Multi-well Pads Research Articles

Optimal planning and modular infrastructure dynamic allocation for shale gas production

Compared with the conventional method utilizing permanent processing facilities, modular infrastructure has shown greater potential to hedge against the uncertainty due to the rapidly declining characteristic of shale gas production. However, there is still a lack of a comprehensive approach that integrates the production planning and the dynamic allocation of the modular infrastructure based on the production curve of shale gas wells. Therefore, a systematic optimization framework is developed to simultaneously optimize the production planning and modular infrastructure allocation over a given time horizon, maximizing the net present value (NPV) of the system, considering the production curve and gas well status, the processing capacity as well as the scheduling of modular infrastructure. The proposed mixed-integer linear programming model combines the decisions relevant to shale gas production, transportation, and processing together with the decisions regarding modular infrastructure, including allocation, capacity selection, installment planning, moving scheduling, and salvage operation. A case study deciding a development strategy for 24 multi-well pads over a period of 15 years is implemented to illustrate the applicability of the proposed model. The results show that the dynamic allocation of the modular infrastructure can adapt to productivity fluctuations. The use of the modular approach increases the NPV by 9.12% and has a high utilization efficiency of processing devices compared to the conventional method. This work reveals that the synergistic interaction of the production planning and modular infrastructure dynamic allocation can increase efficiencies in the uses of energy, resources, and human capital to promote cleaner production practices.

Flowing Shale Wells Sooner Would Add Billions to Sector Cash Flow

Trimming the time that exists from the day drilling begins to the delivery of first oil represents a largely overlooked opportunity for US shale producers to improve free cash flow. In the Delaware Basin alone, accelerating this cycle time would save the shale sector more than a billion dollars. This is according to a recently published study from Westwood Global Energy Group and the Project Production Institute (PPI), a San Francisco-based non-profit that promotes a method called “operations science” for major capital planning and management projects. Their findings offer a new quantitative look at the hidden costs of the shale sector’s nonproducing asset base. The biggest issues boil down to two periods in the life of a shale well: when it is a drilled-but-uncompleted (DUC) well, and after it is completed but still waiting to be attached to a sales line. Holding too large an inventory of these dormant properties means locking up large sums of capital indefinitely. On the other hand, a lower balance of DUCs coupled with achieving initial production on a quicker basis frees more of that sunk capital to generate revenue. DUCs and completed wells awaiting hookup are categorized in the study as a single measurable called “work in process.” This metric includes drilling and completions, but it is the nonoperational days where producers have the most room to improve. Excessive work in process also includes drilling permits sitting idle, pads that are built but not yet drilled upon, well design lead times, and other delays. Amanda Goller, who leads research for PPI, acknowledges that while overall cycle times have remained relatively constant in spite of larger well pads and longer laterals, nonoperational time on multiwell pads is steadily creeping higher. This is attributed to the fact that, generally, the shale sector has not considered work in process an effective way to benchmark capital management•performance. “Most oil companies have scheduling software to track what their work in process is—but that won’t tell them what it should be,” she explained, adding that, as a result, “The industry does not control its work-in-process inventory.” Goller is both the director of analysts communications at PPI and the director of analytics with Strategic Project Solution, which develops operations science software. She said this class of software deviates from traditional planning programs because it “uses mathematical formulas to tell you pretty much in real time, where everything should be every day.” The PPI website offers this definition: “Operations science focuses on the interaction between demand and production and the variability associated with either or both.” As evidence that operational practices are a difference maker, Goller points to the wide disparity of cycle times among the 15 largest unconventional operators in the Delaware Basin. The study found that mean cycle times across the basin are 154 days, with the poorest performers averaging 233 days from spud to initial production. The top percentile sees first oil in 88 days.

Community Noise and Air Pollution Exposure During the Development of a Multi-Well Oil and Gas Pad.

Unconventional oil and gas development (UOGD) in the United States is increasingly being conducted on multiwell pads (MWPs) and in residential areas. We measured air pollution, noise, and truck traffic during four distinct phases of UOGD: drilling, hydraulic fracturing, flowback, and production. We monitored particulate matter (PM2.5), black carbon (BC), A-weighted (dBA), and C-weighted (dBC) noise using real-time instruments on 1 and 5 min time scales, and truck traffic for 4-7 days per phase at a large 22-well pad sited in a residential area of Weld County, Colorado. Hydraulic fracturing, which requires frequent truck trips to move supplies and diesel engines to power the process, had the highest median air pollution levels of PM2.5 and BC and experienced the greatest number of heavy trucks per hour compared to other phases. Median air pollution was lowest during drilling at this MWP, possibly because an electric drill rig was used. The equivalent continuous noise level ( Leq) exceeded guidelines of 50 dBA and 65 dBC for A-weighted and C-weighted noise, respectively, during all development phases. Our data show that these multiple stressors are present around the clock at these sites, and this work provides baseline measurements on likely human exposure levels near similarly sized MWPs.

Development of a fully implicit 3-D geomechanical fracture simulator

Hydraulic fracturing modelling is a multi-physics problem which must be solved in the reservoir domain, fracture domain, and wellbore domain. The physical phenomena that need to be quantitatively modelled include solid deformation and fluid flow in the poroelastic reservoir, fluid flow in the fractures, and fluid and proppant transport in the wellbore. These problems which are tightly coupled with each other in a highly non-linear manner are solved together implicitly for the first time. This fully implicit, parallelized 3D hydraulic fracturing simulator is capable of simulating simultaneous propagation of multiple fractures in multi-well pads. In this new simulator, four sets of governing equations are coupled implicitly and solved simultaneously. The solid deformation equations and reservoir pressure equations are discretized using the finite volume method while the fracture pressure equation is discretized using the finite area method. Fluid flow in the wellbore is modelled considering wellbore compressibility, perforation pressure drop, and wellbore friction pressure drop. A Barton-Bandis contact model is applied to model fracture closure due to stress shadow effects as well as production. The simulator is parallelized using the distributed memory approach with domain decomposition to improve the computation efficiency. We first validated our simulator with two well-known model problems and the numerical results show good agreement with the existing analytical solutions. We compare the performance of the new simulator with the past explicit methods and show that the new simulator offers significant improvement in numerical stability and computation speed. Finally, the simulator is applied to simulate and analyze one stage of a fracturing treatment with five fractures propagating simultaneously to show the unique capabilities of our simulator.

Oil and gas development footprint in the Piceance Basin, western Colorado

Understanding long-term implications of energy development on ecosystem function requires establishing regional datasets to quantify past development and determine relationships to predict future development. The Piceance Basin in western Colorado has a history of energy production and development is expected to continue into the foreseeable future due to abundant natural gas resources. To facilitate analyses of regional energy development we digitized all well pads in the Colorado portion of the basin, determined the previous land cover of areas converted to well pads over three time periods (2002–2006, 2007–2011, and 2012–2016), and explored the relationship between number of wells per pad and pad area to model future development. We also calculated the area of pads constructed prior to 2002. Over 21million m2 has been converted to well pads with approximately 13million m2 converted since 2002. The largest land conversion since 2002 occurred in shrub/scrub (7.9million m2), evergreen (2.1million m2), and deciduous (1.3million m2) forest environments based on National Land Cover Database classifications. Operational practices have transitioned from single well pads to multi-well pads, increasing the average number of wells per pad from 2.5 prior to 2002, to 9.1 between 2012 and 2016. During the same time period the pad area per well has increased from 2030 m2 to 3504 m2. Kernel density estimation was used to model the relationship between the number of wells per pad and pad area, with these curves exhibiting a lognormal distribution. Therefore, either kernel density estimation or lognormal probability distributions may potentially be used to model land use requirements for future development. Digitized well pad locations in the Piceance Basin contribute to a growing body of spatial data on energy infrastructure and, coupled with study results, will facilitate future regional and national studies assessing the spatial and temporal effects of energy development on ecosystem function.

CO2 Storage Capacity for Multi-Well Pads Scheme in Depleted Shale Gas Reservoirs

As a promising technology to improve shale gas (SG) recovery and CO2 storage capacity, the multi-well pads (MWPs) scheme has gained more and more attention. The semi-analytical pressure-buildup method has been used to estimate CO2 storage capacity. It focuses on single multi-fractured horizontal wells (SMFHWs) and does not consider multi-well pressure interference (MWPI) induced by the MWPs scheme. This severely limits the application of this method as incidences of multi-well pressure interference have been widely reported. This paper proposed a new methodology to optimize the injection strategy of the MWPs scheme and maximize CO2 storage capacity. The new method implements numerical discretization, the superposition theory, Gauss elimination, and the Stehfest numerical algorithm to obtain pressure-buildup solutions for the MWPs scheme. The solution by the new method was validated with numerical simulation and pressure-buildup curves were generated to identify MWPI. Using the new method, we observed that the fracture number and fracture half-length have a positive influence on CO2 storage capacity. Both can be approximately related to the CO2 storage capacity by a linear correlation. For a given injection pressure, there is an optimal fracture number; the bigger the limited injection pressure, the smaller the optimal fracture number. Stress sensitivity has positive influences on CO2 storage capacity, thus extending the injection period would improve CO2 storage capacity. This work gains some insights into the CO2 storage capacity of the MWPs scheme in depleted SG reservoirs, and provides considerable guidance on injection strategies to maximize CO2 storage capacity in depleted SG reservoirs.

Spatiotemporal Industrial Activity Model for Estimating the Intensity of Oil and Gas Operations in Colorado.

Oil and gas (O&G) production in the United States has increased in the last 15 years, and operations, which are trending toward large multiwell pads, release hazardous air pollutants. Health studies have relied on proximity to O&G wells as an exposure metric, typically using an inverse distance-weighting (IDW) approach. Because O&G emissions are dependent on multiple factors, a dynamic model is needed to describe the variability in air pollution emissions over space and time. We used information on Colorado O&G activities, production volumes, and air pollutant emission rates from two Colorado basins to create a spatiotemporal industrial activity model to develop an intensity-adjusted IDW well-count metric. The Spearman correlation coefficient between this metric and measured pollutant concentrations was 0.74. We applied our model to households in Greeley, Colorado, which is in the middle of the densely developed Denver-Julesburg basin. Our intensity-adjusted IDW increased the unadjusted IDW dynamic range by a factor of 19 and distinguishes high-intensity events, such as hydraulic fracturing and flowback, from lower-intensity events, such as production at single-well pads. As the frequency of multiwell pads increases, it will become increasingly important to characterize the range of intensities at O&G sites when conducting epidemiological studies.

Unconventional gas development facilitates plant invasions

Vegetation removal and soil disturbance from natural resource development, combined with invasive plant propagule pressure, can increase vulnerability to plant invasions. Unconventional oil and gas development produces surface disturbance by way of well pad, road, and pipeline construction, and increased traffic. Little is known about the resulting impacts on plant community assembly, including the spread of invasive plants. Our work was conducted in Pennsylvania forests that overlay the Marcellus and Utica shale formations to determine if invasive plants have spread to edge habitat created by unconventional gas development and to investigate factors associated with their presence. A piecewise structural equation model was used to determine the direct and indirect factors associated with invasive plant establishment on well pads. The model included the following measured or calculated variables: current propagule pressure on local access roads, the spatial extent of the pre-development road network (potential source of invasive propagules), the number of wells per pad (indicator of traffic density), and pad age. Sixty-one percent of the 127 well pads surveyed had at least one invasive plant species present. Invasive plant presence on well pads was positively correlated with local propagule pressure on access roads and indirectly with road density pre-development, the number of wells, and age of the well pad. The vast reserves of unconventional oil and gas are in the early stages of development in the US. Continued development of this underground resource must be paired with careful monitoring and management of surface ecological impacts, including the spread of invasive plants. Prioritizing invasive plant monitoring in unconventional oil and gas development areas with existing roads and multi-well pads could improve early detection and control of invasive plants.

Numerical modeling of simultaneous hydraulic fracturing in the mode of multi-well pads

In order to investigate propagation regularity of hydraulic fractures in the mode of multi-well pads, numerical modeling of simultaneous hydraulic fracturing of multiple wells was conducted. The mathematical model was established coupling rock deformation with fluid flow in the fractures and wellbores. And then the model was solved by displacement discontinuity method coupling with implicit level set method. The implicit method was based on fracture tip asymptotical solution and used to determine fracture growth length. Simulation results showed that when multiple wells were fractured simultaneously, adjacent fractures might propagate towards each other, showing an effect of attraction other than repulsion. Fracture spacing and well spacing had significant influence on the propagation path and geometry of multiple fractures. Furthermore, when multiple wells were fractured simultaneously, stress reversal regions had a large area, and stress reversal regions were distributed not only in the area between fractures but also on the outside of them. The area of stress reversal regions was related to fracture spacing and well spacing. Results indicated that multi-well fracturing induced larger area of stress reversal regions than one-well fracturing, which was beneficial to generating complex fracture network in unconventional reservoirs.

Reservoir Characterization and History Matching of the Horn River Shale: An Integrated Geoscience and Reservoir-Simulation Approach

Summary We present a systematic approach to integrate geoscience and dynamic reservoir modeling for two multiwell pads in the Horn River basin, Canada. The Horn River shale-gas play is a world-class unconventional gas resource and is being exploited by use of multistage hydraulic fracturing along horizontal wells. The two well pads, Pad-1 and Pad-2, selected for this study comprise eight and seven horizontal wells, respectively, with 1 to 7 years of production history. Numerical modelling of shale reservoirs has historically been a problematic low-confidence exercise because of the difficulties associated with inadequate characterization of the geologic framework of shale plays; the problems of estimating the properties of induced-fracture networks; and the complexities of capturing multiphase flow in fracture networks and wellbores during production, especially in the face of offset-well activity. This paper provides insights into these issues. The geoscience modelling activity begins with integrating information from cores, well logs, petrophysical analyses, and seismic data into a 3D geocellular model. At first, the model is built upon a simple lithostratigraphic concept, which is the basis of the numerical-flow-modelling exercise of Pad-1. The 3D geocellular model is thereafter thoroughly reworked to incorporate a sequence-stratigraphic perspective to the Horn River shale. This reworked geocellular model has a profound impact on the dynamic modelling of Pad-2. Also, hydraulic conductivity of induced and natural fractures is measured on Horn River core plugs at reservoir conditions to constrain conductivity values assigned to primary, secondary, and tertiary flow paths into dynamic reservoir modelling. As a result of the integrated work flow, we have achieved a history match allowing us to further understand the hydraulic-fracturing behaviour and its impact on producing shale reservoirs of the Horn River formation. On the basis of the findings, we recommend targeting the Evie and Otter Park shale reservoirs for landing horizontal wells and multistage fracturing when the Carbonate Fan is thin; this approach can produce all three compartmentalized shale reservoirs of the Horn River formation. Ultimately, the objective of any reservoir modelling project is to provide a range of reliable forecast of future performance that is grounded in representative geoscience interpretations and that takes operational constraints into account. The technical learnings described in this work will be helpful to further understand hydraulic-fracturing behaviour and its impact on producing shale reservoirs.

Technology Focus: Reservoir Performance and Monitoring (September 2015)

Technology Focus Recent months have been very challenging for the oil and gas industry. When the previous Reservoir Performance and Monitoring feature appeared in JPT in September 2014, Brent was trading at approximately USD 105/bbl. At the end of June 2015, when this statement was written, its price was 41% lower, at just above USD 62/bbl. In addition, the world rig counts reported by Baker Hughes in September 2014 and June 2015 were 3,659 and 2,152, respectively, a decrease of approximately 41% (rig count is a trailing indicator of oil price). The international and North America rigcount decreases between September 2014 and June 2015 were approximately 12 and 57%, respectively. These steep decreases, mostly the direct consequence of a global imbalance between demand and supply, are warnings that our conventional innovation schemes need to be recalibrated. Even if the rig count has been dropping, the rig efficiency continues to improve. From multiwell pads to advanced drilling technologies, innovation is helping keep current production high. If current low prices persist, further innovation may improve the alignment between short-term production and long-term recovery, while lowering overall production costs. Maximizing short-term production and optimizing longterm recovery may provide key opportunities for cost savings during the next downturn of major proportions. This could be achieved through the industry’s ability to innovatively acquire and interpret data for optimizing the reservoir performance. The industry is continuously looking at new monitoring devices and techniques, and there are huge opportunities for monitoring fieldwide data with the ultimate goal of understanding the reservoir better and predicting its short- and long-term production more accurately. The current downturn may be a great opportunity for the big-data revolution from other industries to be extended to the oil and gas industry in general and to reservoir performance in particular. As a result of the industry’s current efforts to improve reservoir performance and reduce production costs, many great papers have been presented at recent SPE conferences and meetings. From the more than 100 papers reviewed for this feature, approximately half of them present case histories, field-data interpretation, and work flows, and the other half present theoretical and laboratory results. The papers summarized in this feature and recommended as additional reading are excellent samples of this distribution. JPT Recommended additional reading at OnePetro: www.onepetro.org. SPE 170619 Wireless Inflow Monitoring in a Subsea Field Development: A Case Study From the Hyme Field, Offshore Mid-Norway by Svein Mjaaland, Statoil, et al. IPTC 18115 Three-Dimensional Visualization of Solvent Chamber Growth in Solvent-Injection Processes: An Experimental Approach by F. Fang, University of Alberta, et al. SPE 171932 Linking Diagenesis, NMR, and Dynamic Data for Accurate Flow Characterization of Heterogeneous Carbonate Reservoir by Umer Farooq, Abu Dhabi Company for Onshore Oil Operations, et al. SPE 172929 Production Forecast, Analysis, and Simulation of Eagle Ford Shale Oil Wells by Basel Alotaibi, Texas A&M University, et al.

Eagle Ford Shale Well Control: Drilling and Tripping

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 163984, ’Eagle Ford Shale Well Control: Drilling and Tripping in Unconventional Oil and Gas Plays,’ by K. Ridley, SPE, M. Jurgens, SPE, R.J. Billa, SPE, and J.F. Mota, SPE, Shell, prepared for the 2013 SPE Middle East Unconventional Gas Conference and Exhibition, Muscat, Oman, 28-30 January. The paper has not been peer reviewed. In late 2010, Shell began an Eagle Ford appraisal program in the Piloncillo Ranch lease in south Texas. These wells are 8,500- to 9,500-ft-true-vertical-depth (TVD) horizontals, with an average total depth of 14,500-ft measured depth (MD). Initially, underbalanced-drilling techniques were used to drill the formation. As more wells were drilled, completion fracturing of offset wells began to cause well-control problems as induced fractures were encountered in horizontal sections during drilling. The authors describe the development of well-control techniques that allowed successful drilling operations. Well Design The original pore-pressure concept drove the field to a basic two-string casing design. The wells have 9?-in. surface casing and 5½-in. production casing. The surface-casing point was designed to be set between 3,000- and 3,500-ft TVD in the Midway shale below the base of the freshwater aquifer, which varies between 2,000- and 2,800-ft TVD. The fracture strength at this point was found to be 17 lbm/gal equivalent mud weight (EMW), which was considered to be sufficient for kick tolerance through the openhole interval to total depth (TD) in the Eagle Ford. The next hole section is then drilled out of the surface shoe to the kickoff point in the Austin chalk and landed in the upper Eagle Ford, where a 5,000-ft lateral section is drilled. The bottomhole assemblies (BHAs) were optimized until one run was possible from drilling out the surface shoe to TD of the well. The fracture strength of the surface shoe, along with the assumed pore pressure of 12.5 lbm/gal EMW in the Eagle Ford, allowed for a two-string design. This initial appraisal phase consisted of single-well pads with 5,000-ft laterals along a preferred azimuth. With further field development, the plan was set with multiwell pads in order to minimize the footprint and reduce undeveloped space in the reservoir (Fig. 1). Drilling—Phase 1: Initial Wells The first wells were drilled with a mud weight (MW) of 11.0 lbm/gal and exhibited few well-control challenges. No flow was observed while making connections or when performing flow checks at TD, and minimal background gas while drilling and at bottoms-up upon reaching TD was common. There was no flare during drilling, but the flare at bottoms-up at TD averaged between 10 and 20 ft. Previous experience in the Eagle Ford and other tight gas plays showed this level of gas to be manageable with a conventional rotating control device and a mud/gas separator. Some losses were encountered during the initial 5½-in.- production-casing cement jobs with a two-slurry design of top of cement at surface and a 12.7-lbm/gal lead and 16.4-lbm/gal tail. This was attributed to formation weakness in the Olmos sand, which occurred from 5,300- to 6,700-ft TVD. Equivalent-circulating- density simulations established this formation as a potential weak point, with an estimated fracture strength between 13- and 14-lbm/gal EMW across the field.

Centralized Water-Management Facilities in the Piceance Basin

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 169586, ’Strategies and Methods for Centralized Water-Management Facilities in the Piceance Basin,’ by Joseph J. Lobato, SPE, WPX Energy Rocky Mountain, and Gary Zolnosky, Chem Treat, prepared for the 2014 SPE Western North American and Rocky Mountain Joint Regional Meeting, Denver, 16-18 April. The paper has not been peer reviewed. The Piceance basin in western Colorado is a long-term play expected to produce for another 20 years or more. Given this extended time horizon, the operator implemented a permanent and centralized water-management infrastructure to control costs and improve profitability. The role of the centralized water-management facility (CWMF) is to treat water produced from natural-gas wells; recover oil and condensate; operate within federal, state, and county regulations; and consistently provide high-quality treated water for hydraulic-fracturing operations and disposal. Background Properly designed, implemented, and operated water-management facilities (WMFs) provide the means for controlling water-movement costs. WMFs also allow for predictable operations and provide a consistent high-quality water product on demand for hydraulic fracturing. Three types of WMFs will be discussed in this paper (these can be permanent or temporary): Centralized pumping stations for water transfer Pipelines Centralized water-treatment facilities Once it is determined that a facility is needed, the decision to build a permanent or a temporary facility is driven primarily by economics. The operator needs to complete an economic analysis comparing the total cost of building a permanent facility with the cost of using contract services and rented equipment to accommodate the business need. For a discussion of cost analysis in this context, please see the complete paper. Pipeline Facilities and Infrastructure Once the boundaries of the natural-gas-producing zones are established, the operator needs to plan and build pipeline infrastructure and begin the transition away from water hauling. Drilling and completing multiwell pads require high-volume, efficient, and cost- effective water movement. In the Piceance basin, operators use a technique called remote fracturing in which the equipment for completions is set up on one pad and all the well pads within a 3.5-mile radius are fractured from that single pad (Fig. 1). The remote-fracturing pad and surrounding well-pad arrangement are designated a centralized plan of development (CPOD). Pipeline Planning and Development In the Piceance basin, the most efficient way to move water for hydraulic fracturing and flowback is to build a water-pipeline loop through and around the area to be developed. In Fig. 2, two water-line loops are shown with a CWMF located between each loop. CPODs will be planned all around the loop; storage pits and transfer pumps can be installed and tied in anywhere around the loop, as needed. Water can flow in either direction around the loop. Use of 10-in.- inner-diameter or larger polyvinyl chloride pipe in the loop infrastructure will allow water-flow rates in the range of 25 to 50 bbl/min to and from the CPOD and remote-fracturing pad. With this high flow rate, wells can be completed very efficiently, with no water-delivery delays, and the number of water-storage tanks on the pad is reduced greatly.

Evolution of multi-well pad development and influence of well pads on environmental violations and wastewater volumes in the Marcellus shale (USA)

A majority of well pads for unconventional gas wells that are drilled into the Marcellus shale (northeastern USA) consist of multiple wells (in some cases as many as 12 wells per pad), yet the influence of the evolution of well pad development on the extent of environmental violations and wastewater production is unknown. Although the development of multi-well pads (MWP) at the expense of single well pads (SWP) has been mostly driven by economic factors, the concentrated nature of drilling activities from hydraulic fracturing and horizontal drilling operations on MWP suggests that MWP may create less surface disturbance, produce more volumes of wastewater, and generate more environmental violations than SWP. To explore these hypotheses, we use geospatial techniques and statistical analyses (i.e., regression and Mann–Whitney tests) to assess development of unconventional shale gas wells, and quantify environmental violations and wastewater volumes on SWP and MWP in Pennsylvania. The analyses include assessments of the influence of different types of well pads on potential, minor and major environmental events. Results reveal that (a) in recent years, a majority of pads on which new wells for unconventional gas were drilled are MWP, (b) on average, MWP have about five wells located on each pad and thus, had the transition to MWP not occurred, between two and four times as much land surface disturbance would have occurred per year if drilling was relegated to SWP, (c) there were more environmental violations on MWP than SWP, but when the number of wells were taken into account, fewer environmental violations per well were observed on MWP than on SWP, (d) there were more wastewater and recycled wastewater volumes per pad and per well produced on MWP than on SWP, and (e) the proportion of wastewater that was recycled was higher on MWP than SWP. This study sheds light on how the evolution from SWP to MWP has influenced environmental violations and wastewater production in a field that has undergone rapid development in recent years.

Target-rate Tracking for Shale-gas Multi-well Pads by Scheduled Shut-ins

The recent success of shale-gas production relies on drilling of long horizontal wells and stimulation with multistage hydraulic fracturing. This practice normally leads to an initial peak production with a subsequent rate decline, followed by low and erratic production rates caused by water accumulation in the wells. Shale-gas recovery requires a large number of wells in order to maintain a sustainable total gas supply. To reduce the surface area disturbances caused by this extensive drilling and to share available surface infrastructure, the use of multi-well pads is a key driver in shale-gas developments. Furthermore, the inherent rate decline of shale-gas wells, the water accumulation in them and the large number of wells, leads to severe operational challenges for well operators. The fact that shut-ins may be used as a means to prevent liquid loading and boost late-life production rates from shale-gas wells, suggests scheduling of shut-ins to perform maintenance and clean-up of the wells, and to track a target rate for the multi-well pad. In this paper we propose an optimization scheme for shale-gas multi-well pads to schedule shut-ins and to track a target rate. The optimization problem is formulated as a discrete time mixed integer linear program (MILP) with binary variables defining at which times the well is either shut-in or producing. A reservoir proxy model and a well model for each well is designed and tuned against a realistic multi-fractured reservoir model. We demonstrate the benefits and the potential of the proposed methodology through a one-month production planning problem for an eight-well shale-gas pad.

When Unconventional Becomes Conventional

Summary British Columbia (B.C.) has seen near-exponential growth in the areas of the Horn River and Montney unconventional shale-gas plays situated in northeastern B.C. (Fig. 1). The original-gas-in-place volume for the Montney and Horn River basins has not been formally calculated, but it has been estimated at greater than 500 Tcf and continues to be revised upwardly as new and more-refined information is obtained and development takes place. The Cordova embayment and Liard basin, east and west (respectively) of the Horn River basin, are at early stages of assessment but promise additional massive gas-in-place values. Approximately 5 years ago, industry experts were predicting a dramatic reduction in viable gas production from the western Canada sedimentary basin, and from North America in general. Market predictions were favouring investment in import terminals for liquefied natural gas (LNG), in which gas from offshore suppliers could be imported and moved through the North American transportation grid to market. Regulators were anticipating an influx of LNG-facility applications and myriad infrastructure modifications to handle the resulting new flow regime. In 5 short years, this dire future has been reversed completely because of the advent of economically viable methods to access gas trapped in shales and similar tight formations. At the current rates of production and exploration, there are more than 20 years of gas reserves in B.C., reversing a previous decline, as shown in Fig. 2. B.C. is ideally positioned to provide gas to North America with ready access to a number of major gas-transportation pipelines, including systems operated by TransCanada Pipelines, Spectra Energy Gas Transmission, and the Alliance Pipeline. Many of these systems are undergoing significant capacity expansions to accommodate the influx of gas from these new plays. This paper will explore the challenges posed to regulators in rapidly moving from conventional vertical-well developments to unconventional multiwell pads consisting of multiple fracture-stimulated horizontal wells.

Proppant Flowback Control in Deviated Shallow Gas Wells

Abstract This case-history paper presents results from various proppant flowback prevention methods. The wells studied are part of a shallow gas development project near Brooks, Alberta, Canada. The wells were drilled from multi-well pads resulting in deviated wellbores that reach the gas targets. Each well penetrates two or three gas bearing geologic formations, 400 m to 800 m in depth. Each formation has multiple sand and shale layers that were typically completed by perforating six or seven 2.0 m pay intervals. Then each interval was hydraulically fractured with energized, viscosified water frac fluid that placed 12 tonne of proppant in the formation. The fracture treatments were pumped through coiled tubing and a straddle packer was used to isolate each pay interval. The occurrence of undesirable proppant flowback into the wellbore lengthened clean-out time and increased disposal cost. Three solutions to the flowback problem were tried:curable resin-coated proppant;proppant surface- modification agent; and,fibre elements. Each product was tailed into the end of the frac treatment and the amount of each product used had to stay within the economic limits of the project. This paper describes the proppant flowback control achieved by each technique. Other considerations that were required to successfully pump the flowback control products are also discussed. Introduction History The occurrence of proppant flowback from propped hydraulic fractures has long been an operational problem. Many solutions to try and prevent proppant flowback have been attempted with inconsistent results(1, 2). In most cases, the unwanted proppant is produced during cleanup operations, immediately following the fracture treatment, when the well is being flowed or is swabbed to recover frac fluid. During this time, operators can easily handle the produced proppant with the equipment that is present for well stimulation and completion operations. However, proppant disposal can be time consuming and costly as well as reducing the effectiveness of the stimulation treatment. In other situations, proppant is produced during hydrocarbon production and can be a problem for the production life of the well. Proppant flowback can cause valve and choke erosion, plugging of surface vessels, and proppant can build up in the wellbore covering perforations. During production of the well, proppant flowback increases operating costs, compromises safety and reduces hydrocarbon production. Substantial work has been conducted in the industry to explain, predict, and reduce proppant flowback(3). Uneven closure of the formation on the proppant coupled with proppant settling allows upper portions of the proppant pack to be free moving. Proppant flowback is more prevalent in soft, low closure-stress formations and in deviated wells, but can occur in almost any situation. The chance of proppant flowback from properly packed fractures is reduced but proper packing does not insure proppant free production(2). The literature does not provide a clear understanding of proppant flowback causes or flowback prevention techniques. Problem In the subject case history, proppant flowback is a problem in the field's deviated wells but is not a problem in the nearby vertical wells.