bluuebunny/crossref_metadata_2025 huggingface dataset:
A Semi-Analytical Method for Forecasting Wells Completed in Low Permeability, Undersaturated CBM Reservoirs
Authors: Clarkson C. R. , Qanbari F..
Published: November 2015

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.
The Effect of Rank and Lithotype on Coal Wettability and its Application to Coal Relative Permeability Models
Authors: Mahoney Shilo A. , Rufford Thomas E. , Dmyterko Anastasia S. , Rudolph Victor , Steel Karen M.
Published: November 2015

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.
New Toe Sleeve Enables True Casing-Pressure Test in an Eagle Ford Shale Well: A Case Study
Authors: Wellhoefer Ben , Canning Sean , Alkek Travis , Haydell Garner , Smith Molly Wharton
Published: November 2015

The Eagle Ford Shale in the southern part of Texas is a carbonate-rich, oil-producing, organic shale. Typically, wells are drilled horizontally through the target section of the Eagle Ford shale formation. A long string production casing is then run and cemented in place. A plug and perforate completion helps enable hydraulic fracturing of multiple target intervals along the lateral section of the wellbore. Before fracturing the wellbore, pressure testing of the casing string to the maximum fracturing pressure has become an industry best practice. Then, a flow path is created at the toe of the wellbore using tubing-conveyed perforating (TCP) guns run into the wellbore on coiled tubing (CT).

With the constant drive to improve efficiency and lower completion costs, pressure-activated toe sleeves (PATS) have rapidly replaced the TCP CT run to create the initial fluid flow path. The PATS is run as part of the completion casing and cemented in place. Internal casing pressure is then applied to open the PATS and create the flow path. However, to accomplish a casing pressure test, the first generation PATS design must have the activation pressure set higher than the testing pressure. The casing test pressure must then be exceeded to open the PATS which is not ideal operationally for a variety of reasons.

This paper reviews a case study where a new, second generation PATS was used in an Eagle Ford shale well to allow a true casing pressure test and provide the initial flow path. The paper discusses the subject well, design, and operation of second generation PATS technology, and presents the results of the application. The positive economic impacts are also reviewed. The paper draws conclusions based on the results from the subject well, operation of the new PATS tool, and the economic impact experienced.
Preparing for the Tight Gas Steeplechase, Talking to Canadians about Deep, Tight Gas Sand (TGS) Developments
Authors: Pearson Bob
Published: November 2015

In recent years, a number of Basin-Centred, Tight Gas Sands and Shale Gas Exploration Wells have been tested in Australia. Since monetization of the resulting Contingent Resources involves embarking on a multi-year, multi-billion dollar mega-project, most operating companies use a formalized Stage Gate Process to critically review the maturation of the business opportunity.

To obtain adequate resources and time to undertake Appraisal Drilling and Field Development Option Assessments, the project must pass through a Stage Gate-1 Review of the Exploration results and scoping-quality economic screening of the potential development concept. Concept generation often relies on ideas obtained from literature reviews and brainstorming, as well as data gathering trips to somewhat analogous operations.

This paper summarizes observations from a somewhat disappointing data gathering initiative undertaken in 3Q2015 in Calgary to talk with knowledgeable Canadians about learnings from their Deep Tight Gas Sand Developments.

These interviews reconfirmed that many of the field development planning (FDP) issues discussed in the literature and at technical conferences over the last 25 years remain in-play:

Significant resources and time should be allocated to the Appraisal TGS plays. Many existing projects initially suffered from inadequate access to properly preserved and representative core materials and/or rotary sidewall cores. A broad ranging assessment of development alternatives and feasibility studies is recommended in Stage 2, before committing to FEED. There are multiple drivers for the use of large well pads with either integrated facilities or proximal facility hubs. This also facilitates fuel substitution and the re-use of fuel gas, frac fluid handling and power lines for other services later in the field's life. Pilot studies and phased developments are desirable to address a wide range of reservoir uncertainties, completion options and artificial lift methods. However, it may be possible to defer some pilots that address Tactical Issues into Stage-5 to increase hydrocarbon capture. Some operators are now revisiting ideas that were popular more than 25 years ago, including the use of non-aqueous frac fluids and/or stable foams. The FDP, pad and completion designs should anticipate both re-fracturing and infill drilling requirements. Much greater attention is now being paid to fracture effectiveness, rather than simply operational effectiveness and CAPEX reduction.
Numerical Investigations on the Impact of Fracture Characteristics on Elastic Anisotropy in Coal Seam Gas Reservoirs
Authors: Gao Jinfang , Gross Lutz , Tyson Steve
Published: November 2015

Coal seams are embedded into other sedimentary structures, such as sands, clays and shales. In coal seam gas reservoir engineering, structures such as layering, fractures, cleat orientations, porosity and fluids within the cleats have an important effect on production. The interpretation of 3D seismic surveys in terms of these fractures characteristics is of great interest.

Weak anisotropy is commonly described using Thomsen-style parameters. From seismic survey data, values for Thomsen-style parameters are determined, usually through non-hyperbolic normal moveout (NMO) and azimuth gathers. The interpretation of the parameters in terms of fracture characteristics is based on restrictive assumptions; sparse, non-interacting, disk-shaped fractures are commonly assumed in cases where fracture geometry is not required. This paper investigates the effect of 3D fracture geometry in coal seams on the effective 3D anisotropic elasticity parameters using a numerical approach. We show some first results to verify existing, commonly used elastic models for fractured media, derived under restrictive assumption and then test their validity for more realistic scenarios; fracture distributions and densities, and material-filled cleats. Our study will help to provide a more reliable interpretation of Thomsen-style parameters obtained from seismic survey data.

The impact of cleats, and other small-scale structures, on the elastic properties of coal is investigated using the discrete element method (DEM). The method is capable of simulating complex fracture distributions, surface roughness and orientations on different spatial scales. Firstly, DEM is calibrated by performing uni-axial compression testing and shearing testing on a virtual coal sample, to determine values for macroscopic model parameters for intact coal. Then, cleats with different fracture densities and occupying materials are added. From these tests, we are able to validate commonly-used elasticity models for fractured media (e.g., Linear-slip models and Hudson's model), which is of first order in fracture density.
Hydrodynamic Modelling of Hydraulic Fracturing Fluid Injection in North Perth Basin Shale Gas Targets
Authors: Palat Sankar , Torbatynia Mina , Kanadikirik Kerem , Varma Sunil
Published: November 2015

Recent discussions on potential Australian shale gas developments have raised public concerns regarding groundwater protection. This paper presents the results of modelling the movement of the hydraulic fracturing (HF) fluid after injection in north Perth Basin shale targets (Carynginia Formation). The model is also used to predict the migration of HF fluid along an imaginary adjacent fault. Similar studies are rare, both in terms of the technique applied and the geographical area covered.

A 3D model of a part of the North Perth Basin was constructed extending 100 km (East-West) by 10 km (North-South) by 5 km (in depth) with local grid refinement in the target zone to represent the fractured zone having higher hydraulic conductivity and higher specific storage. The fracture extent was determined by 2D fracture propagation modelling (PKN/GDK models). The model was run using the multispecies, density and temperature dependant MODFLOW-SEAWAT code, which simulates HF fluid injection and migration and the post-injection flow-back. The injection rate and the concentration of the additives in the HF fluid are based on field data, and the modelled flow-back rate is calibrated to the observed flow-back data of about 62% of the injected volume.

The simulation indicated that the HF fluid plume was contained in close proximity to the injection well and was reduced to a very small fraction of the original injection concentration (0.1 mg/L) within a distance of less than 250 m. Simulation also showed that injecting near the fault did not influence the flow of the HF fluid along the fault, with concentrations decreasing rapidly with height. A model sensitivity analysis was carried out, which showed that the plume extent is mostly sensitive to the rate of HF fluid injection.

The model shows that the HF fluid is contained within the target formation and that fluid intersecting a fault of high transmissivity results in the concentrations dissipating faster. The maximum concentration of the HF fluid declined to well below the human risk-based concentration of the critical constituents (within <1 year), based on several guidelines such as US EPA, European Chemicals Agency and Institute of Medicine.

This study indicates low impacts of hydraulic fracture stimulation during shale and tight gas development on potable groundwater sources in the north Perth Basin.
Adsorption Behavior Study of Shale Gas: Models and New Combination Approach
Authors: Jianchao Li , Zhang Lie Hui , Chen Yulin
Published: November 2015

Comparison of different adsorption models in the application of shale reservoir is performed, adsorption capability of shale is reconstructed by the combination of pure mineral adsorption capability with adsorption potential theory. Results are tested by experimental study of specific shale samples in China.

The research is based on the high pressure adsorption experiment of methane, in the same time X-ray diffraction experiment is performed to get the mineral information of the shale samples, which are taken from Lungmaxi formation in China. With the experiment, different adsorption models including monolayer Langmuir model, multilayer BET model and D-A model are used to match the data. Also, adsorption capability of pure minerals is combined by adsorption potential theory, which is used to study the contribution of different minerals on the total adsorption capability of shale.

Results show that Langmuir curve fits can be used to describe the adsorption behavior of shale, but BET curve fits give more accurate results, D-A curve fits make the best match. The use of characteristic curve can provide further information of the adsorption behavior, by which the unknown isothermal data can be forecasted. The adsorption capability with combination of pure mineral through adsorption potential theory (according to the mineral composition of each sample) gives reasonable results to indicate the total adsorption capability of shale, which means the new approach to get the adsorption information is applicable if the mineral composition and adsorption capability of each mineral are known.
Experimental Research on the Shale Imbibition Characteristics and Its Relationship with Microstructure and Rock Mineralogy
Authors: Yang Liu , Ge Hongkui , Shen Yinghao , Ren Kai , Sheng Mao , Gao Zhiye , Qin Xiaolun , Su Shuai
Published: November 2015

Field researches conducted on the multi-stage hydraulic fracturing measurements manifest that a large proportion of fracturing fluid retains in tight reservoirs, and the flow-back efficiency is usually lower than 30%. The publications have demonstrated that the spontaneous imbibition plays a significant role in large volumes of water loss, which is caused by high capillary pressure of tight rocks. Nevertheless, the imbibition characteristics of tight rocks are quite complex and still need further research owing to the complex pore structure, mineral constituent and strong microscopic heterogeneity.

Comparative imbibition experiments were carried out on 12 core samples, which are seclected from tight sandstone formation from Ordos Basin, tight volcanic formation from Songliao Basin and shale formation from Sichuan Basin. Hence, a new method is proposed to demonstrate the imbibition characteristics and estimate fracturing fluid intake in tight gas formation. Moreover, the authors study the water imbibition capacity and characteristics of tight rocks, which holds diverse mineralogy, pore-size distribution and pore connectivity. The experimental data of tight rock samples in different size and shape can be normalized by using the new characterizing method, which exhibits the imbibition capacity, initial imbibition and late imbibition rate. The imbibed water volume increases with the clay content, and smectite and illite/smectite tends to strong water imbibition. Due to the water absorption on clay surface, the ratio of imbibed water volume to pore volume measured by Helium exceeds 100%. In addition, a general observation shows that each imbibition curve of tight rock can be divided into an initial imbibition region, a non-linear transition region, and a late imbibition region. However, the imbibition characteristics of different tight rocks vary greatly, which could be attributed, at least in part, to the complex pore connectivity, pore-size distribution and mineral composition. Well-developed macropores tend to have well pore connectivity and large time exponent at the initial imbibition region. Well-developed mesopores and micropores tend to have poor pore connectivity and large time exponent at the late imbibition region. These studies can be used to evaluate the fracturing fluid imbibition characteristics, and to understand its relationship with pore connectivity and pore-size distribution in tight reservoir rocks.
A Novel Model of Brittleness Index for Shale Gas Reservoirs: Confining Pressure Effect
Authors: Hu Yuan , Perdomo M. E. , Wu Keliu , Chen Zhangxin , Zhang Kai , Ji Dongqi , Zhong He
Published: November 2015

Brittleness indices (BI) commonly used in the petroleum industry are based on elastic modulus or mineralogy that can be calculated from well logs. However, they both ignore the effect of confining pressure. Shale is usually distributed at different depth under different confining pressure. Models without considering the influence of confining pressure will directly lead to inaccuracy in BI calculation, thus resulting in the failure of hydraulic fracturing. In this work, we compared confining pressure with rock mechanics parameters and the microcrack quantity of a core, introduced "fracture toughness" to explain how confining pressure influences BI, and finally developed a new model to correct the effect of confining pressure in BI calculation. Fracture toughness is an important parameter that characterizing a rock’s resistance to a fracture. It increases with confining pressure, since an increase of confining pressure may close preexisting cracks and restrict the crack propagation. The results show that BI is usually larger at low confining pressure than at high pressure. Also, higher content in brittle mineral does not necessarily mean brittler. The results calculated by the new model, which considers the influence of Young’s modulus, Poisson’s ratio, tensile strength, confining pressure and fracture toughness in BI calculation, match well with experimental results.
Evaluation of Microwave Heating on Fluid Invasion and Phase Trapping in Tight Gas Reservoirs
Authors: Wang Hongcai , Rezaee Reza , Saeedi Ali
Published: November 2015

During well drilling, completion, stimulation and fracturing, moisture invasion and phase trapping lead to a drastic permeability reduction, which prevent the tight gas reservoir producing at an economical rate. To eliminate such formation damage, the power of microwave was considered. As an effective heating technique, the application of microwave heating in removing moisture in the near wellbore area is relatively novel and thus lack of experience. This paper simulates effects of microwave heating on the formation damage and gas production rate of a tight gas reservoir in Western Australia and demonstrates its effectiveness. The well information for a tight gas well in Western Australia was obtained to simulate the actual gas production in numerical model. Finite Element Analysis (FEA) software and industry standard reservoir simulation software were coupled to simulate microwave heating at borehole scale. The electrical conductivity was extracted from well logs and the dielectric constant and loss factor of the reservoir rock was calculated using the empirical equations and proven mixing law. Two cases studied are in non-fractured well and fractured well. In each study, same water amounts were injected for 5days followed by a same period of clean-up and gas production, the difference is one model has microwave heater while the other not. The effects of microwave heating on water saturation and relative permeability to gas were made between two scenarios of gas production with heating and without heating. The electric filed and magnetic field distributions and the heat generation rate in the near wellbore area were calculated based on the actual petrophysical properties of the reservoir rock and Maxwell's Equations. Based on the results from FEA, the heat generated by microwave was applied on the well models respectively. After microwave heating started, gas relative permeability increased and water saturation decreased through the heated zone. In all the cases, microwave heating seems to be an effective way to remove moisture and to recover the gas productivity back to a high rate. But in non-fractured reservoir, the gas production rate has achieved the most improvement. The present paper focuses on the interaction of microwave and trapped moisture in the reservoir. By simulating the heating assisted gas production, illustrate how microwave heating was able to increase gas well productivity by reducing water saturation. More factors need to be considered in the future, and the suggestions have been given in this paper.
Downhole Naturally Convective Hydrocarbon-Separating Production System to Avoid Unnecessary Water and Sand Production
Authors: Surjaatmadja Jim B. , Lewis Bryan J.
Published: November 2015

In the production of oil and gas, operators are usually faced with undesirable by-products: water and sand (or particulate matter). Bringing these unwanted materials to the surface requires additional energy and cost and reduces the total flow of hydrocarbons to the surface. Once water and sand are brought to the surface, additional energy-intensive processes are required to separate them from the oil and gas. Once separated, properly disposing of unwanted materials also can be challenging and costly. Eliminating, or at least reducing, their production is therefore economically beneficial.

Downhole separators are often used to separate fluids and particulate matter. While these devices are effective, they require a substantial amount of energy. Passive, conductive separation based solely on static weight is a relatively slow process and not practical, as the weight difference of water and oil is approximately 10%. This paper discusses the use of a long angular conduit, or deviated wellbore, to passively create convective forces that enhance the separation. In the deviated section, as the heavier water and sand move to the bottom side of the conduit, the net forces push the heavier water and sand to the bottom, resulting in a convective motion pushing the lighter fluid to the top of the conduit. The weight differences in the produced mixture are amplified by the extended length of the conduit, and the heavier liquids and solids quickly separate from the lighter-weight fluids without any additional energy input as the mixture flows through the deviated section.

Laboratory tests show that convective separation can occur more than 10 times faster than natural static conductive separation. Additionally, the convective separator is capable of effective operation with production flow rates up to 6,000 BOPD with a 6 in. production casing. At higher flow rates, the separation is incomplete because of turbulent mixing, and some unwanted materials could be produced at the surface.

Using this approach, no energy is wasted for producing water, as it can be injected in lower strata after separation. The separated water also can be used for water drive in the formation. Sand, on the other hand, might need to be removed periodically. However, such periodic sand removal can be performed without damaging wellhead equipment.
Development and Verification of Degradable Sealing Elements for Fully Degradable Frac Plugs
Authors: Takahashi Shinya , Okura Masayuki , Kobayashi Takuma , Takahashi Takeo
Published: November 2015

The continuing growth in demand for hydrocarbons has led to the increase in the stage count of hydraulic fracturing in unconventional reservoirs. A typical stimulation method is the plug-and-perf system, which uses frac plugs for zone isolation. Conventional plug-and-perf requires milling out to recover the flow path for hydrocarbons after fracturing is complete. Fully degradable frac plugs are in great demand to eliminate milling out, reducing the cost and risk of well completion, and extending the lateral length of wellbores. A key material for fully degradable frac plugs is a sufficiently degradable rubber with good sealing properties for the sealing elements of the plugs. This paper provides an overview of the material properties of the degradable rubbers that were developed by a comprehensive study of materials, and their suitability as sealing elements for degradable frac plugs. Nonlinear, three-dimensional multi-body contact analysis and qualification testing were integrated to design and test the sealing elements. The results indicate that the resulting sealing element will function at over 100 MPa without failing.
Fracture Complexity: Analysis Methodology and Signature Pressure Behavior of Hydraulic Fracture Propagation from Horizontal Wellbores
Authors: Bazan Lucas W. , Meyer Bruce R.
Published: November 2015

During hydraulic fracture propagation three regions may be identified from the pressure response referred to as: 1) near-well, that extends tens of inches, 2) mid-field, that extends tens of feet and 3) far-field, that extends hundreds of feet from the wellbore. Each region can experience simple, tortuous, and complex fracture behavior creating unique pressure signatures. It has been observed that complex fractures with extended fracture storage can result from hydraulic fracture stimulation in highly deviated and horizontal wells. Complexity is created as a result of induced hydraulic fractures turning and twisting as they exit the wellbore in the near-well region, propagating into the mid-field region, and then re-orienting in the direction of principal stresses in the far-field. This results in anomalously high apparent net pressures as evident by increased ISIP's and rapidly declining pressures that dissipate minutes after shut-in.

This paper presents minifrac and post-job pressure matching case studies that identify and describe mid-field fracture complexity (MFC), or extended wellbore pressure storage. The pressure behavior supports complex fracture propagation, high fracturing pressures and pressure fall-off responses typically observed in horizontal shale wells. High apparent fracturing stress gradients are often seen that are much greater than the over-burden stress-gradients. Although suggestive, these high stress gradients are not indicative of horizontal fractures in the far-field. Uncharacteristically high MFC is also not necessarily related to fracture complexity in the far-field. A methodology is presented that identifies the "actual" ISIP which allows for in-situ stress calibration, true net pressure identification, proper minifrac interpretation and an improved fracture treatment design.

Rapidly declining pressure during a shut-in as a result of MFC resembles pressure dependent fluid loss and often is misinterpreted as such. However, the pressure response is a result of extended fracture storage and energy dissipation in the mid-field region, which can result in multiple closure signatures. Multiple closure events are indicative of complex fracture network behavior as a result of stress anisotropy and creation of multiple non-planar fractures in the mid-field region. Additionally, hydraulically induced secondary fractures perpendicular to the maximum horizontal stress can provide insight into stress anisotropy. Identifying and incorporating MFC into pressure interpretation analyses will enhance fracture treatment design and post-job pressure matching providing a systematic methodology for designing and analyzing horizontal shale fracture treatments. Information regarding MFC is critical in interpreting fracture treatment pressure responses and optimizing fracture treatment designs in horizontal wells, including well spacing and fracture interference.
Anisotropic Wellbore Stability Model for Transversely Isotropic Formation and Its Application in Drilling Through Shale Formation
Authors: Lu Y. H. , Chen M.. , Jin Y.. , Chen G.. , Lin B. T. , Liang C.. , Ji J. X.
Published: November 2015

Severe borehole collapse has occurred during extended reach drillingsin shale formations of Dongping Block, Qinghai Oil-field. An extreme difficulty is to choose mud weight lower bounds properly. Previous isotropic wellbore stability model does not consider the heterogeneities in transversely isotropic porous media like shale, thus fails to predict mud weight accurately. To solve the problem, a new wellbore stability modelis proposed; and an optimized nano-type drilling fluid is designed.whichcan be applied fordrilling operation.

The wellbore stability modelis developed through four steps: 1. The far-field stressesare transformed from an in-situ stress coordinate system to a borehole coordinate system; 2. An analytical solution for a near-borehole stress distribution in an elastic anisotropic formation under a transformed in-situ stresses regime is used, based on the complex-variable elasticity theory and the Biot's consolidation theory; 3. The around-borehole stressesare transformed from the borehole coordinate system to a weak-plane coordinate system; 4. An improved Mohr-Coulomb failure criterion is used to identify rock failure mode (along weak plane or through rock matrix) and to calculate the mud weight lower bound.

In addition, laboratory experimensts have demonstrated the ability for water-soluble hybrid nano-particles to plug shale matrix and micro cracks inside the shale, which helps to prevent chemical erosion of fluid to the rock. By sealing natural fractures with nanoparticles and optimizing mud weight using the new wellbore stability model, the borehole instability is effectively controlled. A procedure is also developed for wellbore stability analyses based on a comprehensive consideration of the formation property, the mud chemical property and the mud weight. This approach was applied to 12 deviated pilot wells drilled through shale formation in Dongping Block, where high pore pressure and natural fracture systems prevail: the mud weight is increased from previous 1.5g/cm3 to the present 1.85g/cm3. It is observed that the drilling time and the drilling complexities have been reduced by up to 52.4% and 62.4%, respectively, with significant cost savings.
The Application of Mud Weight Optimization Method in Fractured Tight Sandstone Formation
Authors: Liu M.. , Jin Y.. , Lu Y. H. , Chen M.. , Hou B.. , Yang S.. , Wen X.. , Chen Y..
Published: November 2015

Fractured tight sandstone formation is an important unconventional oil and gas accumulation distributed in a wide region of Tarim oilfield in China at great depth, and has several distinct features: high-pressure/high- temperature drilling environment, low rock matrix permeability, well-developed natural fracture system, and highly anisotropic in-situ stress. Even using highly inhibitive oil-based fluid during drilling operation, mud loss and wellbore collapse still occurred frequently. Moreover, in many wells when the mud weight is added, borehole conditions become not better but worse. Contrary to the traditional field experiences, collapse pressure itself has a mud weight window.

According to the field observations and literature reviews, we built a model based on the poroelastic theory, coordinate transformation technique and temperature field simulation. We found that classical Mud Weight Window is no longer being appropriate for wellbore analysis in fractured tight sandstone foremation. Instead, a Crtical Mud Weight Window is proposed, which properly explained unusual drilling problems.

A mud weight optimization strategy is also discussed to minimize the shear failure region around a borehole. In addition, a flow chart including the experimental equipments and calculating method is presented.This approach is applied to explain the drilling problems in 8 vertical wells drilled through Bashijiqike formation. It is observed that the new method may provide more accurate instructions for mud weight selection.

Finally, we presented a field case study in Keshen block, Tarim field. In this case, the engineers used our method to choose the mud weight. As a result, this model offers reasonable mud weight that is useful to mitigate borehole instability in fractured tight sandstone formation.
Novel Well Test Design for the Evaluation of Complete Well Permeability and Productivity for CSG Wells in the Surat Basin
Authors: Bottomley W.. , Schouten J.. , McDonald E.. , Cooney T..
Published: November 2015

The Surat Basin Coal Seam Gas (CSG) play requires a vast number of wells to develop, and reservoir productivity changes quickly over small distances. Well testing provides a means to evaluate these changes. But, the high cost of conventional testing precludes sufficient tests to ensure areal and statistical coverage across a large well stock. This paper discusses a new approach whose reduced cost allows five times more wells to be tested than conventional methods. By testing more wells, there is more data for subsurface model calibration and productivity fairways can be better mapped and developed.

In the Surat Basin CSG play there is an industry-wide completion technique that uses air to lift every well to size the initial downhole pump for dewatering. This paper describes an enhancement to this standard pump sizing test which facilitates the provision of key reservoir information: full well permeability, skin and productivity. This novel well test is termed an Air Assisted Flow Test (AAFT).

During the AAFT the well is produced at a predictable drawdown for up to an hour whilst accurate rate measurements are made at surface. A downhole shut-in is then performed and a pressure gauge measures the build-up pressure response. The additional equipment and rig time have been designed to add a minimal cost to the standard completion operation and test cost is 20% of a traditional Drill Stem Test (DST).

Field tests using the AAFT and multiple dual packer DST's in the same well clearly demonstrate that both testing methodologies deliver the same results. It is therefore valid to incorporate the AAFT into the extensive permeability database for the Surat Basin. Additionally drawdown dependent skin has been observed in data from the new AAFT. This phenomenon is interpreted to be the result of stress dependent coal fracture permeability in the near well bore region.

This new testing method is only directly relevant to CSG developments. However the awareness to gather additional data, from enhancing a standard operation, is applicable to all unconventional and conventional reservoirs.
Application of UDM-2 Drilling Fluid Technology in the Development of Upper-Deep Oil and Gas Resources in Tarim Basin
Authors: Zhu Jinzhi , Li Long , Li Lei , Zhang Zhen , Cheng Rongchao , Zhang Jie , Liu Xiao , Li Jiaxue
Published: November 2015

The oil-gas exploitation techniques of the piedmont tectonic formation of Tarim Basin are facing a great challenge. Due to the ultra-high temperature (up to 180 °C), high pressure (mud weight up to 2.6 s.g.), ultra-thick composite gypsum-salt formations (thickness up to 4137 m), high pressure brine layer, significant non-productive time (NPT) and low rate of penetration (ROP) are encountered in dealing with borehole instability, stuck pipe, high pressure brine influx and downhole losses. To meet the need of drilling operation in the piedmont tectonic formation, a kind of high-temperature high density oil-based drilling fluid system known as UDM-2 drilling fluid system is developed.

UDM-2 drilling fluid system has excellent comprehensive properties, and it could resolve the contradiction between safety drilling of complicated deep wells and formation complexity. UDM-2 drilling fluid system has been recommended to run for about 60 wells in this block, resulting in very good results.

Three sets of plugging technology for oil-based drilling fluids are applied successfully in the gypsum-salt formations or pay zones, and the total volume of loss of UDM-2 drilling fluids to the formation is significantly reduced from the beginning of the project, so the drilling time and cost can be saved remarkably.

The large-scale application of UDM-2 drilling fluid technology has brought great economic and social benefits, and provides a strong technical support for efficient production and development of upper-deep oil and gas resources in Tarim Basin.
Quick Tricks, Tips, Analytical Methods and Other Proxy Tools for the Unconventional Reservoir Engineer
Authors: Jordan Colin Lyle
Published: November 2015

The unconventional reservoir engineer is required to evaluate increasingly complex data. In additional to the rapid advancement of technology used to complete and stimulate unconventional resources, there has been a proliferation of type curve procedures (i.e. pressure and rate transient analysis), decline techniques, and reservoir modelling strategies in the literature. Specific challenges are the analysis of single and multi-phase flow form hydraulically stimulated horizontal and multi-lateral wells. Although state of the art simulation techniques can be used to model any complex reservoir and well architecture, restrictions on data quality, project schedules, and budgets do not always allow for detailed simulation and analysis. Furthermore, initialization of the numerical model often requires some form of analytical modelling as a precursor to the larger model.

However, complex scenarios production analysis or forecasting of horizontal wells, dual and tri-laterals, fracture horizontals as well heterogeneous reservoirs can be simplified by using an proxy model which is accurate (if not exact) with respect to long-term deliverability and resource/reserve estimation. Complex wells and reservoirs can be modelled and analyzed by using a simple homogenous reservoir with effective permeability, skin, and wellbore radius combinations. Examples will demonstrate this procedure would allow for the use of simple analytical software tools in lieu of simulation, or the generation of reliable forecasts in the absence of completion/reservoir data
Saudi Arabia's Emerging Unconventional Carbonate Shale Resources: Moving to Horizontals with an Integrated Engineering and Geosciences Approach
Authors: Al-Mulhim N. I. , Korosa M.. , Ahmed A.. , Hakami A.. , Sadykov A.. , Baki S.. , Asiri K. S. , Al Ruwaished Azmi
Published: November 2015

Unconventional resources in Saudi Arabia symbolize an opportunity to extend required gas plateaus in the long term, to substitute gas for liquid fuels, and to provide potential feedstock for the growing chemical industry. This paper aims to outline an integrated completion engineering and geosciences approach that was applied in the Jafurah shale gas play. The goal was to address complex unconventional reservoirs and their associated challenges, and to determine the optimum completion and fracture design.

Sweet spot identification within the Jurassic Tuwaiq Mountain Formation in the Jafurah basin represents a major challenge as it requires a large number of wells drilled over a wide geographical area with high associated costs. This requires innovative drilling, completion and stimulation practices. In order to identify and maximize potential frac stages and placements, a comprehensive study was completed using an advanced workflow encompassing drilling, geophysics, geomechanics, reservoir characterization, completion and fracturing and microseismic monitoring.

The targeted Jurassic Tuwaiq Mountain rocks are calcareous and interpreted to have been deposited in a restricted marine environment within an intra-shelf basin. This shale carbonate play shows a high Total Organic Content (TOC), low clay content, good matrix permeability, high gas saturation and high effective porosity. Scanning Electron microscope (SEM) images exhibit a dominant presence of organic porosity associated with the kerogen. Initial results from vertical wells drilled in the Jafurah basin proved that proppant fracturing can be successfully placed, and indicated the presence of a potential gas rich play within the same source rock. Subsequent horizontal wells were the first liquid rich/gas carbonate horizontal wells with ultra-low shale permeability in Saudi Arabia. The first horizontal wells had excellent gas production with significant amounts of condensate.

By further building on experience from the drilled and stimulated wells, the lessons learned provide a foundation for the completion of future unconventional gas wells in the Jafurah basin.
Study of Pore Structure of Gas Shale with Low-Field NMR: Examples from the Longmaxi Formation, Southern Sichuan Basin, China
Authors: Chen Yulin , Zhang Liehui , Li Jianchao
Published: November 2015

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.
Evaluating Dynamic Behaviour of a Complex In-Situ Gas Composition From a Coal Seam Reservoir - A Case Study From Fairview Early Permian Cattle Creek Coals
Authors: Falcon G. E.
Published: November 2015

Early Permian Cattle Creek Coals in Fairview Field in Queensland Australia is an insitu multicomponent Coal Seam Gas Reservoir. The Early Permian East coals or Springwater play typically occur at depths between 1,100 m to 1,800 m. These medium volatile bituminous coals are characterized as having lower permeability (<5 mD), a high gas content (10 – 15 m3/t daf), an elevated concentration of ethane and heavier hydrocarbon components (2 – 14% C2+), and higher inerts concentration (0.2 – 12% CO2, < 3% N2) than found in many CSG fields. .

An analysis and history match of the production data from existing appraisal wells with a particular emphasis on the produced gas composition and its variation with depletion was performed using both an in-house compositional simulator which used the extended Langmuir Isotherm as the basis for the equilibrium relationship between the free and the sorbed gas phase and a commercial compositional simulator. Methane, Carbon Dioxide, Ethane, Propane and Nitrogen were simulated during this study.

The results showed potential differences between the produced gas composition obtained during well production (considering the adsorption/desorption behavior of a multicomponent gas in a coal seam reservoir) and the in-situ gas composition determined from gas sampling during desorption tests. Heating value profiles were generated and compared illustrating the potential impact of the reservoir dynamic behaviour.

The results also showed how the produced concentration of N2 (free gas phase) can be 4 to 7 times higher than its insitu concentration and that a variation of up to 75% of the initial concentration in free gas phase of CO2 and C2H6 concentration is possible due to the variability of the isotherms indicated from core.