British Columbia has seen near exponential growth in the areas of the Horn River and Montney unconventional shale gas plays situated in North Eastern B.C. (figure 1). The original gas in place volume for the Montney and the Horn River basins have not been formally calculated but have been estimated at more than 500 Tcf and continues to be revised upwards as new and more refined information is obtained as 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 drastic reduction in viable gas production from the Western Canada Sedimentary Basin, and North America in general. Market predictions were favouring investment in import terminals for liquefied natural gas (LNG) where 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 as well as a myriad of infrastructure modifications to handle the resulting new flow regime.
In five short years, this dire future has been completely reversed due to 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 year of gas reserves in BC, reversing a previous decline, as shown in Figure 2.
Hydrate reservoirs have been categorized as Type I, II, and III; Type I with underlying free-gas, Type II with underlying free-water, and Type III that is sandwiched by impermeable formations. The most common type of hydrate reservoirs are probably Type III reservoirs, where there is no underlying mobile phase beneath the hydrate layer. Depressurization in Type III reservoirs is characterized by difficulty in reducing pressure over a large region because of limited available surface area for decomposition and low permeability in the hydrate. This is unlike to be the case in Type I and II reservoirs, where pressure could be reduced across a large surface area between the hydrate and the underlying free phase.
A 3D numerical model incorporating heat and fluid flow, along with kinetics of decomposition and (re)formation of hydrate and ice, is developed in this paper. Next, the solution behaviour of Type III hydrate reservoirs in response to application of the depressurization technique is studied, with the goal of understanding the interactions between fluid and heat flow and their effects on the decomposition region. This is achieved by exploring for similarity solutions in Type III reservoirs.
The results of this study indicate that the behaviour of Type III reservoirs is sometimes close to that of diffusion problems, suggesting that a similarity solution exists. This has also been shown to be the case in the literature. However, under some other conditions, it is shown that the solution to this problem is also identical to a travelling wave solution, which is another type of similarity solution often observed in diffusive-reactive problems that exhibit frontal behaviour and sharp gradients. Conditions leading to development of these two types of similarity solutions are identified.
The contribution of this work is in identifying the different solution regimes in Type III hydrate reservoirs. This could help to understand and simplify the modeling of governing mechanisms involved in the process of gas production from the most common type of hydrates.
This presentation will review the nature of fractures in the Jean Marie from thin section to the seismic scale and focus on the seismic methods used to detect and exploit these high permeability fairways. Drilling results and production indicators of fracture flow will be reviewed, and the controls on fracturing discussed.
The Jean Marie carbonate is an Upper Devonian aged carbonate platform that developed on the western margin of North America. Gas is regionally trapped in moderate porosity and low permeability stromatoporoid-renalcid limestone reef mounds and limestone intermound sediments. The pool has been developed using underbalanced horizontal drilling to minimize damage to the fine pore system in this under-pressured reservoir. Advanced seismic techniques are being used to detect porosity zones and high permeability fairways which increase deliverability and recovery of gas from the Jean Marie carbonate. Variable well productivity has been observed in similar facies, as has high productivity in low porosity rock.
In the last five years, in the Kotcho area, Encana has been targeting natural fracture/fault networks in the Jean Marie. These zones of fracture enhanced and diagenetically altered carbonates have better permeability, and often better porosity. The fracture networks appear to have controlled the distribution of hydrothermal fluids which enhance the porosity and permeability of the carbonate via dissolution and recrystalization. Horizontal wells that encounter fractures generally have better deliverability and greater associated reserves. The use of seismically derived porosity and fracture detection techniques has improved the well planning and the frequency of discovery of higher permeability/deliverability zones.
Fracture detection is an important component in the development of the understanding of the permeability system in a reservoir. Fractures and faults can be high permeability production zones, or thief zones for fracturing programs, or barriers to flow if they are cemented shut. The techniques used by Encana in the Jean Marie can be applied to other reservoirs and other lithologies.
Since 1979, Alberta's Energy Resources Conservation Board (ERCB) and other Canadian authorities have been releasing reserves estimates based on the report of the Joint Task Force on Uniform Reserves Terminology to the Inter-Provincial Advisory Committee on Energy (IPACE). This report, while including terms related to petroleum types and recovery methods, defined three main resource/reserve terms; Initial Volume In-Place, Established Reserves (both Initial and Remaining), and Ultimate Potential.
While the IPACE terminology is a simple and useful system, and is well suited to conventional pools, it is not as well suited to continuous accumulations, especially in classifying in-place quantities that are currently being developed from those that have been or those that might be developed in the future. Additionally, its definition of established includes a quantity of less certainty that is not well defined and has been interpreted in several ways. With the increasing importance of unconventional resources, the introduction of newer classification systems by Canadian and international authorities, and the evolving nature of its business, the ERCB began a review of the IPACE terminology.
The review concluded that the IPACE system, particularly with initial established reserves and ultimate potential, is still a very useful classification scheme, especially for resource management, but would benefit from modification to better suit the wide potential of unconventional resources. The most significant potential changes envisaged are the introduction of multiple in-place categories, the alignment of established reserves with "best estimate??, and the recognition of established reserves under active development.
Unconventional resources continue to gain importance to the future long term energy supply of Canada and the ability for governments to reasonably classify their full potential is important. Potential modification of the IPACE system recognizes these two issues.
Recently, the Ensemble Kalman Filter (EnKF) has emerged as an effective tool for performing continuous updating of petroleum reservoir simulation models. The method is firmly grounded on the theory of Kalman filters and sequential Monte Carlo techniques. The ability of the method to sequentially update the spatial properties in petroleum reservoir models, such as permeability and porosity, by integrating the dynamic production data makes it a very attractive approach. Moreover, the method takes into account the production uncertainty in the reservoir models by using error covariance matrices for the measurement vector (Production and injection rates, Gas-Oil ratio, Steam-Oil ratio, etc.) and the state vector (pressure, saturation, permeability, porosity). Similar to the traditional Kalman filter, the covariance matrices have to be tuned to reflect the uncertainty in the model and the measurements. We consider two unconventional oil reservoir models: 1) highly heterogeneous black-oil reservoir model, and 2) heterogeneous SAGD reservoir model. The results will demonstrate the advantage of using the localized EnKF for effective history matching using ensemble sizes relatively lower than what otherwise would be required with the ordinary EnKF. The results will also show the advantages of using prior knowledge available from the wells (permeability and porosity measurements) to generate initial realizations. One of the main practical advantages of history matching using the EnKF over traditional optimization based approaches is its low computational effort. The computational cost is dominated by Monte Carlo simulation of the ensemble of models only. Thus, significant computational time saving is possible by running each of the ensemble simulations on independent processors in a parallel mode. Moreover, the method can be easily integrated with any commercial reservoir simulation software.
Traditionally reserves management has been an exclusive function for Reservoir Engineers; however in mature fields the need to involve Production, Facilities, Geology, Operations Engineers and Financial Analysts is critical. This paper presents a suggested workflow to improve the way reserves are evaluated, supported, booked and documented with a concerted effort of a multidiscipline team. This paper is focused on tight gas reservoirs and the central idea is to reduce the uncertainty that is always present when dealing with reserves.
Most of the discussion is concentrated in understanding and verifying the hyperbolic decline "b?? factor to be used for production decline analysis; we normally understand the mathematical meaning, but very rarely spend the time understanding the physical meaning and the consequences of using the wrong value. Once the "b?? factor is defined, the proper documentation must be filed for each reserve record and the focus becomes the economic analysis of those reserves which is critical for future development especially in a very volatile economy in which prices are fluctuating a lot.
Schicks, Judith Maria (GeoForschungsZentrum GFZ) | Spangenberg, Erik (GeoForschungsZentrum Potsdam) | Steinhauer, Bernd (GFZ) | Klump, Jens (GFZ) | Giese, Ronny (GFZ) | Erzinger, Joerg (GeoForschungsZentrum Potsdam) | Haeckel, Matthias (IFM-Geomar) | Bigalke, Niko (IFM-Geomar) | savy, Jean-Philippe | Kossel, Elke | Deussner, Christian | Wallmann, Klaus
Huge amounts of CH4 bound in natural gas hydrates lead to the idea of using hydrate bearing sediments as an energy resource. Natural gas hydrates remain stable as long as they are in mechanical, thermal and chemical equilibrium with their environments. Thus, for the production of gas from hydrate bearing sediments, at least one of these equilibrium states must be disturbed by depressurization, thermal stimulation or addition of chemicals such as CO2. In the framework of the German national gas hydrate research project SUGAR (Submarine Gas Hydrate Reservoirs), all three reaction routes - alone or in combination - are tested. The aim is to find the most flexible and efficient, but also environmentally friendly method for gas production from hydrates. One method in this context is the thermal stimulation using in situ combustion. Therefore, a heat exchange reactor was designed and tested for the catalytic oxidation of methane. Furthermore, a large scale reservoir simulator (Volume 425 l) was realized, to synthesize hydrates in sediments under conditions similar to nature and to test the efficiency of the reactor. Thermocouples placed in the reservoir simulator collect data regarding the expansion of the heat front, respectively. These data are used for numerical simulations for up scaling from laboratory to field conditions. However, thermal stimulation may be used alone or in combination with CO2 sequestration. Therefore, laboratory studies on the methane production from pure hydrate phases as well as hydrate bearing sediments by use of CO2 injection are investigated using several analytic tools such as Nuclear Magnetic Resonance spectroscopy, confocal Raman spectroscopy and X-ray diffraction.
In this study we present the experimental set up of the large scale reservoir simulator and the reactor design. Preliminary results show that the catalytic oxidation of CH4 in a countercurrent heat exchange reactor operated as a temperature controlled, autothermal reaction outside of the flammability limits of CH4 is a safe and promising tool for the thermal stimulation of hydrates. In addition, preliminary results from the laboratory studies on the CO2-CH4 swapping process in pure and pore-filling gas hydrates are presented focussing on the kinetics of this process.
As gas production from conventional gas reservoirs in the United States decreases, the industry is turning more to the exploration and development of unconventional gas resources (UGR), especially shale gas reservoirs. This trend is expanding quickly worldwide. Unlike in many mature North American basins, where resources and reserves are well characterized, the volume of unconventional gas resources is generally unknown in most basins outside North America (frontier basins). Therefore, a comprehensive investigation and evaluation of North American unconventional gas resources is significant not only for identifying and understanding the quantitative distributions of recoverable UGR in North American basins, but also for estimating the volume of UGR in frontier basins. Our investigation of North American unconventional gas resources is based on the resource triangle concept, which implies that all natural resources, including oil and gas, are distributed log-normally in nature. Martin et al. (2010) described a methodology to estimate values of total recoverable resources (TRR) for unconventional gas reservoirs. In their work, the authors combined estimates of production, reserves, reserves growth, and undiscovered resources from a variety of sources into a logical distribution. They used data from 8 basins in North America to demonstrate their results. We have expanded the work of Martin et al. (2010) to include data from a total of 25 basins in North America. The results show that the overall ratio of TRR in unconventional gas reservoirs to those in conventional oil and gas reservoirs in the 25 basins is approximately 4 to 1. This means that for every Tcfe of oil and gas produced from conventional reservoirs, one could expect another 4 Tcfe to be technically recoverable from unconventional gas reservoirs in the same basin. This observation can help companies assess the potential of unconventional gas resources development in North American basins and in frontier basins worldwide.
Driven by a new understanding of the potentially huge amount of unconventional gas resources (UGR) and the feasibility of unconventional gas development, global interest in the development of unconventional gas reservoirs has been on the rise during the last few years. In North America, unconventional resources have been produced for decades and play a major role in the national energy picture. Around the world, UGRs can be found in every major oil and gas basin, but have yet to serve as the major contributor for energy supply, partly due to the scarcity of information about the exploration and development technologies required to produce UGRs (Holditch et al. 2007). Also, there are many factors, such as service company infrastructure, gas markets and low gas prices in some areas, which will inhibit development any time soon. However, to fulfill the growing global energy demand, unconventional resources outside of North America will receive more attention in coming years. To better evaluate the UGRs in North America, Martin et al. (2010) developed the software system Petroleum Resources Investigation Summary and Evaluation (PRISE). PRISE used data from 8 basins to assess total recoverable resources (TRR) in unconventional gas reservoirs (UGR) (Martin et al. 2010). In this paper, we expand the work of Martin et al. (2010) to include data from 17 additional North America basins that contain significant volumes of gas in UGRs.
PRISE Software. We improved the software developed by Martin et al. (2010) and added data from more basins in North America. The upgraded PRISE database includes evaluations of 25 North American basins, and is designed to assess the volume of gas in UGRs in frontier basins. PRISE works in conjunction with another program, BASIN, which can be used to find the North American basin most analogous to any frontier basin (Singh et al. 2008). BASIN and PRISE share a common database (Fig. 1). Once the analogous basin has been determined, PRISE uses the resource distribution of the analogous North American basin to infer the resource distribution of the frontier basin. PRISE and BASIN are components of a more general set of programs called the Unconventional Gas Advisor (UGA) (Fig. 1).
The Marcellus Shale, often referred to as "America's next super giant,?? has generated considerable interest in the Northeastern United States. Producers are leasing vast acreages, drillers are converging from across the nation, and service companies are mobilizing in force. Jobs are being created with local businesses benefitting from the increased activity associated with extracting shale gas. While technological advancements in horizontal drilling and hydraulic fracturing have allowed for a footprint significantly reduced from years gone by, and despite positive influxes of revenue, development of the Marcellus Shale in the Appalachian Basin is not without controversy. The speed at which the Marcellus is being developed, coupled with the lack of understanding by the public about a domestic fuel source long taken for granted, is creating a tension over how best to maximize the Marcellus Gold Rush while minimizing the negative impacts on the local environment.
The Marcellus Shale lies amidst some of the largest blocks of contiguous forests east of the Mississippi. More than 72 percent of the Susquehanna River Basin sits above the Marcellus. Consumptive water use to fracture a horizontal well can be in the millions of gallons. Unfamiliar chemicals are being transported and operations continue around the clock. There is no history of activity like this in the modern age in this region. Community groups have formed on both sides of the issues, while government agencies have ramped up their efforts to monitor extraction and consider the Marcellus as a new revenue stream for deficit-ridden state budgets.
This paper will address environmental concerns associated with Marcellus Shale development and explore positive solutions to mitigate local conflict and enhance cooperation. The exigency of addressing issues in the development of this new resource from an industry perspective as well as the local economic and environmental impacts will also be examined.
Previous study of unconventional tight gas plays in the Deep Basin area of the Western Canadian Sedimentary Basin identified a rapidly increasing volume of production and EUR developed in wells where production is commingled from multiple reservoirs in stacked plays. Historically, most Deep Basin wells were drilled for a primary target play - a single play strategy - and completed producing from a single play. However from 2007 to 2008, over 40% of the EUR connected in all Deep Basin plays was from multiplay producers. Extensive commingling to maximize the recovery per well and reductions in segregation and testing costs should improve well economics and increase total recovery. However, commingling multiple plays often obscures information important for resource characterization by play, such as: EUR per zone, individual zone productivity, producing success by play and well spacing by play.
Commingling is especially common in the Wild River region of the Deep Basin area, where up to eight potential plays may be stacked for completion. This paper will discuss the characteristics and distribution of commingled wells in the Wild River region. What is the impact of these multi-play wells in terms of activity, EUR connected and supply compared to single play wells? Where are the commingled play wells located? Which plays are targeted in terms of zones penetrated? Which plays are completed most frequently in these commingled wells? Is recovery per well improving with experience? Does recovery improve as more plays are completed? What is the overall success rate in this area? What is the density per section of Deep Basin producing wells? How do strategies and results vary by operator?
Based on the results observed in the Wild River region, the implications for resource estimates and development in other areas of the Deep Basin will be discussed.