Routine lab characterization of conventional cores is often limited to geology, petrophysics, and mineralogy. With unconventional plays, however, geochemistry and rock-mechanic are key parameters to characterize as well. In this paper, we present several innovative techniques which allow coping with challenges associated with lab characterization on unconventional core samples.
Such alternative techniques need addressing the following issues:
• Complex lab measurements, potentially to the threshold of what routine lab devices can characterize.
• Potentially high vertical variability of mineralogy and organic content.
Two innovative and worldwide unique measurement devices have then been developed in-house:
• A transient permeameter, the Step-Decay device, capable of measuring permeability down to the nanoDarcy, at different levels of confining stress and connate water content.
• A high-resolution geochemical core logging tool, the LIPS device (Laser Induced Pyrolysis System), designed to measure the organic matter content on a continuous centimeter scale basis.
We also combined existing techniques together, so as to cope with the variability issue:
• First, by systematically running a comprehensive set of high resolution core logs: CT-scan and spectral GR logs for petrophysics, scratch-test log for rock-mechanic, and LIPS log for organic matter quantification.
• Second, by coupling Micro X-ray fluorescence Spectrometry techniques for elemental characterization at 3 different scales, consisting of μ-XRF 1D-logging on whole core, then μ-XRF Spectrometry on thin section for 2D-elemental-mapping down to 25 μm resolution, last μ-XRF coupled with SEM for 2D-elemental-mapping at nanometer scale. This process of combining multiscale μ-XRF analysis is promising and opens the possibility of a classification scheme based on texture, potentially explaining permeability and rock-mechanic responses.
We present the analysis workflow applied to a gas-shale case-study, insisting on the challenges we faced and the way we coped with them. Benchmarking with alternative techniques and lab results is presented as well.
A multistage fracturing treatment was performed in two adjacent horizontal wells (Wells A and B) in the Chicontepec basin Mexico. A stimulation technique called “zipper fracturing” was planned and performed in these wells to create a high-density system of low-complexity planar fractures between laterals with the objective to maximize the contact area with the reservoir and therefore the stimulated reservoir volume (SRV).
The wells were drilled perpendicular to the expected fracture azimuth in the objective Pechi-B formation and completed as openhole laterals using a ball-and-sleeve completion strategy. Thirty-two fracturing stages (16 fractures per well) were selected based on an integral analysis of geological, petrophysical, and geomechanical disciplines. This zipper frac technique using a ball-and-sleeve completion was the first stimulation treatment of its kind in Mexico. The zipper frac technique fractures adjacent wells in sequence, enabling one well to hold fracture pressure while the adjacent well is being fractured. The fractures then avoid each other because of the stress pattern set up in the pressured well. The zipper frac technique also maximizes the exposure of new reservoir rock. The two adjacent horizontal wells were successfully stimulated in 108 hours of continuous work, pumping 95,000 bbl of fracturing fluid and 8.6 million pounds of ceramic proppant.
The stimulation technique reduced stimulation cycle time to just four days, and the initial production of the two wells was more than 8,320 bbl/day, which was more than ten times the average initial production in the area, becoming stable at 2,517 and 1,011 BOPD, respectively. For comparison, a typical well in the area, either vertical or deviated, produces 220 BOPD initially. This new completion technology was so successful than now the use is extending to other fields with horizontal wells.
1: Description of the material
This research shows how to obtain detailed knowledge of vertical and lateral distribution of reservoir properties in potential shale gas plays. This is achieved by combining data-sets on the regional to micro-scale in order to bridge current knowledge gaps. Shale characterization includes petrophysical (well logs), geophysical (seismic surveys, well tests), geological (outcrop, static modeling), geobiological (microfossil type, biofacies analysis), geomechanical (experiments and models) and microscopical techniques.
The presented workflow helps to understand changes in lithological and geomechanical properties, to get an increased insight in both fraccability and productivity of a target shale gas formation. It helps to locate shale-gas sweet spots and to predict mechanical reservoir behavior.
3: Results, Observations, and Conclusions
Shale characterization was performed on core- and well data of the Jurassic Posidonia Shale Formation (PSF) in the Netherlands and the time-equivalent Jet Rock Member of the Whitby Mudstone Formation (UK). Outcrop studies include a.o. characterization of natural fracture networks, Gamma Ray measurements and high-resolution (~10 cm) geochemical, sedimentological and geobiological sample analyses. Shale zonation can be based on multiple properties which are compared between the (English) outcrop- and (Dutch) borehole formations and which explain the petrohysical characteristics. The outcrop analogue allows to predict heterogeneity in subsurface data and will lead to better conceptual models of shales in the subsurface and how heterogeneity is expressed in conventional well logs.
4: Significance of subject matter
The proposed methods and techniques allow to better determine optimum reservoir conditions in relation to heterogeneity that eventually will lead to an improved understanding of design and scaling for stimulation treatments. As such, they will help in reducing the footprint of unconventional gas development through less wells and a higher percentage of successful stimulation activities.
Keshavarz, A. (The University of Adelaide) | Khanna, A. (The University of Adelaide) | Hughes, T. (The University of Adelaide) | Boniciolli, M. (The University of Adelaide) | Cooper, A. (The University of Adelaide) | Bedrikovetsky, P. (The University of Adelaide)
Injection of proppant particles of increasing size and decreasing concentration results in deeper percolation of proppant into the natural fracture system, expansion of the stimulated reservoir area and the enhancement of the well productivity index. The proposed graded proppant injection technology can be used for productivity enhancement of coal seam gas wells and other unconventional resources, for i.e., shales, tight gas and geothermal reservoirs.
A mathematical model was derived to describe proppant particle trajectory and optimum proppant placement in order to increase productivity/injectivity indexes. Computational fluid dynamics has been used to determine the hydraulic resistance due to proppant plugging of the fractured system. The model can predict proppant particle trajectory in naturally fractured system based on a force balance involving gravity, Stokes and Saffman lifting forces. The trajectory is calculated by exact solution of ordinary differential equations. An optimal injection schedule, i.e., the timely dependence of the injected proppant size, density and concentration, has been developed in order to avoid fracture closure during production stage and also to provide minimum hydraulic resistance in the system of fractures plugged by the proppant particles.
The analytical model shows that the productivity/injectivity indexes are very sensitive to the injection schedule, initial fracture aperture and permeability. Hence, proper selection of proppant density, size distribution and injection schedule can strongly increase well productivity.
Unconventional plays call for unconventional technologies. This paper will discuss the application of electric line, tractor conveyed, technologies and their environmental advantages in operations with limited space or sensitive areas calling for small footprint solutions. A world’s first operation will be used to illustrate the applicability of the technologies deployed from a remote island on Alaska’s North Slope, where electric submersible pumps (ESPs) were changed out on three wells using e-line. Reported are the lessons learned from the operations as well as the potential for application on a broader scale, including unconventional plays like HT/HP well environments. The operational challenge was to transform a traditionally rig-based intervention into a lightweight operation, as the field was located on a remote island with no coiled tubing unit available. ESP failures prompted the operator to retrieve and change out the pumps. First a clean-out run was completed to ensure no debris would be affecting the swap out. The various components were pulled in sequence. When all parts of the ESP had been retrieved to surface, a new ESP was successfully installed by reversing the order of the previous runs. For the first time in the industry, ESPs were changed out using electric line. During the operation over 100,000 ft. were tractored in a highly deviated well (up to 86°). Based on the results of the first ESP swap, the operator decided to perform ESP change-outs on two additional wells. When integrating the lessons learnt from the first job, it was possible to successfully complete the second job with twice the efficiency. This operation demonstrated the broad application of electric line intervention tools eliminating the need to mobilize a rig or coiled tubing, which carries specific importance for remote locations, where logistics may prohibit the mobilization of large and heavy equipment.
Europe is on the cusp of an expansion in unconventional resources development and many analysts are turning to Australia and North America to learn lessons from markets at different stages of the development curve. Most attention has been focussed on similarities and differences in geology, service industry and labour costs whilst consideration of environmental stewardship has been dominated by concerns over the potential environmental impacts of hydraulic fracturing. Issues related to local water security and land conflict have, in contrast, received far less attention.
To address these issues, the authors take alternative fresh look at the European market, using experiences in North America and Australia to consider how and why land and water disputes have increasingly constrained gas production.
In North America, the unprecedented boom in shale gas production has, in a limited number of cases, occurred at the detriment of environmental stewardship. These instances have supported the rise of a strong anti-lobby group whose calls for more stringent regulation and moratoria are increasingly heeded by state governments. In Australia, the absence of an accepted environmental baseline has resulted in fragile and frequently changing regulation that has increased industry costs and fuelled investor uncertainty. Furthermore, whilst coal seam gas water has the potential to act as a valuable water source in water scarce regions, conflicts with the long-standing agricultural industry, worries over aquifer and surface water contamination and concerns over legacy liabilities are increasing.
Drawing lessons from these examples and others, the authors conclude by identifying three initiatives essential to the emergence of a viable and sustainably sound European market. Crucially, these initiatives require government and industry collaboration, underpinned by academic support through the dissemination of objective science. Failure to support these initiatives could stifle projects, breed uncertainty, promote conflict with existing industries and the public, and ultimately discourage investment.
This paper discusses a hydraulic fracturing treatment on a tight gas well operated by a major Oil and Gas organization in India. The objective was to perform a hydraulic fracturing treatment on an uncased open hole section to assess the potential of the barefoot section by creating at least two to three separate independent fractures. A successful treatment would unlock potential oil and gas reserves in this area of the country, which has huge estimated reserves.
This tight gas reservoir fracturing treatment was to be performed under these conditions for the first time in the area, and hence there was no prior information to predict the result of the job. Injectivity and mini-frac tests were performed to analyze the reservoir properties before designing the final fracturing treatment and execution plan.
One of the major challenges was to perform the fracturing treatment in an uncased open ole section under strenuous operational deadlines which eliminated the options of using previously proven completion method. Hence, it was proposed to employ a diverting agent in the fracturing treatment to maximize the stimulated reservoir volume. The challenge was to manage the pumping rates and deliver the diverter accurately bottomhole.
In addition to the details given above, the following issues had to be addressed as well for the main fracturing job. Heavy mud in the wellbore and open hole section which had to be cleaned out, low perm reservoir, customer’s wellhead tree pressure rating, deep well, long open hole interval, extremely short operational execution deadline, and close proximity of an adjacent well leading to possible communication between the wells.
This paper reviews the fracturing analysis performed to design the fracturing treatment, the ideologies employed in performing the successful fracturing treatment using new diverter technology and the results achieved with this technique.
Shale has certain characteristic features that make it difficult to evaluate in a traditional laboratory setting. The unique characteristics of shale formations include low permeability, existence of microfractures, and sensitivity to contacting fluids. Advances in testing of shale remain relatively stagnant: Current shale fracturing practices and technology are mainly based on simulation models and extension of experience from conventional formations. The objective of this study is to develop an experimental setup to measure the hydraulic breakdown pressure for fractures in shale cores, and to use this setup to study the effect of different parameters (fluid types and characteristics, injection rate, shale bedding, acid injection, and different additives for different systems) on the breakdown pressure, fracture shape, and fracture direction.
Shale cores from the Eagle Ford, Marcellus and Mancos, were evaluated in this study. Based on experimental results, breakdown pressures in shale formations have strong exponential relationship with the fluid viscosity, where increasing fluid viscosity increased the breakdown pressure. A linear relationship was observed between injection rate of fracture fluids and breakdown pressure. Additionally, a relationship between closure stress and breakdown pressure has been experimentally established and verified with existing mathematical model: Closure stress increases the breakdown pressure by a factor of 2.8.
Even for shale with low HCl solubility (less than 2 wt%), the breakdown pressure of shale formations was reduced by injecting HCl acid, with further increase of the HCl acid contact time reducing the breakdown pressure more. Also, additives that improve the flow of fracturing fluid in microfractures tend to reduce the breakdown pressure and enhance fracture complexity. Finally, factors determining the fracture complexity have been identified, allowing enhanced complexity by optimizing fluid characteristics and treatment design. All of the above relationships and more experimental results will be detailed in the paper.
At present, multistage hydraulic fracturing of horizontal wells has become a widely used technology in stimulating tight oil reservoirs. However, the treatment of hydraulic fractures in numerical simulation of multi-fractured horizontal wells in tight oil is excessively ideal. Effects of some fracture properties on numerical simulation of tight oil are usually not taken into consideration. Actually, fracture geometry in the reservoir is complex and fracture permeability is not a constant value. Numerical model without these factors may lead to a significant error in forecasting the reservoir response. In this paper, to make the result more reasonable and credible, based on an actual block of Imperial Oil Ltd in Cardium pool that is a tight oil reservoir of Pembina field, AB, Canada, geo-model is constructed at first with accurate description of the reservoir according to geology, physical properties and so on. In numerical reservoir model, in terms of micro-seismic data and relationship between fracture permeability and effective stress from experiment data, dynamic fracture permeability and fracture geometry are taken in considerations. And the history-matched reservoir model is then used to understand the development of multi-fractured horizontal wells in tight oil. Using field reference data and history-matched reservoir model, different scenarios including waterflooding and depleting development have been simulated. We also simulate similar scenarios without these factors. Results indicate that the effect of geometry and property of hydraulic fractures may be significant and cannot be neglected. The results in the model including these factors are different significantly from that without these factors. Especially, the difference is more evident in waterflooding development. And the results in the model with fracture geometry and dynamic fracture permeability are more suitable to the actual production of multi-fractured horizontal wells. The results proposed in this paper can act as a reference to optimize development of tight oil.
Ai, C. (Northeast Petroleum University) | Hu, C. (Northeast Petroleum University) | Li, Y. (Northeast Petroleum University) | Yu, L. (Northeast Petroleum University) | Zhang, Y. (No.3 Production Plant of Daqing Oilfield Company) | Wang, F. (Northeast Petroleum University)
Lots of cleats, fractures and other weak structures have developed in coal reservoirs, and as a result, there are relatively big difference between its mechanical properties and coal matrix. During the drilling process, the cleats and fractures near the sidewall are more prone to surfer damage than coal matrix under the ground stress, crack stress, fluid pressure and borehole fluid additional stress, and thus destabilizing phenomena such as borehole collapse and circulation loss would take place. This paper used elasticity and fracture mechanics theories, and took the time effect of sidewall rock drilling fluid seepage into consideration to deduct stress intensity factor I and II at the cleat tip under the action of the fluid-solid coupling, to establish criterion for the failure condition of coal matrix and cleat fractures, and to establish the wellbore stability calculation model for the cleat-featured coal body. Applying the model can calculate the safe drilling fluid density during the drilling process in cleat-featured coal seam, get the influence law of the factors which affect the wellbore stability such as the length of cleats, horizontal inclination and opening time of borehole, etc, and it also can analyze the time-delay effect of wellbore destabilization during the drilling process in cleat-featured coal seam. The study achievement was the supplement and perfection of the existed estimation model for the wellbore stability of coal seam gas well.