well for the same formation. We found that the early-time stage-by-stage pressure decline trend is controlled by progressive hydraulic fracture closure on the proppant pack, while late-time pressure decline reflects linear flow. Thus, the pressure decline rate alone is not a reliable indicator of the productivity or stimulation efficiency of a certain stage. When DFIT data is not available, pressure decline analysis of a main hydraulic fracturing stage can be used even if it can be monitored for a relatively short period of time (1 hour). Most important of all, we show that the slope of pressure derivative on a log-log plot and the normalized fracture stiffness plot can be used to infer the uniformity of proppant distribution.

Unexpected problems during completion create costs that can cause a well to be outside its planned AFE and even uneconomic. These problems range from merely experiencing abnormally high pressures during treatment to casing failures. The authors of this paper use machine learning methods combined with geomechanical, wellbore trajectory, and completion datasets to develop models that predict which stages will experience difficulties during completion. The operator collected geomechanical data for 26 lateral wells. Several of these wells experienced significant difficulties during completion, including casing failures. By examining the completion data for the study wells, engineers developed two objective proxies for trouble stages: a high fracture gradient cut-off and a sand-to-water ratio cut off. The geomechanical data were combined with wellbore trajectory and stage-level completion data. Machine learning techniques were then used to predict the fracture gradient at the end of treatment and the sand-to-water ratio of a stage. The data were subdivided by target horizon to ensure the model results were not skewed towards a specific horizon. The models were cross validated, hyper-parameter tuned, and then tested against a subset of the data withheld from the training algorithm (the test data subset). Multiple metrics were applied to measure the effectiveness of the models. For the fracture gradient regression, the model that minimized the root mean squared error (RMSE) was chosen. This model was compared to a prediction that each stage would have a fracture gradient equal to the average fracture gradient. The correlation between predicted and measured frac gradients was also calculated. These metrics were analyzed for both the entire data set and the test data subset. By all these measures the model performs significantly better than the control prediction. For the sand-to-water ratio metric, the model that maximized the receiver operating characteristic area under the curve (ROC-AUC or AUC) score was chosen. We chose to measure the success of the model with the precision of its prediction of outlier (trouble) stages on the test data subset. The model performs with a precision of at least 73%. Both models identify stages where casing failures occurred as trouble stages. With these initial results, the authors are confident they can predict the probability of any stage causing a significant operational disruption in these horizons. By predicting the probability of a trouble stage, mitigation plans can be implemented to reduce costs ahead of time. By further analyzing the models, engineers can identify the major drivers for the trouble stages and work to reduce them as early as the well planning stage.

Frac plugs remain the most common zonal isolation tool in multistage stimulation. However, while manufacturers in recent past have focused on improving frac plug drillability and dissolvability, the industry critically overlooked significant plug design flaws. Among these flaws is mechanical damage to horizontal well casing caused by inadequate plug construction, poor isolation integrity, and cycled pressure stress on the pipe throughout the entire fracture treatment. Until recently, casing integrity issues had never even been associated with frac plugs. Today, significant improvements in ultrasonic wellbore diagnostics, downhole cameras, and fiber optic well monitoring visualizing post-frac casing integrity have revealed widespread casing breaches at plug setting depths. These recently discovered flaws called for a frac plug with non-damaging slips and optimized packing element systems for improved zonal isolation. Three-dimensional finite element analysis was performed to understand casing damage caused by various slip designs currently being utilized in the market. Extensive laboratory tests were conducted on slip and packing element designs to further support and validate the numerical study. Finally, fiber-optic diagnostic data was used to confirm interstage isolation efficiency by a non-damaging frac plug. This paper will review findings that some slips, under certain scenarios, cause severe casing wall damage. It will also review findings that some packing element designs provide inadequate isolation during the fracture–posing considerable challenges to casing integrity. Based on extensive numerical analyses, laboratory tests, and field trials, a frac plug with non-damaging slips, as well as anti-extrusion packing element systems, limit the frac plug's impact on the casing during high fracture pressure treatments.

Longer lateral length in unconventional wells has proven to increase hydrocarbon recovery and lower overall development costs for oil and gas operators in North America. The application of rotary steerable system (RSS) technology aids this effort by improving and sustaining penetration rates to reduce well time and maximize reservoir drainage. A new "intelligent" RSS has been deployed to enhance drilling efficiency with industry-leading operating limits, automated steering controls, and a global lifecycle maintenance system to drive reliability. The new RSS bottomhole assembly (BHA) consists of an advanced downhole motor, a matched bit design, and high-speed geosteering control. An automation process helps operators meet the challenges of drilling time and wellbore placement in long laterals. High rate of penetration (ROP), rotation per minute (RPM) and weight on bit (WOB) limits are controlled by sophisticated sensor technology that enables precise steerability. The RSS platform includes multiple directional sensors and real-time processors capable of reducing hole tortuosity and optimizing reservoir exposure while drilling. It also includes automated inclination and azimuth control features. Furthermore, a structured, pre-job design process evaluates critical engineering risks and mitigates those risks using a systematic methodology. The initial testing of the new RSS on a test beam qualified its ability to operate at high speeds and high loads. Multiple holes were drilled in cement blocks to benchmark performance. Beam testing was followed by full-scale testing at a dedicated drilling rig, where over 40,000 ft was drilled in a variety of configurations, including vertical, curve, and lateral trajectories. After the extensive field testing program, the intelligent RSS was utilized to drill multiple ~14,000-ft, 8.5-in. lateral hole sections in the Utica Shale. A significant reduction of drilling time was achieved in these long laterals, with an average ROP of 245 ft/hr. A record 5,300 ft were drilled in 24 hours, beating previous wells by 600 ft. The activation of inclination and azimuth control delivered a smooth, high-quality wellbore with minimal tortuosity. Inclination was maintained within +/− 0.5° and azimuth +/− 1°. The outstanding performance of the innovative BHA enabled the longest one-run lateral to be drilled with an RSS. The new, intelligent RSS has successfully demonstrated it can decrease well time and drilling costs, while increasing wellbore placement accuracy. The improvement in drilling efficiency and lateral length capability will enhance unconventional asset value across North America, and elsewhere around the world.

Stage length and perforation cluster spacing are important design parameters for multi-stage hydraulic fracturing. This study aims to demonstrate that the interplay between subtle variations of the least principal stress (S hmin ) with depth and the stress shadows induced by simultaneously propagating hydraulic fractures from multiple perforation clusters, primarily determines the propped and fractured area in the target formations. This principle is illustrated with the help of a case study in a prolific unconventional formation in the north eastern US, where the vertical stress variations are well characterized through discrete multi-depth stress measurements and actual stage design parameters used by the operator are known. At first, we show how the hydraulic fracture footprint and proppant distribution varies with a change in the vertical stress profile. The stress profile is shown to be a very important in determining the optimal vertical and lateral well spacing. The evolution of the stress shadow in the different layers is shown during the pumping as the fracture propagates across multiple layer boundaries. Subsequently, we demonstrate that by changing the magnitude of stress perturbations caused by the stress shadow effect, the distribution of propped area can be altered significantly. We use this method to determine the optimal cluster spacing keeping other design parameters constant such as flow rate, perforation diameter, etc. Simulations from selected cluster spacing realizations are run with high and low permeability scenarios to show the importance of correct matrix permeability inputs in determining the three-dimensional depletion profile and ultimate production. By varying the cluster spacing we show the hydraulic fracture propagation change from being solely stress layering driven to stress shadow influenced. The effect of stress shadow on the final fracture footprint is highly specific depending on the given stress layering and is thus case-dependent. This study demonstrates that knowledge of stress variations with depth and modeling are critical for optimizing stimulation efficiency.

Hole cleaning is a concern in directional or horizontal well drilling operation where drill cuttings tend to settle in the lower annulus section. A lab-scale experiments were performed with different non-Newtonian fluids in a 6.16-meter-long, 4.5-inch × 2.5-inch transparent annulus test section to investigate cuttings transport behaviour. This experimental study focused on understanding the cuttings transport mechanism in the annulus section with high-speed imaging technology. The movement of cuttings in the inclined annular section was captured with a high-speed camera at 2000 frames per second. Also, cuttings bed movement patterns at different fluid velocity and inner pipe rotation were captured with a DSLR video camera. The electrical resistance tomography (ERT) system was used to quantify the cuttings volume fraction in the annulus. Different solid bed height and cuttings movement were observed based on fluid rheology, fluid velocity and inner pipe rotation. The mechanistic three layers cuttings transport model was visualized with the experimental procedure. This study showed that solid bed height is significantly reduced with an increase in the inner pipe rotation. This study also identified that cutting bed thickness largely depends on fluid rheology and wellbore inclination. The image from the high-speed camera identified a downward trend of some rolling particles in the annulus due to gravitational force at a low mud velocity. Visual observation from high-speed camera identified a helical motion of solid particles when drill pipe is in contact with solid particles and rotating at higher RPM. Different cuttings movement patterns such as: rolling, sliding, suspension, helical movement, downward movement were identified from the visualization of a high-speed camera.

Completion designs in horizontal, multi-stage wellbores is a complex problem and has many potential scenarios depending on the desired well performance. Up until recently the industry has been focused on improving early-time productivity; 90-day cumulative production, 24-hour initial potential (IP) or achieving a target daily rate. Many operators are now refocusing on a desired economic outcome; achieving free cash flow, improving return on investment and increased net present value. Our paper will discuss the effects that different completion design changes have on these desired results and present examples of past well performance and new well performance utilizing these changes. Our methodology will include the analysis of producing well histories to determine average reservoir permeability and completion effectiveness as described by the number of created, producing transverse fractures and the average effective length of those fractures. From this characterization of the reservoir and past completions we will forward model completion design scenarios to determine the effect changes in design have on the performance parameters we wish to achieve. The process used includes hundreds of completion design scenarios which are compared to each other to find the design which maximizes the desired economic result. Multiple examples of this will be presented. Increasing early-time production performance has resulted in increasing capital expenditure. Several completion design parameters lead to increases in this performance parameter (IP); increasing lateral length, increasing stage volume and decreasing stage spacing. However, all of these changes increase the capital spent on the completion. To achieve improved economic performance parameters, balancing the total capital expenditure against the revenue generated becomes the primary focus. What may have worked in the past to meet past goals does not work to meet new, economic focused goals. The most important parameter we must know when designing the completion is the reservoir permeability. This value determines the reservoirs ability to deliver hydrocarbons to the well and how effective the reservoir can be to creating the revenue necessary to pay for the capital spent. Identifying the balance between capital spent and revenue generated leads to completion designs that reduce well cost while maximizing economic parameters versus maximizing early-time production alone. The results and conclusions from this paper will run contrary to the industry's past trends in completion design. However, the focus on economic improvement can be a pathway to our industry to achieve better economic results. Our industry has provided increased energy independence for our nation, but far too many companies are suffering financially while doing so. Billions of barrels of oil have been produced, yet many are going broke.

After a blowout incident, the wellhead conditions (hydrocarbon flow rate and pressure) are difficult to predict. The worst-case discharge during an offshore blowout has always been a concern for the oil and gas industry. When a blowout occurs, the two-phase flow establishes various flow patterns along the wellbore depending on several factors such as wellbore and reservoir conditions as well as flowing fluid properties. The multiphase (gas-liquid) fluid flows upward through the wellbore at an extremely high velocity that may reach a sonic condition at the wellhead. One of the challenges for the worst-case discharge rate calculation is predicting the pressure drop and velocity of the influx in subsonic and sonic conditions. This paper presents a novel computational tool which is developed to characterize the well control events by simulating the possible worst-case discharge (WCD) scenarios under field conditions. The exactness of a WCD prediction tool is strongly related to the accuracy of models used to analyze the two-phase flow and the formation of sonic flow condition. The WCD tool developed in this study utilizes the nodal analysis technique to precisely predict the wellhead conditions post blowout incident. The tool has two main parts: i) reservoir portion, and ii) wellbore portion. The tool integrates various reservoir, PVT and production models to estimate the deliverability of a reservoir. Different forms of hydrocarbon production (oil, dry gas, and condensate) from multiple reservoir layers are considered in tool development. To forecast pressure loss along the wellbore, well-established models have been selected to make predictions for different flow patterns (bubble, low-velocity slug, high-velocity slug, and annular flows). In addition, various two-phase flow models have been modified and adapted to suit the Worst-Case Discharge (WCD) predictions. Furthermore, based on experimental observations, a new flow pattern map has been established and implemented in the model. One of the findings of this study is that the WCD rate is not only dependent on conditions of the wellbore section but it is also influenced by the fluid properties and reservoir characteristics. Therefore, the tool accounts for reservoir type, the number of producing layers, formation type (consolidated and unconsolidated), fluid types (oil, gas water, and gas condensate), and the pay zone thickness. In addition, the tool allows the user to specify fluid and reservoir properties for each layer including permeability, water, oil and gas saturation, API gravity of oil, salt concentration, bubble point and reservoir pressure, irreducible water saturation, critical oil and gas saturation, and gas specific gravity. With respect to the wellbore section, the tool provides flexible options for the user to design the desired wellbore configuration. These options comprise of the depths of cased and open-hole sections, casing and hole diameter, the roughness of casing and open-hole section and the inclination angle of the wellbore. The tool provides good WCD rate predictions for wells with an inclination up to 45° from the vertical. This article presents a novel WCD tool developed based on modified mechanistic two-phase flow models, which are validated for wide ranges of gas and liquid superficial velocities. As outputs, the tool predicts the wellhead parameters post blowout incident such as WCD rate, gas and water rates, the occurrence of the sonic condition and surface pressure. In addition, it provides an inflow performance relationship (IPR curves) for each reservoir layer. Predicting the wellhead pressure at the moment of the blowout helps to control the well by determining the density of the killing fluid.

Well completion selection and design involve the selection of optimum well completion architecture and associated downhole equipment to deliver hydrocarbon to surface in a safe and efficient manner. A number of well architectures can be conceived for a given application, and a plethora of equipment is available across the industry, with hardware to meet a wide range of operating conditions including hole size, pressure, temperature, flow rate and fluid type. This wealth of choice results in a highly complex and challenging selection process that today is done manually, relying on subject matter experts and local best practices through trial and error approach. As a result, the process can be quite inefficient, designs can be suboptimal and fail to consider unique reservoir and well conditions leading to premature equipment failure causing loss of production and well integrity. These failures can have impact ranging from unplanned well intervention, equipment pull outs, fishing operations, extended rig time, workovers, or even complete well loss—costing the oil and gas industry billions of dollars. The shortcomings in design are therefore ripe for innovative digital solutions. This paper describes how manual completion selection process can be seamlessly transformed into an intuitive digital solution providing insights for the well completion selection process. The proposed digital solution describes software tools and architecture used to consolidate thousands of historic, unstructured, completion schematic data into a structured database. It automatically maps the completion architecture and equipment details to relevant operating environments, captures nonproductive time and highlights installation challenges. The solution also identifies correlations and data trends across various types of well designs and equipment categories, using advanced artificial intelligence and machine learning algorithms to provide insights into equipment reliability, operational efficiency, total cost of ownership and production performance. A minimum viable product consisting of 24,000 wells from across the world has been successfully developed to demonstrate key value propositions. New data coming in from recently completed wells can be seamlessly integrated with the existing data bases and the algorithms constantly improvise its learning process to provide better accuracy. The digital solution proposed for well completion selection and design process ultimately enables oil and gas companies to optimize well completion configurations and equipment that can deliver maximum value. It allows them to identify offset well issues, derisk operational concerns, check compatibility of equipment with respect to dimensional constraints, pressure and load rating requirements, thread configurations, metallurgy constraints, seal elements, complete well on digital file with tracing and accountability.

For offshore wells requiring sand control, the trend in the industry has been to gravel pack longer and longer wells to access more reserves with reduced well count. In challenging environments (e.g., low frac pressure), gravel packing with shunt tube technique is the preferred option. This paper discusses development and qualification of an enhanced shunted alternate path technology (ESAPT) screen that will extend openhole gravel packing lengths to more than 7,000 ft with zonal isolation. Extending openhole gravel pack lengths with shunt tubes required several issues to be addressed. First, if static shunting (bypassing an annular blockage through shunts and packing in a toe-to-heel fashion downstream of the blockage) occurs intentionally or unintentionally, large volumes of slurry will exit through a limited number of shunt tubes manifolds before complete packing, raising erosion concerns which were addressed through: 1) computational fluid dynamics simulations to identify the location of maximum erosion and to redesign the shunts geometry and metallurgy accordingly; 2) yard tests with slurries passing through the manifold at rates representative of field applications. Second, if continuous shunting (bypassing an annular blockage through shunts and packing in a heel-to-toe fashion downstream of the blockage) occurs, the pressure inside the shunt tubes can: 1) exceed the burst pressure limit of conventional shunted alternate path technology (CSAPT) screens, which was addressed through modification of the weak links in the CSAPT and then tested to the required burst limit; 2) cause higher fluid leak-off through the packed interval, resulting in increased gravel concentration, increased friction and potential bridging inside the shunt tubes, which was addressed through a) leak-off behavior characterization of carrier fluids in shunt tubes of packed interval; b) friction pressure measurements with various gravel concentrations and rates inside shunt; c) modification of nozzle distance based on results from (a) and (b), and d) verification of the modified design through gravel pack yard testing. Recent testing demonstrated that under static shunting conditions, CSAPT shunt system can have substantial erosion in long interval gravel packing. ESAPT shunt system showed significantly improved erosion resistance for slurry flow in yard tests. It was demonstrated that ESAPT shunt system could withstand 10,000 psi burst pressure after flowing 450 klbs of proppant at 5 bpm slurry rate. It was also successfully tested for 10,000 psi burst pressure at elevated downhole temperature of 300F. The data from leak-off tests of viscous fluids through packed interval shunt tubes at high differential pressures combined with friction pressure measurements with various gravel concentrations and rates (gravel concentrations as high as 20 ppa and rates as low as 0.25 bpm) led to the conclusion that the distance from the shunt manifold to the first nozzle needed to be increased for longer wells to be gravel packed. In a yard test using a full-scale model of the new design with the increased nozzle distance, and including the blank handling sections, a complete pack was achieved with proppant. An ESAPT screen that will push the openhole gravel pack lengths to more than 7,000 ft with zonal isolation is presented herein. The system has a more erosion-resistant, high burst pressure shunt system and allows quicker make-up of screen joints on the rig floor.

The STACK (Sooner Trend Anadarko Canadian and Kingfisher counties) is a prolific multi-target stacked play in Oklahoma. Development challenges in the STACK are underpinned by fieldwide geological heterogeneities, including variable reservoir quality throughout the Sycamore-Meramec and Woodford formations and the presence of natural fractures and dense laminations. This case study examines the operator's first fully co-developed section in Canadian County, which comprised of 11 wells across 4 targets. This project was undertaken after de-risking much of the geological uncertainty in several offset pads. The data acquisition program was designed to assess the impact of total completion design including: interwell spacing, targeting, and wine-rack configuration on well-to-well connectivity and well performance in full section development. Within the section, half of the wells were drilled with the same spacing as offset pads and the other half were downspaced. On both sides of the section, similar targets received the same hydraulic fracturing design. Given it was the operator's first full section development in the county, the operator utilized an advanced data acquisition program that included downhole pressure gauges, chemical tracers, and DNA based diagnostics. DNA diagnostics proved especially useful in measuring the relative contribution from the multiple strata between landing zones, which would not have otherwise been possible. Although the previous offset pilot pads were developed with similar spacing and completion parameters, there were significant differences between average production profiles, with higher initial production (IP-180) observed in the full section. This paper evaluates these production differences by examining the impact of well spacing/targeting, completion design, and interwell communication on well performance in full section development. Well performance was assessed by integrating production, pressure, and tracer data, along with DNA based diagnostics. DNA diagnostics played a key role in assessing and monitoring the duration of interwell communication between offset wells across the section. Results from this integrated approach demonstrated that full section well performance was impacted by completion design and interwell communication in three notable ways: 1) interbench co-development significantly increased communication across perceived deterrents to fracture growth, 2) well-to-well communication was influenced by completion order, and 3) aggregate interwell communication was higher in full section development than in pilot pads, which may have contributed to the full section initially outperforming pre-drill expectations. The differences in well performance and well-to-well connectivity carry important implications for operators who plan to use partial spacing tests to develop multi-target full sections. Specifically, these observations underscore the potential for similar completion designs to yield materially different well performances between full section and 1 to 3 well pad development. These results also demonstrate the ability of DNA based diagnostics to accelerate learnings in full section development, which may have otherwise required additional CAPEX to test via heuristic techniques.

Lateral spacing in unconventional plays can have a significant impact in the economics of field development ( Bharali et al., 2014 ; Lalehrokh & Bouma, 2014 ). This spacing is most often verified using magnetic measurement while drilling (MWD) instruments. In well spacing studies, the distance between two laterals is typically assumed to be precise, however, MWD may have large uncertainties associated with their bottom hole locations (Williamson, 2000; Grindrod et al., 2016 ). Standard error models were built primarily using data from major service providers' offshore operations and assume a level of accuracy that may not reflect current practices for onshore drilling in North America ( Love, 2019 ). This study better quantifies the positional uncertainties of MWD surveys in long laterals and uses those uncertainties to estimate well spacing uncertainty. More than 35,000 MWD bit runs across more than 9,000 laterals wellbores in major basins across North America have been analyzed for survey errors. The observed errors are then tested in magnitude and distribution against assumptions of industry standard models. An empirical MWD error model for North America is generated, and additional area-specific analysis is performed for the Bakken, Denver-Julesburg, Eagle Ford, Marcellus/Utica, Permian/Delaware and Western Canada. The wellbore trajectories were analyzed to produce a prototypical wellplan for each basin studied, as well as an overall "North America" wellplan. Positional uncertainty calculations were performed for each wellplan using several industry standard positional uncertainty models as well as the empirical models based on real MWD data. Using the combined covariance method of wellbore separation, the uncertainty in lateral spacing is estimated for each wellplan at landing point, mid-lateral, and the toe. A pair of typical North America long laterals (10,000ft step out, drilled parallel) were modeled using the empirically derived MWD error model. After accounting for geomagnetic correlations, there remained an estimate 350 ft of uncertainty in the separations (at 2-sigma) between the wellbores are the toe. This is significantly larger than the 160ft of spacing uncertainty that would be predicted using an industry standard MWD model or the 100ft theoretically achievable with standard survey management practices. A similar analysis was performed at a basin level, and in all cases the modeled uncertainty from common practice was larger than predicted by industry standards. The dominant error source that is impacting lateral spacing is magnetic drillstring interference (DSI). The 68th, 95th, and 99.7th percentiles for observed DSI magnitudes were 520, 1400 and 4200 nanotesla respectively. Creating a 95% confidence equivalent error model (2-sigma) requires and error magnitude more than 3 times greater than the industry standard. For companies that use greater than a 2-sigma limit when well planning, deviations even more extreme should be expected. Further discussion of the probability distribution and its impact on lateral spacing is included. Additional analysis compares how these uncertainties change for parallel wells drilled in opposite directions (anti-parallel) as opposed to drilled in the same direction. MWD error models are routinely used as the basis for both safety critical and economically significant workflows in onshore North America operations, to date, there has been a lack of data collected regarding their suitability for this purpose. For drilling programs where lateral spacing will have an impact on economic performance, proper estimation of the spacing uncertainty will lead to better asset modeling. Further, it will enable better estimation for the marginal value provided by improvements in survey accuracy.

This work describes the use of integrated production modeling (IPM), along with digital platforms, as reliable tools to increase liquid yield, reduce operational expenditures ($/BOE) and maximize the project's net present value (NPV) in the Appalachian Basin. The results of the work, as applied to a real field show that the liquid yield for the gas condensate produced fluids can be increased by 3-5%; compression energy and process heating requirements can be reduced significantly. The condensate to gas ratio (CGR) in Marshall County, West Virginia (WV) changes rapidly from southeast to northwest. For example, on a single pad (8-10 wells) the CGR of the northwestern wells is ~40% higher than the CGR of southeastern wells. Moreover, the CGR decreases with production time. A fixed-pressure, two-stage separation process is suboptimal for this area. Calibrated physics-based models leveraged to an integration platform can significantly improve the facilities performance. The facilities set up is as follows: the gas produced from a well is fed to a line heater followed by a surface choke. The fluid then enters a gas processing unit (GPU) separator. The separated fluids from each well's GPU in the well pad are processed at common facilities consisting of separation and compression. The processed gas is exported to a sales gas line and the liquids are transported separately. A fully integrated model has been built for eight wells on a pad. The reservoir and well models were history matched and then integrated with the surface network and facilities (compressor, heater) using network modeling and integration platforms. Various scenarios were run to identify the optimal pressure setting for a given month. The optimization exercise yielded 5-10% additional natural gas Liquids (NGLs) on a pad by increasing the GPU pressures by 100-200 psi. The higher GPU pressures reduced the well choke pressure drop, thereby reducing the heating requirements by 50% as the Joule-Thomson cooling across the choke was minimized. The reduced cooling also minimized flow assurance risks due to hydrate formation and reduced inhibitor injection costs. Finally, the compression energy requirement was reduced via better management of the pressure staging. The developed integrated models, combined with digital platforms, offer novel and versatile capabilities for efficiently operating an asset to maximize liquids and reduce operational expenditure (OPEX). The deployment of a physical model-based digital oil field will facilitate the validation of these models on a continuous basis. This in turn will allow changes to be made in the field to keep the system optimized as the characteristics of the producing fluids change with time.

Recovery efficiency (RE) is a poorly constrained parameter with respect to unconventional resource development. However, the increasing volume and quality of data related to Marcellus development in West Virginia provide an opportunity to assess this parameter. In this report, we develop a map of estimated ultimate recovery (EUR) per square mile (mi 2 ) for the Marcellus Play in West Virginia and compare that map to published estimates of both technically recoverable resources (TRR) and original gas-in-place resources (GIP). These comparisons reveal that Marcellus wells appear capable of producing significantly more gas than previously estimated and, throughout large areas of the State, more gas than has been assessed to be in place. While explanations for this observation likely include both potential overestimation of EUR and underestimation of GIP, our review indicates that a primary source of the discrepancy is overly-conservative GIP calculations. New GIP calculations have been conducted for a range of wells that appear to account for the bulk of the "excess gas" by including GIP volumes from bounding formations determined likely to be part of the larger Marcellus Reservoir Unit (MRU). In northeastern West Virginia, the MRU includes both the Marcellus Formation and the lower 300 ft of the Mahantango Formation. In northwestern West Virginia, units up to the Cashaqua Shale Member of the Sonyea Formation are included in the MRU. These new GIP/mi 2 values, when compared with our estimates of TRR/mi 2 , indicate that ultimate RE for ongoing development generally ranges between 20 to 60%. Our approach to estimate TRR/mi 2 is based on identification of 166 Marcellus "development sites" in northern West Virginia. Each development site was selected to consist of multiple horizontal wells that were drilled as a coordinated activity at a common spacing over a short period of time by a single operator. Sites and wells also were selected to maximize both the relevance (post 2012 vintage wells where possible) and reliability (more than 18 months production history) of the EUR forecasts. Site area was determined as the product of cumulative lateral length and well spacing. The cumulative EURs for all wells in each site were estimated (using two independent sources for EUR estimation) and those sums were divided by the area to obtain a single point estimate of TRR/mi 2 . Our review indicates that Marcellus Play resource assessments tend to be overly conservative. This analysis shows the value of focusing on the most relevant production data and using those data as a ground truth check on resource assessments.

The model of "learn at school" and "do at work" is outdated and must keep up with the changing environment of the Industrial Revolution 4.0 (IR 4.0). The petroleum engineering curricula, therefore, must also change accordingly and this change is needed at a time the new generation of students entering the workforce is different from the generation leaving the workforce. It is time to examine the core curricula being taught at petroleum schools so that long-term sustainability can be established. The petroleum education has been modified very little in the past 30 years and needs to change in the post-Google era to cater to the tech-savvy minds of the modern student. Although developments in technology have positively responded to the needs of the industry in the past, its future advancement will include areas such as telemetry, sensors and data handling, and analytics. Thus, a new approach to engineering education, involving the fundamentals of engineering sciences that culminates in the development of experiential learning on cyber-physical systems, is important. The paper presents and lays out the urgent need for a new type of curriculum for petroleum engineering education that encompasses engineering, science, and technology.

The drive for cost efficient solutions in drilling has become stronger the last few years, and one of the approaches to this end is to increase the level of automation. Automation is multi-disciplinary task, and to really succeed, there is a need for collaboration between the different parties in the drilling industry. In this paper we discuss which underlaying technologies within instrumentation, control systems and communication technology that should be in place for a typical model-based automation and well protection software to work optimal. We elaborate on what is needed to take out the full potential of performance-enhancing functionalities in automated drilling control software. We highlight the gaps present today and how this affects the automation efforts as a whole. The discussion shows that there are some low-hanging fruits that can give significant cost reduction and improvements in automation and safety, while there are also some technology gaps that will take some time to fill and that require coordinated efforts between the vendors.