Hydraulic fracturing technology requires securing sufficient water resources to access and unlock the pores of unconventional formations. Therefore, successful treatment depends on the fracture fluids, which mainly consist of water-based fluids with a low percentage (around 1%) of chemical additives. However, the oil and gas industry is among the largest freshwater consumers: three to six million gallons of water per well based on the number of fracturing stages. As a result, traditional water resources from subsurface and surface supplies are getting depleted, and freshwater is becoming more difficult to access with higher costs associated with continued demand. For example, operator companies in West Texas face many challenges, including a recent increase from USD 2 to 8 per barrel of freshwater. Also, the transportation of raw water to fracture sites, such as the Bakken shale play, has an environmental impact, with costs of up to USD 5 per barrel, while costs of water disposal range from USD 9 per barrel. This paper aims to investigate produced water as an alternative water-based fluid to several fracture fluids, such as crosslinked, linear gel, and high viscosity friction reducers (HVFRs) to reduce environmental footprints and economic costs. The workflow of this research started with a comprehensive review of extant publications, reports, and case studies to summarize the application of produced water with fracturing fluids in unconventional shale plays, such as the Bakken (North Dakota), Barnett (Texas), Eagle Ford (Texas), Wolfcamp (Texas), Marcellus (Pennsylvania), and Periman Bain (Texas). The critical review begins with explaining the features of produced water, its challenges, and water management options. Furthermore, the different fracturing fluids in a high TDS environment are described using recent lab fluid characterizations of produced water as 10% to 50% of produced water usage at a temperature range between 70 to 210 deg F. Moreover, 2D and 3D pseudo frac simulations are utilized using real field data from the Middle Bakken Formation to construct reliable models to evaluate the feasibility of reused water in shale plays development. The outcomes show that recycling water with high TDS in a high-temperature environment can create a fracture network and proppant transport when high viscosity friction reducers with surfactant (HVFR-PRS) was used. In addition, the result of this critical review is a powerful tool for predicting the future of hydraulic fracturing technology, which might help operator companies reduce costs and develop unconventional wells successfully for a return on their investment. The opportunities and challenges conclusions of water management are provided a survey of future hydraulic fracturing applications in North American shale plays by offering recommendations of environmental and economic impacts. The general guidelines obtained can promote the sustainability of using hydraulic fracturing treatment to produce more oil and gas from unconventional resources without compromising on environmental issues.

Coalbed Methane (CBM) is becoming a significant portion of the US gas resource and is gaining importance in Australia, China, Indonesia and Europe. CBM reserves in the United States are estimated at some 450 Tscf. In Australia, CBM resources exceed 300 Tscf, while China has a resource potential greater than the United States and Australia combined. Recent advances in well design and production technology offer scope to significantly increase the proportion of gas contained in coal that can be commercialized. Generally, initial water saturation is 100% within coal seams and gas can only be found as an adsorbed phase inside the coal matrix, so how much adsorbed gas can be released at an economical rate will determine the ultimate gas recovery. The Langmuir isotherm has been widely used in industry to describe the pressure dependence of adsorbed gas. However, temperature dependent adsorption behavior and its major implications for evaluating thermal stimulation as a recovery method for coalbed methane have not been thoroughly explored. Therefore in order to investigate the feasibility of thermal treatment in coal bed methane reservoir successfully, it is crucial to understand the effects of thermal stimulation on the adsorption and desorption phenomenon, and how can we exploit such effects to enhance coalbed methane recovery from hydraulically fractured reservoirs. In this study, we propose a method to evaluate desorbed gas as a function of pressure and temperature in coal seams, by regression on Langmuir isotherm data. In addition, a CBM reservoir simulator is developed, which is capable of capturing real gas diffusion in the coal matrix and flow in the hydraulic fractures, as well as the heat transfer process within the matrix. This simulator enables us to investigate various thermal stimulation techniques on the global well performance and recovery. The results of this study show that by increasing the formation temperature, ultimate gas recovery can be improved in CBM reservoirs. The higher the thermal stimulation treatment temperature, the more extra gas can be recovered. However, the efficiency of thermal stimulation is mostly constrained by how much the formation area/volume that can be stimulated in a reasonable period of time. Due to the low heat conductivity of coal, it is not possible to heat up a large drainage area/volume by heating the surface of vertical hydraulic fractures directly. If the heating source (e.g., electromagnetically excited nano-particles) can be dispersed further into the formation through the cleat system during hydraulic fracture execution, then larger formation area/volume can be heated up, depending on how further the nano-particles can be pushed and the arrangement of production (injection) wells. In the case of horizontal fractures, a large formation volume can be thermally stimulated if the fractures can be placed close enough to cover the whole lateral area. Thermal stimulation by hot water/steam injection can increase formation temperature more rapidly than direct element heating methods, especially when the formation permeability is large. Considering large amount of residual adsorption gas still left behind even with low production pressure, thermal stimulation has the potential to enhance CBM recovery substantially if techniques and designs are tailored to the formation properties appropriately.

A hydro-geomechanical coalbed methane reservoir characterization workflow is reviewed and applied to three field cases from the same coalseam formation. The workflow begins from core sample characterization and ends at reservoir performance. A core sample and geophysical logging rock mass characterization approach using the newly adopted Geological Strength Index (GSI) is used. GSI was developed for Civil Engineering tunneling projects to characterize fractured rock masses and is adopted here with new functions to related GSI to observed Young's modulus and then included for permeability changes during production. The GSI characterization is applied to three separate reservoir geomechanical simulation models with separate and distinct production profiles. Reservoir and geomechanical data to populate the models comes from three sources: Nexen, the University of Alberta, and the Alberta Energy Regulator. The significance of this study is to investigate the influence of geomechanics on well productivity for fractured reservoirs using a common geological parameter which relates fracture intensity to mechanical properties.

Unconventional gas reservoirs have complex storage and transport properties that are difficult to characterize and are dynamic. The large internal surface area of nano-scale organic pores gives them the capability to store adsorbed gas along with free gas, with the amount of free gas storage changing as a function of adsorption/desorption. Further, diffusion and slippage mechanisms compete with compression and possibly matrix shrinkage effects to alter absolute permeability of the organic matter pores. An additional factor controlling permeability change, which has not been previously considered, is the change of effective radius of organic matter pores as a function of adsorption/desorption. A statistical study is required to fully explore the overall effect of the above mentioned parameters on unconventional gas well production performance, along with other properties such as total carbon content, pore connectivity configuration, adsorption capacity, pore size distribution, and natural fracture intensity. In this study we investigate two sets of matrix pore sizes thought to represent a reasonable range observed in unconventional gas reservoirs. Pore size affects the interaction between the gas molecules and pore walls and results in a distribution of adsorbed phase thickness. Therefore, the adsorbed layer modifies the effective hydraulic radius for flow of gas which in turn alters the effective permeability to the gas phase in organic matter pores. This complexity can be captured by combining the simplified local density model and apparent permeability approaches. The contribution of compression and matrix shrinkage to fracture permeability change with pressure is also investigated and compared to changes in apparent permeability in the matrix caused by diffusion and slippage mechanisms. A commercial reservoir simulator is used to study the effects of pore size and pore size alteration, and consequent permeability changes, on unconventional gas well performance. A screening statistical method is used to quantify the relative importance of each factor. The results of this study will help the engineers evaluate the relative importance of all of the permeability-altering processes that can affect unconventional gas well performance, and make appropriate simplifying assumptions. This will enable them to prioritize history matching parameters for real production data analyses and forecasting, which in turn decreases the time required for a complete field simulation study.

The production of natural gas from coal seam gas reservoirs has had a long and established history in the energy industry. Due to the relatively low permeability seen in many of these reservoirs, hydraulic fracturing is sometimes required to achieve economic production rates. The economic validity of hydraulic fracturing is dependent on a number of factors, including reservoir properties (and subsequent production rates), cost of stimulation services, as well as the type and quantity of materials. The justification of hydraulic fracturing is usually performed through net present value (NPV) analysis. NPV models for hydraulic fracturing in conventional and shale reservoirs are readily available in literature; however the same cannot be said for coal seam gas. This paper presents a NPV model adjusted to the coal seam gas environment. That is, it considers the effect of the dewatering period required before natural gas may be desorbed from the targeted formation. The model only considers the incremental production of hydraulic fracturing as well as the incremental cost to fracture, thereby demonstrating the true present value of the treatment. Included in the model is a break-even price required for sales gas. The production data represented within this paper was forecasted utilizing a pseudo three dimensional model that integrates unified fracture design (UFD). Sensitivity analyses were performed based on variances in reservoir properties (e.g. net pay, permeability, Langmuir isotherm) and stimulation design (e.g. proppant mass, type of proppant). This allows for greater understanding of the effects of the reservoir upon the economics of the project, as well as providing a means to economically optimize stimulation design.

There are three distinguishing phases in the production life of a wet CBM well: a period of inclining gas rate due to dominance of relative permeability effects, a period of rate stabilization during which the gas rate peaks followed by the depletion phase during which gas production rate declines. The declining gas production rate can be attributed to many factors such as: ■ Declining reservoir pressure ■ Loss of productivity due to compaction and permeability loss ■ Loss of productivity due to fine migration that creates a choke skin near wellbore While the decline in reservoir pressure is inevitable, the loss of productivity due to the choke skin and permeability loss for a declining CBM well can be remedied or slowed down through a multi-stage hydraulic refracturing. The impact of such fracturing on improving well productivity and boosting the gas production rate is investigated. Reworking the well through refracturing could help clean up the zone near wellbore, re-activate or improve the coal network of natural fractures; lead to more effective dewatering and even create new contacts between the reservoir and formation. The area near wellbore will benefit from re-invigoration of fracture network and creation of an area of enhanced permeability. In this study the benefit of completing a new vertical and/or horizontal CBM well with a multi-stage hydraulic fracture is examined. The production of wells with such completions are compared to typical single-stage fracturing and benefits of creating an inner zone of enhanced permeability in short-term and long term are investigated. A numerical dual-porosity reservoir model is used to generate the CBM gas production forecasts.

Although the modern Alberta petroleum industry has been in existence for 65 years, the past decade has seen the courts and the legislature wrestle with some fundamental issues relating to the ownership of resources. Indeed, some of the most contentious issues have arisen within the last year. The first part of this paper is based on the approach taken by the Canadian courts as they were required to resolve subsurface ownership issues. In the earliest days of the industry, this process began with the initial determination that it was possible to distinguish between the ownership of petroleum and natural gas within the same reservoir. The paper will examine the extension of this approach as novel issues arose in more recent times, including the ownership of evolved (or secondary associated) gas, coalbed methane and gas found in association with bitumen. The bulk of the paper will discuss controversial recent changes instituted by the government of Alberta between 2007 and 2011. They deal with the clarification of resource rights, the direct removal of resource rights and the rate of return from the exploitation of resource rights. The recent actions of the Alberta government have been seen as a departure from the traditionally favourable legal and policy environment enjoyed by the energy industry. The paper will demonstrate that the controversial initiatives of the government do represent a break in the tradition that was followed between 1981 in 2007, but they are consistent with the attitude of the provincial government over the long term. The paper will provide guidance on the existing state of law in Alberta and some of the legal and policy consequences of the recent government actions. It will examine the reasons for the changed approach adopted by the government over the last four years with parallels to the period of rising energy prices that occurred between 1971 and 2001.

Relative permeability of coal to gas and water is an important variable in coalbed methane (CBM) reservoir development as it is required for reserve estimation and field production planning. In this study, two coal samples (GP and GS) were used to determine the relative permeabilities using three gases (He, CH 4 and CO 2 ) at three different operating pressures (100, 300, 400 psi) and a constant overburden pressure of 800 psi. Both drainage and imbibition curves were obtained. Unsteady state displacements were used. The petrophysical properties of these coal samples were also measured. The very low absolute permeability of the cores (0.07 mD) required special procedures to minimize errors. The experimental results presented here showed that the relative permeabilities were typically very low for all gases and high for water. The irreducible water saturation showed correlation with the type of gas (non-adsorbable He to strongly adsorbable CO 2 ) and pressure. It is concluded that coal relative permeability to gas and water depended on the nature of gas and the operational pressure. Relative permeability of coal changed also because of fluid-mineral interactions. It is concluded that the GP and GS samples tended to be more water-wet at higher pressures in the case of the adsorbable gases, viz. methane and carbon dioxide. However, in the case of non-adsorbing helium, higher pressure prevented the influx of water into the larger pores leading to smaller irreducible water saturation.

It is estimated that only 5% of Alberta’s CBM reserves are recoverable (Rieb, 2006). A variety of techniques such as horizontal drilling and new fracturing methods have allowed greater recoveries of the methane gas. Alberta Innovates – Technology Futures (formerly the Alberta Research Council) is developing a biotechnology that stimulates and enhances biogenic methane production coal seams. Biogenic methane production is believed to have occurred in the geological past, and is believed to be still occurring in deep, subsurface coal seams albeit at extremely slow rates. It is postulated that the native microorganisms are nutrient limited and, based on laboratory evidence, by adding an organic, nitrogen-rich nutrient, the methane production rate can be increased up to 30-fold over non-amended cutlures. The microbial diversity of Alberta coal seams has begun to be mapped out using state-of-the-art genomic sequencing techniques. It appears the geophysical environment has a strong influence on the types of microbes present as the microbial populations from deeper, more saline Mannville coals are significantly different than the microbes detected in Horseshoe Canyon coals. The microbial population changes upon addition of a nutrient, with shifts occurring in the types of fermenting organisms and methanogenic species. Low molecular weight monocarboxylic acids were observed to be produced and then consumed over the incubation period. These methanogenic precursor substrates accumulated in cultures with only nutrient and no coal. Much lower methane production occurred in these cultures suggesting an unbalanced nutritional state, whereas those cultures with un-limiting carbon from coal and nitrogen source from the nutrient generated large amounts of methane. The effects of surface area, bioavailability of coal moieties and coal porosity and permeability on biogenic methane production are under investigation. Results will aid in the design and deployment of an effective enhanced biogenic methane coal bed field trial.

Coalbed methane (CBM) production in the San Juan Basin of northwestern New Mexico and southwestern Colorado has spanned over 30 years. Some parts of the field, such as the high-permeability Fairway, are now in a mature stage of reservoir pressure depletion. Optimization of well production operations in the Fairway presents many challenges because of its extremely low reservoir pressure (less than 100 psi in some areas), heavy coal fines production, difficult artificial lift challenges, increasing CO 2 %, and the presence of paraffin, inorganic scale and corrosion. We use history matching by reservoir simulation to help diagnose the causes of well production inefficiencies and then plan how to mitigate them. Simulation of Fairway wells typically requires the use of an increasing reservoir permeability trend caused by coal matrix shrinkage with the desorption of methane and CO 2 . However, we have observed in some Fairway wells that below a reservoir pressure of around 300 psi, there is a flattening or even a decrease in the permeability trend. This shift in the permeability trend is likely caused by coal failure (i.e. a change in mechanical properties of coal) that is evidenced in the wells by an increased amount of coal fines production. This paper is written in two parts. The first part presents the challenges we face in operating Fairway wells and the solutions we have developed to overcome them. Field observations and operating guidelines will be shared along with well intervention histories where we have seen success. The second part discusses our use of reservoir simulation to diagnose the causes of reduced well production efficiency.

Development of CBM in the Horseshoe Canyon (HSC) has exploded since its commerciality was first demonstrated in 2003. To date over 15,000 wells have been drilled and are producing from HSC coals. Quicksilver's development has been steady with approximately 1800 wells drilled and brought on-line between 2003 and 2009, and today operates 17 development pods located throughout the HSC fairway. This case study overviews Quicksilver's learnings and experiences from these activities including various aspects of geological and resource assessment, development tactics and recovery optimization, and presents practical datasets for appropriate management of the resource. Geological investigation has been an important factor right from the outset of this play's development. Many initial concepts have been challenged and subsequent production data often shows discordant relationships with geological parameters used to calculate net pay, depth, and subsequently the OGIP. Water production trends, gas rate variability, anomalous seam contributions, nonlinear pressure gradients, and variable permeabilities are discussed within this case study and the challenges that they present. As development unfolds, production data has increasingly become a key factor in understanding these unconventional reservoirs, and is variable between areas and even within the development pods / areas themselves. Despite the variability, trends have been identified using production indicators and forecasts. A statistical approach is used to examine these trends, and in conjunction with the geology / resource characterization is enabling improved management decisions for optimal development. In particular variable density drilling, ranging from 2 wells per section to 8 wells per section, as well as various pilot higher density projects, is examined closely and provides valuable information from a reservoir development and optimization perspective. Impacts of sands completions as an add-on to the primary CBM target are also investigated.

Western Canada has had a thriving conventional energy industry for many decades. It encompasses the exploration, development, transformation and transportation of hydrocarbons to markets across North America. In Quebec, until recently the oil and gas industry was limited to distribution and transportation activities. As an industry, it regulated the infrastructure needed to process hydrocarbons and the legislation had very little to do with the exploration and development of hydrocarbons. However, with shale gas development, technological breakthroughs, and more favourable pricing conditions, Quebec has witnessed the birth of an unconventional oil and gas industry which now includes intense activity by exploration companies, developers and possibly, over the next few years, producers. The Western Canadian regulatory framework will be reviewed and contrasted with the emerging Quebec regulatory framework to highlight the different challenges that may arise. We will outline the legislative framework that governs the unconventional oil and gas industry in Quebec. Also, we will address the potential liability of officers and directors regarding the reclamation and abandonment of upstream facilities. We will comment on Quebec laws regulating land use, planning and the environment which may pose specific challenges depending on whether or not local gas lines, or processing plants need to be built or implemented. The oil and gas industry in Quebec is made subject to mining laws that are not entirely compatible with industry practices of traditional players. The regulation of unconventional oil and gas is emerging throughout North America. In the St-Lawrence valley in the past 5 years, there has been a thriving exploration push. This exploration could lead in the medium to longer term to the securing of defined reserves for consumption in the local market. There had been anecdotal evidence of this over the years; however, recently this possibility has become very real indeed. Millions of dollars had been invested over the years by local entities such as Petrolia and Gastem Inc. These juniors have partnered with western Canadian or American players which have confirmed their participation and are motivated to further exploration and development of shale gas discoveries and unconventional oil plays.

In developing the Doris Mannville Coal Bed Methane (CBM) gas field near Fort Assiniboine, Alberta, the Nexen exploitation team encountered many unforeseen artificial lift challenges using Electric Submersible Pumps (ESPs). High failure rates and short pump run times made forecasting of production volumes and reserves difficult, while high operating costs driven primarily by downhole servicing reduced the economic viability of the project. The root cause of the high pump failure rate was attributed in most part to the unanticipated volume of produced coal fines and reservoir solids in the produced water stream. The production of these solids, coupled with lower than expected water production rates, led to a re-evaluation of the field's artificial lift strategy. Following a thorough artificial lift evaluation, a change from an ESP to a reciprocating rod pump (Pump Jack) system was initiated. The largest anticipated benefit of reciprocating rod pumping systems over ESP artificial lift systems were: Increased minimum flow path area through the system, reducing the frequency of solids plugging, leading to longer pump run times. Reduced well servicing costs with reciprocating rod pumps through elimination of services required solely by ESPs. Elimination of pump failures due strictly to electrical shortages by changing from an electrical/mechanical (ESP) to a straight mechanical (Pump Jack) downhole system. Improved operating efficiency by matching artificial lift design with actual water production rates. The change in artificial lift strategy made an immediate impact on pump failure rates in the Doris field. This paper will present the resulting increased pump run times, sustained production rates and drastically lower operating costs that has made reciprocating rod pumping systems the artificial lift method recommended by Nexen to exploit Alberta's Mannville coal for CBM.

Fort Assiniboine is a commercial Coalbed Methane field in central Alberta, Canada with over 200 multilateral horizontal wells in the Upper Cretaceous Mannville coal. The Mannville coal seams in this area are under-saturated. Therefore the reservoir's ability to dewater the coal through the fracture fabric to establish a gas phase is key to improving permeability to gas within the fracture system and thus achieving economic gas production rates. There is a wide range of production rates seen across the field. The multiple variables that affect gas production can be divided into a two main categories, wellbore parameters and reservoir parameters. Some of these variables were sufficiently straightforward to establish while other variables, such as permeability, are not as easily ascertained in a fractured coal system having multiphase flow. Field wide data was collected from core, wells, geological and geophysical mapping and production data. The information was compiled and analyzed in order to determine the major controls on gas production rates.

Alberta's Energy Resources Conservation Board (ERCB) has regulated oil and gas resource development for almost 75 years. Throughout most of that time the industry and the regulator were concerned with conventional oil and gas resources. In the last decade or so the emphasis has shifted, for several reasons, towards unconventional resources— in situ bitumen, tight oil, tight gas, deep- or basin-centred gas, coalbed methane (CBM), shale gas, and in situ coal gasification. The characteristics of these resources, as well as the technologies required to develop them, create the need to modify the ERCB's regulatory framework. This is integral to reaching the ERCB's vision of being The Best NonConventional Regulator in the World , capable of dealing with the pressing issues of the future energy development in Alberta. Given the realities of the changing resource base, unconventional resources are a priority, and the ERCB needs to adopt non-conventional ways of regulating their development. The ERCB has already adapted the regulatory framework to deep/basin-centred/tight gas, coal bed methane, and in situ bitumen. The ERCB responded with new regulatory structures—Development Entities for CBM and Deep Basin gas; control wells for CBM; commingling of production streams from coal-sand sequences—to more effectively manage the development of some of those resources. After only a few years of operational experience, and with industry feedback, we have already improved the efficacy of some of these approaches and continues this effort as an ongoing practice. Moving to the next level, however, requires some substantively different approaches. The ERCB's Unconventional Gas Regulatory Framework Project is intended to identify new ways of regulating and facilitating such resource development. It is being done with the consultative input of knowledgable stakeholders. We have already determined the major regulatory risks, and are focusing on developing ways to mitigate them with the appropriate level of necessary regulation or other, non-regulatory means.

One of the horizons of interest for future unconventional resource development is deep (greate than ~5,000 ft) coalbed methane (CBM) production. Unfortunately, coal permeability is highly sensitive to changes in stress leading to the belief of limited permeability in deep coals. However, this conclusion is generally based on the assumption of constant pore volume compressibility of a coal's porosity/cleat system during changing stress conditions. Modeling the evolution of permeability within potential deep coal reservoirs is highly dependent on this assumption of constant or variable pore volume compressibility. This paper shows how this assumption affects modeled permeability changes and that permeability in deep coals may maintain much higher values during production than previously suggested. Utilizing prior work and data, ideas are reorganized into an alternative view of deep CBM permeability. The modeled compressibility and permeability results are then applied to the simulation of deep CBM reservoirs to discover the practical difference of the compressibility assumption on a coal's simulated production. Simulations show significant difference in production based on the two assumptions. Application of the simulation results may provide a justification for exploration into deeper CBM reservoirs.