wang, Jiandong (CNPC Tubular Goods Research Institute) | rao, Xiaodong (CNPC Chuanqing Drilling Engineering Company) | han, Lihong (CNPC Tubular Goods Research Institute) | li, Yufei (Petrochina Southwest Oil and Gas Field Company) | zhou, lang (Petrochina Southwest Oil and Gas Field Company) | lu, Xiaoqing (Tianjin Seamless Steel Tube and pipe Co.,Ltd.)
The fracture interventions were operated in 144 segments of 24 wells in CNPC Changning and Weiyuan shale gas fields. Among these fracture interventions, 10 wells happened different degree of casing deformations, and one well had casing connection jump-out. So the casing failure rate reached 45.8%. The casing failure modes included casing deformations in reservoir fracturing sections which occurred following hydraulic fracturing, blockage during drifting and bridge plug process, casing connection jump-out, and annulus pressure buildup between casing and tubing during well shut-in. A comparative study was performed on the geological conditions, well completions, and fracturing pressure for the shale gas fields between China and North America. The study shows significant challenges for shale gas exploration in China, with severe conditions such as high reservoir temperature at 150 °C, high gas pressure at 60MPa, and discontinued in-situ stress in the faults where the maximum horizontal stress is significantly higher than the overburden pressure and the minimum horizontal stress. Standard T&C connections were used for casing strings. Based on analysis of casing installation, fracturing and production process, it was concluded that the conventional tubular design approach could not be applicable for the shale gas applications in China. The primary cause for local casing deformation can be related to the formation shear loading, resulting from multi-layer fracturing process. Casing joint used premium connection of gas-seal. API Spec 5CT (2010) material transverse impact toughness couldn't meet fracturing needs in practice. Coupling often cracks and then jumps out. This paper presents Finite Element Analysis (FEA) of casing strings subjected to shear loading and transverse impact toughness of resistance to crack initiation on fracturing. Based on the FEA study, the performance requirements and evaluation criteria for shale gas production casing were developed. This paper also presents an example where the proposed methodology was used to analyze and evaluate casing performance, and ensure the safety of the well operation.
Exploration and development of coalbed methane (CBM) reservoirs is ongoing in the Asia Pacific region, with low permeability, undersaturated coals being the target in some areas. Horizontal wells are typically required to produce low permeability CBM reservoirs at commercial rates, and may experience a period of single-phase (water) transient flow, followed by a transition to two-phase (water+gas) transient flow. Wells exhibiting this behavior are particularly difficult to model analytically, yet simple analytical and semi-analytical tools are desirable for making quick, but reasonably accurate forecasts. The purpose of this work is to therefore provide a new forecasting methodology for low permeability, undersaturated CBM wells.
The new method for forecasting CBM wells introduced in this work is based on the concept of a dynamic drainage area (DDA), recently adapted to forecast tight black oil and gas condensate wells exhibiting two-phase flow. A critical advancement provided in the current work is modeling the transition from single-phase flow of water to two-phase flow of gas and water during the transient linear flow period, which was not attempted for the black oil/gas condensate cases. Above desorption pressure, material balance, performed on the dynamic drainage area to determine average pressure in the distance of investigation, is combined with the linear flow productivity index equation to forecast water production at each time step. For two-phase flow below desorption pressure, the two-phase version of the linear productivity equation and material balance equations for water and gas are solved iteratively for pressure, saturation and fluid production rate within the DDA. The gas material balance equation accounts for desorption effects. In order to calculate the DDA at each time step, the linear flow distance of investigation equation is used. Importantly, using the DDA method, variable operating conditions (flowing pressures) may be accounted for, which is critical for CBM wells during early stages of production.
The new semi-analytical DDA model is used to history-match production data from an actual horizontal well completed in a low permeability, undersaturated, western Canadian CBM reservoir. Further, the match is compared to that obtained from rigorous numerical simulation. The history-match of the field data is reasonable with the new model and comparable to numerical simulation. The new model is however easier to setup and less data-intensive than numerical simulation, providing a practical alternative to CBM reservoir engineers who are responsible for generating a large number of forecasts.
In this time of uncertainty within the industry, operators are under increasing pressure to reduce cost and increase operating efficiency. The cost in both time and resources for hydraulically stimulating a well is a substantial part of the total expenses for the well and the economic success of the investment, as most formations being drilled presently in North America (NA) are incapable of economic returns without multi-stage hydraulic fracturing. Coil tubing (CT) deployed hydra-jet perforated pinpoint stimulation methods both aim to improve the success of hydraulic fracturing treatments and deliver increased versatility in terms of the treatment design of the well. This is achieved by specifically targeting each section of the well with a customized treatment plan and fracture placement to optimize the formation return. This paper presents a summary of various pinpoint stimulation technologies and methods. An economic comparison to a traditional plug-and-perf stimulation is provided based on total treatment time, hydraulic horsepower (HHP) requirements, and percentage of treatment time spent in fracturing, perforating, setting plugs, drilling out plugs, and other necessary activities. Using these metrics, each of the pinpoint stimulation methods outperformed the plug-and-perf operation, with the addition of a reduced capital expense for equipment on location, reduced wear on tubular and tools in the wellbore, and the elimination of the cost, international importation challenges, and health, safety, and environment (HSE) risks with explosive shape charge perforation guns.
Unconventional oil reservoirs have taken a prominent role in the United States as a source of crude oil. Different methodologies to estimate reserves for shale gas and coal bed methane have, thus far, proved to be reliable, but no simple yet accurate workflow has been generally accepted to forecast production and estimate reserves for shale oil. To fill this gap in technology, we proposed and validated a workflow that integrates analytical methods with empirical methods. The final methodology is both easily applied and accurate. In developing the final workflow, we evaluated several alternatives, most of which proved to be unsuitable. We also investigated the use of a filter to eliminate outliers in a systematic way, as proposed by
The workflow was successfully applied to three of four volatile oil wells in the Eagle Ford shale, with similar results. The analytical model that best matched the wells is called the Stimulated Reservoir Volume (SRV) Bounded Model. We tested this and other models using a new field production analysis tool software. While accurate, this modeling approach is too time consuming for routine use. We found that a simple empirical approach that led to the same results as the analytical model was a 3-segment Arps decline model. The early flow regime was transient linear for all the wells; thus an Arps "
The unconventional revolution in North America has attracted large investments from national oil companies (NOCs) and international oil companies (IOCs) eager to gain knowledge and add profitable unconventional resources to their asset portfolios. A key element of realizing this goal is the rapid and effective development of in-house technical personnel to support the effort. In 2008, a major NOC in Asia began its unconventional quest with an initial entry into a coal seam gas (CSG) opportunity in Australia, followed by investments in shale gas plays in the prolific Canadian North Montney area. To develop the much needed in-house capability, the NOC partnered with a major service provider to develop and deliver training programs to prepare its geoscientists and engineers to work within the unconventional division.
Previous efforts by the NOC to develop in-house unconventional capabilities were hampered by a lack of data specific to their joint-venture shale assets. The newly established Unconventional Division had recently acquired an interest in Canadian Unconventional assets, and challenged the joint team to design a capability development program that would utilize this data, deliver practical experience, and build critical staff knowledge, in less than 6 months. The NOC agreed to provide data from their Canadian asset to enable the development of an accelerated, immersive program.
The redesigned 10-week program used a source rock reservoir development workflow that incorporated a geoscience and engineering software suite to enable participants to review the field data and evaluate optimization opportunities. The goal-oriented tasks were to evaluate the project areas and develop the in-place gas resource to reach plateau production.
The program was conducted entirely in Kuala Lumpur at the service provider's offices between September 8 and November 20, 2014, with development plan results presented to the NOC's management in Kuala Lumpur and Calgary. This paper presents the program development, challenges encountered through the preparation and deployment, final outcomes, and lessons learned.
The measurement of gas content of coals has been dominated by the standard methods of core desorption described by ASTM D7569 and
The current practise of measuring isotherms is also questioned, particularly with respect to mixed gas types where the extended Langmuir or IAS models are found wanting.
To overcome these deficiencies the process of measuring gas contents to known partial pressures of seam gas is used. So too is the process of measuring native isotherms on initial desorption of core. This is extended to the measurement of laboratory isotherms at reduced pressures.
The results of isotherm testing indicate that the native isotherms are generally not the same as isotherms derived from laboratory testing though they are more similar where the seam gas is of a single composition. By undertaking isotherm tests to lowered pressures we can see that there are shortcomings in the Langmuir equation and that gas storage at lowered pressures may vary substantially from this model. The measurement of gas content by conventional desorption needs to be measured to a known partial pressure and this needs in turn to be related to the isotherm.
This paper uses some basic science to produce better solutions to gas content analysis. Along with these developments comes the analysis of desorption of a sample and how this relates to the diffusion coefficient and core fracturing. This leads in turn to an improved process to determine the lost gas on core retrieval for coals and shales.
Mahoney, Shilo A. (The University of Queensland, St Lucia Australia) | Rufford, Thomas E. (The University of Queensland, St Lucia Australia) | Dmyterko, Anastasia S. K. (The University of Queensland, St Lucia Australia) | Rudolph, Victor (The University of Queensland, St Lucia Australia) | Steel, Karen M. (The University of Queensland, St Lucia Australia)
We report the effect of rank and lithotype on the wettability of artificial cleat channels in five coals from the Bowen Basin with ranks in the Rmax% range 0.98-1.91%. Wettability was assessed by measuring contact angles of air and water in the artificial cleats using a microfluidic Cleat Flow Cell (CFC) instrument. The artificial cleats were produced by reactive ion etching and had widths in the range 20–40 µm that replicate the width and shape of some natural coal cleats under sub-surface reservoir conditions. These model cleats were developed to allow systematic laboratory investigations of water and gas relative permeability behaviour.
Imbibition and drainage experiments were performed in the artificial channels using air and 0.1 %wt. fluorescein in fresh tap water to observe contact angles, the entry pressure of the air-water and water-air interface to the channel, and the pressure at which the channel was filled by the displacing fluid. Relative contact angles on the coal surface of 110 -140° were determined from images collected in the imbibition experiments. A trend of increasing contact angle with coal rank was observed. The low rank coal exhibited smaller contact angles and lower breakthrough pressures than the higher rank coal samples. In the drainage experiments the injection air displaced the water but left a residual liquid film on cleat walls across dull, inertinite rich bands. This residual film was not observed in the bright, vitrinite rich bands. The results of this study may provide the basis to consider an improved relative permeability model that explicitly accounts for wettability and the effect of coal rank.
The Australia Pacific LNG Project is scheduled to come online in 2015 and consists of the extensive development of substantial coal seam gas resources across the Surat Basin. A variety of unique and complex challenges are presented when undertaking the geological and dynamic modelling and performance prediction of the laterally discontinuous and thin coal seams within the Walloons package. These challenges require a targeted approach and evolving solutions.
Specific challenges that have been assessed and addressed in the characterisation and modelling workflow of the complex Walloons coal seams include:
Complex coal packages exhibiting thin coal seams with high degrees of lateral and vertical heterogeneity Appropriate prediction of uncertainty Coal body distribution and connectivity Application of learning from fine scale sector modelling to larger regional coarse scale models Significant reservoir dynamics across large distances within Surat acreage Production performance variation over time resulting from stress impacting the matrix Vast scale of the Surat Walloons development combined with fast-cycle decision making Adopting appropriate and unique workflows for regions of different production maturity
Complex coal packages exhibiting thin coal seams with high degrees of lateral and vertical heterogeneity
Appropriate prediction of uncertainty
Coal body distribution and connectivity
Application of learning from fine scale sector modelling to larger regional coarse scale models
Significant reservoir dynamics across large distances within Surat acreage
Production performance variation over time resulting from stress impacting the matrix
Vast scale of the Surat Walloons development combined with fast-cycle decision making
Adopting appropriate and unique workflows for regions of different production maturity
The developed workflow addresses coal seam gas modelling challenges both within the history matching phase and in the subsequent probabilistic forecasting. The workflow identifies uncertain reservoir properties and their expected maximum ranges based on available data and previous studies. An uncertainty analysis is conducted with statistical approaches including Tornado Chart and Latin Hypercube (LHC) to identify the most influential reservoir parameters and fine-tune their ranges in order to optimize the probabilistic history matching process. Subsequently, assisted history matching and optimisation techniques follow a stochastic algorithm of experiments to reduce the mismatch and create convergence with the production history. A number of representative, non-unique history matched models are identified which satisfy matching criteria and capture the uncertainty of the subsurface.
The selected acceptable history matched models, together with forecasting parameters and their ranges, including operational variables, are used in forecasting. Random sampling of uncertainties by LHC is used with assisted history matched cases resulting in thousands of forecasts based on which P10-P50-P90 probabilistic forecasts are selected.
This paper presents solutions to address uncertainty, assisted history matching and performance prediction of the Walloons coal measures for rigorous forecasting, and incorporation of learnings from localized fine scale models into larger coarse scale modelling for time efficient, regional performance prediction.
Chen, Yulin (St. Key Lab. O&G Geo & Exp. Eng., Southwest Petroleum University) | Zhang, Liehui (St. Key Lab. O&G Geo & Exp. Eng., Southwest Petroleum University) | Li, Jianchao (St. Key Lab. O&G Geo & Exp. Eng., Southwest Petroleum University)
Pore structure of gas shale which possesses lots of nanopores is complex. NMR measurement can not only obtain accurate sample parameters but also provide an approach to quantitatively study pore structure. This paper Integrates NMR, mercury injection, nitrogen adsorption and X-ray diffraction to analyze the relationships of pore structure, surface to volume ratio and mineral components.
Both nitrogen adsorption and mercury-injection have some limitations in characterizating of pore structure of gas shale. In this paper we integrate pore size distribution curve of nitrogen adsorption and mercury-injection. Comparison and analyses of NMR T2 spectra and the integrated pore size distribution curve calculate NMR pore size distribution. Capillary pressure curve is constructed based on NMR T2 spectra for quantitatively studying pore structure of gas shale. The diagrams of relationship between characteristic parameters of pore structure, surface to volume ratio and mineral components such as clay minerals, pyrite and TOC are established.
NMR study has been implemented on 15 samples from Longmaxi formation. The results show the porosity range from 2.24% to 5.76%. The NMR pore size distribution curves is more precise than the curves that calculated only according to nitrogen adsorption or mercury-injection. Calculating separation coefficient, skewness, structure coefficient, median pressure and other parameters from constructed capillary pressure curves indicate high threshold pressure, poor connectivity, and complex pore size distribution. Porosity has a positive correlation with clay mineral content, TOC, pyrite. Most of surface to volume ratio and pore volume are provided by micropores and mesopores.
Using integration pore size distribution curve of nitrogen adsorption and mercury-injection to calculate parameter of NMR pore size distribution is a more exact approach than only using nitrogen adsorption or mercury-injection. Capillary pressure curve constructed by NMR T2 spectra can provide information of micropores and mesopores which mercury-injection cannot correctly characterize.
For a tight reservoir, assessment of zonal production contribution is often possible only after the reservoir has been hydraulically fractured. Spinner survey is commonly the tool of choice for diagnosing relative production contribution across perforated interval in a cased-hole and by extension, minimum productive fracture height at the wellbore. However, its limited radial resolution renders such tool unreliable in evaluating flow characteristic within fracture body and across fracture planes. The acquired data is generally insufficient for resolving relative contribution of various productive horizons intersected by the fracture. As the measurements are focused on flow characteristics inside the wellbore, fracture height diagnosis is limited by the extent of perforation interval. Alternatively, radioactive tracing and microseismic survey allow one to see through the casing wall albeit at the expense of heightened cost and operational complexity. Thermal logging, being a cheaper alternative, is time-sensitive and not deployable immediately following proppant placement due to restricted wellbore access. Most importantly, hydraulic and propped fracture heights diagnosed by these methods may not necessarily coincide with effective fracture height that contributes directly to well productivity.
Integrating acoustic logging to conventional production logging measurements may, in addition to increasing resolution for low flow measurement, significantly extend the investigation radius beyond casing wall. Different acoustic characteristics potentially exhibited by flow of different fluid phases may also validate conventional log-derived reservoir fluid types. The paper describes the application of acoustic logging in diagnosing zonal production contribution, fracture height, and reservoir fluid type across hydraulically fractured tight gas condensate and oil reservoirs.
In four naturally flowing wells, zonal production contribution derived from acoustic wave analysis and conventional production log data were both in good agreement. The analysis of depth-specific acoustic wave amplitude provided useful insight in the diagnosis of zonal production contribution and by extension, productive fracture height. In one well, acoustic-derived fracture height could be closely corroborated with that of radioactive tracer data. In addition, one may also observe distinct shape of maximum amplitude of first sound wave arrival in a gas well compared to that in an oil well.