SPE/EAGE European Unconventional Resources Conference and Exhibition

Based on large number of shale gas exploration and development literature research, this paper describe the characteristics, accumulation regularity, adsorption and desorption properties of shale gas which are different from conventional gas reservoir. Langmuir isotherm law and Fick diffusion law are used to established the desorption gas steady diffusion rate expression. Three research works have been done, first, established the production formula of fractured horizontal well based on the model of Genliang Guo rectangle fractured horizontal flow, fracture angle and desorption gas steady diffusion rate are employed to improve the production formula. Second, interact of fractures and desorption are considered, equivalent filtrational resistance is used to establish a capsule model of shale gas steady flow, a new production formula of fractured horizontal well in shale gas reservoir has been derived by the new flow model. At last, rationality of the two formulas has been proved by the calculation of programing based on the field data. Analysised the production influence of formation parameter, horizontal well drilling factors, fracturing effect and desorption gas steady diffusion rate.The production formula of fractured horizontal well in shale gas reservoir and the research of production influence can be used in productivity prediction of later period shale gas reservoir fractured horizontal development. It can also interpret the parameters selection of drilling and hydrofracture more accurately for shale gas reservoir. Optimization design of shale gas reservoir development mode can be improved by the production formula and effect factors research. Desorption gas steady diffusion rate computational method provided us with deeper research about years of stable production, proration, reasonable production system in shale gas reservoir development and how desorption affect production of fractured horizontal shale gas wells.

The exploration of shale gas resources in Europe is moving at a slow pace, despite the fact that drilling for reservoir characterization is essential for any further planning. Whether shale gas development in certain regions is economically feasible at all and what such development activities might entail can’t be determined in the absence of critical data. Yet, there is widespread public resistance that influences political decision making and permitting, and that sometimes doesn’t even allow for exploration. Most of the stakeholders concerns are related to perceived environmental risks for water resources as a result of hydraulic fracturing. The main themes are concerns about the contamination of water bodies by fracturing chemicals, methane or flowback water, or concerns about the depletion of groundwater and surface water.

While some of those perceived risks may be overestimated or unsubstantiated, there are real risks that have to be addressed by thorough assessments of the environmental, health and social impacts, and by an integrated approach to water management from sourcing to final disposal. This includes the transportation and distribution logistics for water and wastewater movements. It is essential to establish relevant reference and baseline data on groundwater and surface water systems well ahead of project implementation, to assess risks in a fashion that is understood by interested stakeholders, to define proactive and reactive resource protection measures, and to monitor performance.

This paper suggests an integrated approach to water management that combines the elements of impact assessments, scientific and technical data gathering, and the monitoring of potential impacts across the life cycle of a shale gas project, as well as sourcing, transportation and disposal strategies. All results and measures taken need to be communicated and documented in a clear and transparent manner.

Gas hydrates will dissociate to gas and water at pressures below the equilibrium pressure or temperatures above the equilibrium temperature. Moreover, some hydrate reservoirs have considerable amounts of mobile gas and water coexisting with the hydrates in the formation. This implies, fluid diffusivity in such reservoirs is predominantly multiphase and hence addressing multiphase flow in such reservoirs becomes very vital.

Conventionally, most well testing models address diffusivity in porous media by assuming a single/dominant flowing phase or addressing the fluid phases separately. If a huge discrepancy exists between the fluid saturations, the fluid with the highest saturation could denote the dominant flowing phase, depending on the fraction flow model, and the correction with the multiphase model becomes trivial, as also seen with most conventional gas reservoirs with low water saturation. However, if the saturations of the different phases do not vastly differ from one another, multiphase well testing models give a more accurate prediction of reservoir behavior. The definition of the multiphase dimensionless time becomes very essential in predicting the diffusivity of the fluids and for well test designs.

The multiphase flow models developed here are based on mass balance and volumetric material balance approaches. The total mobility is derived for both the mass balance and volumetric material balance models, further related to fraction flow models. The total mobility model developed by Perrine, used by most reservoir engineering calculations is not addressed in detail for this work, as this does not fulfill mass conservation considered in this paper. Due to the non-linearity of the diffusivity equation, the multiphase diffusivity model addressed here includes pseudo-pressure and pseudo-time integrals. The solutions to the diffusivity equations for multiphase flow are given for both approaches. The differences between both models and their limitations are addressed and highlighted with illustrative examples.

In this case study we outline how microseismic analysis can be used to optimize treatment design and determine the portion of the stimulated rock volume that should be productive. To begin, microseismic data was acquired with a permanently installed shallow buried array of geophones during the hydraulic fracturing of 17 wells in the Marcellus Shale. The processed results were used to conduct a multi-disciplinary study integrating geology, geomechanics, reservoir and completion engineering, and ultimately, production data. A stress inversion from focal mechanisms was performed, and correlations were made between hydrocarbon production and microseismic results. That work, in conjunction with the variability in the stimulation approach, was used to optimize the treatment design on an individual wellbore and on a field development scale. Treatment design analysis indicated optimum wellbore spacing, stage spacing and length as well as evaluated the vertical coverage of the treatment within the Marcellus. Incorporating information from source mechanisms, an event magnitude calibrated discrete fracture network (DFN) was modeled taking into account the seismic energy of the events, rock properties, the injected fluid volume and efficiency. Evaluating the placement of proppant inside the DFN enables distinction between the part of the stimulated rock volume (SRV) that contributes to production in the long term, and the part of the reservoir that was affected by the treatment but may not be hydraulically connected over a longer period of time. Finally, the permeability of the stimulated fracture system was calculated from the microseismic results. This allows for the evaluation of the drainage volume and estimation of production.

This paper discusses the hydraulic fracturing (HF) treatment of a tight gas well owned by a major power service company in India. The objective was to perform a HF treatment on the openhole (OH) section to assess the reservoir potential for future development work. The success of this treatment could unlock the oil and gas reserves in this area of the country, which are estimated to be massive.

The fracturing treatment of the tight gas reservoir was to be performed under these conditions for the first time in the area, so there was no previous information to help design the treatment nor predict the result. Injectivity and mini-frac tests were performed to analyze the reservoir properties before designing the final fracturing design and execution.

One of the major challenges was to perform the fracturing treatment on an OH section under extremely strenuous operational deadlines, which eliminated the options of using any more suitable well completion methods. Thus, it was proposed to use a diverting agent in the fracturing treatment design to help maximize the stimulated reservoir volume (SRV) in the OH section. The objective was to create at least two to three multiple independent fractures in the OH section. The challenge was to manage the injection rates and deliver the diverter accurately to the bottomhole to create a bridge at the open fracture, isolate it, and initiate a new fracture. This paper discusses this process, and the the lessons learned during the treatment execution.

In addition to the description above, the following issues had to be addressed before progressing to the primary fracturing treatment: heavy mud was in the wellbore and OH section, this was a low-permeability reservoir, operator’s Christmas tree pressure rating was low, this was a deep well with a long OH interval, there was an extremely short operational execution deadline, and this well’s close proximity to an adjacent well, leading to possible communication between the wells.

This paper discusses the fracturing analyses performed to design the fracturing treatment, the ideologies used for performing the successful fracturing treatment using diverter technology, and the results achieved using this technique.

A successful evaluation and development program in oil- and gas-bearing shales requires considerable analysis and investment, not to mention optimization to help ensure a profitable outcome. Accelerating optimization, reducing capital expenditures, and improving lifecycle net present value (NPV) for the asset are reasonable goals. Seven shale properties are key drivers to help achieve successful play economics. However, the heterogeneity of shales makes well location selection difficult without appraisal well logs and geostatistical mapping of shale property quality. The analysis method allows operators to quickly high-grade areas within a large, heterogeneous shale play using logging suites from a limited number of wellbores in the play. Further, the methodology has been extended to quantify the play’s potential reward versus risk distribution for in-fill drilling investments. This study extends the method to optimizing lateral lengths of horizontal wells. Geostatistics provides a means to determine correlation lengths of aggregate shale properties known to be critical to successful economics. The correlation length is used to determine the appropriate length of the horizontal well lateral, restricting it within the highest rock quality for stimulation effectiveness and production rates. Because optimal lateral lengths can be predicted using this approach, it is now possible to pinpoint the best wellhead location, the best landing point for the horizontal portion of the well, and set the optimal length of the lateral. This reduces the drilling of unproductive lateral lengths and targets stimulations. By shortening the “trial-and-error” evaluation lifecycle stage using this methodology, an operator can develop an asset more quickly and at less cost than with previous approaches.

Electric wireline and tractor equipment were chosen to perform through-tubing electric submersible pump change-outs in a remote location with limited access and equipment availability. Electric wireline was available on location where other rigless options such as coiled tubing could not be mobilized. This paper records the retrieval of through-tubing-conveyed electric submersible pumps (TTC ESPs) from three wells and their replacement in two of these wells using a highly adaptable tool string. The application of an existing tool implemented in a novel manner provided benefits to the operator and has potential applications for other operators maintaining through-tubing-conveyed ESPs in deviated wells. The pump assemblies were removed through tubing while the permanently installed equipment, such as seal, motor and cable, remained in situ. All wells contained three individual assemblies to be retrieved including a tubing stop, tubing packoff with check valve and knock-out pressure relief valve, and the pump assembly. The assemblies were re-installed in two wells and the wells placed back in production. The method described herein confirms electric wireline and tractor equipment as a viable alternative for rigless replacement of through-tubing electric submersible pumps.

Optimizing operational efficiencies in unconventional resource developments is one of the key success drivers for improved economics. In this work, an approach for exactly that problem is presented, designed for a field development scenario in Germany. Starting with a model that captures all key parameters which are influencing a development program such as the gas market and prize scenarios, political situation, environmental regulations, logistical requirements, etc., it immediately turns out that the highly complex model has to be significantly simplified and a sub-model with clear and precise boundary conditions has to be generated. This sub-model is tuned to problems of particular interest, considering technological parameters such as the impact of various state of the art drilling technologies or different fracturing methodologies on the entire development program. It is possible to identify interrelations of various procedures and allows estimating project costs. Operational scenarios can also efficiently be tested, and validated and the financial key parameters of different scenarios can be compared. Moreover, short- and long-term benefits and drawbacks of various solutions can be assessed and optimized. Also, limitations of System Dynamics for that kind of simulation are pointed out, and it is shown how to solve the problem with an Agent Based Modeling approach.

Interest in European Coal Bed Methane (CBM), driven by an increasing demand for supplies of natural gas in Europe has been ongoing since the 1990’s in the UK, Belgium, Germany, France and Poland.

The nature of Carboniferous age European coals: multiple, thinner coal seams with lower permeability than coals seen in Australia or North America has resulted in a horizontal well or multi lateral wellbore architecture employing geosteering through the coal seams. Use of a conventional directional drilling Bottom Hole Assembly (BHA) in which the Logging While Drilling (LWD) sensors are usually 40ft or more from the drill bit, makes geosteering in structurally complex coals, with changing dip and rolling topography a major challenge. The cost sensitive nature of CBM wells makes the use of geosteering tools such as azimuthal resistivity tools uneconomic.

This paper describes the experience of Dart Energy and its heritage company, Composite Energy, in introducing an instrumented mud motor with a near bit Azimuthal Gamma Ray and Inclination tool as a cost effective geosteering aid on the Airth CBM Field in Central Scotland. The use of an instrumented mud motor enabled Dart Energy to improve geosteering performance, increasing net coal in each geosteered section, near doubling of average Rate Of Penetration (ROP), and reducing the number of time consuming and costly sidetracks.

The improvement in geosteering is a critical part of realising the commerciality of CBM wells producing from thinner, structurally complex Carboniferous age coals found in the UK and Northern Europe.

New sponge coring service and technology have been introduced to the oil and gas industry. Admittedly sponge coring has been an industry offering in some form for over twenty years but until now it has been plagued by chronic problems. The objective of sponge coring was to determine separate in-situ oil and water saturations of the formation materials. The problem with conventional coring has always been that the fluids would be expelled and lost from the core by the expanding gas while bringing it to the surface. The long-time solution was to surround the core with a special oil-absorptive (oleophilic) sponge material that would capture the expelled oil and hold it in place for laboratory analysis. The challenge was to fit the sponge tightly enough around the core to prevent fluid migration and mud contamination in the sponge-core clearance annulus, and yet avoid core jamming and sponge damage.

This new, more accurate sponge liner coring service is now in place, showing excellent results. A balance seems to have been achieved between smooth core entry and a properly fitting, pre-saturated sponge with virtually no fluid migration. This new service cuts and provides oil-absorptive sponge-encased 3½-in. diameter core in 30 ft lengths with a maximum downhole temperature and pressure of 195°F (90° C) and 15,000 psi (1,034 bar) respectively. Special vacuum pump service equipment and sealing system are utilized to pre-saturate the sponge liner with brine.

In late 2012 a major operator utilized this new and previously unproven system to core nearly 300 ft of sponge core in New Mexico, USA. The coring program used a special low-invasion coring fluid with a low spurt loss and a staged trip-out-of-the-hole schedule to minimize gas expansion/oil movement. The precision core bit that cut a tight-clearance core provided exceptional results with an average rate of penetration (ROP) of 10.4 ft/hr, with 97% core recovery and observable oil saturation in the sponge, indicating the system worked as designed. This case study will be described in detail within this paper.