bluuebunny/crossref_metadata_2025 huggingface dataset:
Investigation of Fracture Tip Behaviour in Visco-Elastic/ Visco-Plastic Shale Rocks and Its Effect on Fracture Propagation
Authors: Song Huifang , Gholami Amin , Bazunu Gamaliel , Rahman Sheik S.
Published: November 2015

Most shale plays have to be hydraulically fractured to acquire commercial production. Shales are typically characterised by varying quantities of clay, carbonate and organic material, therefore each shale type has different deformational properties, which lead to different outcomes with respect to hydraulic fracture efficiency. Unconsolidated, high clay content or organic rich shales exhibit visco-elastic or visco-plastic behaviour, acoording to many researchers[1–3]. Although the effect of this time-dependent behaviour on fracture propagation is considerable it has not yet received much attention. The aim of this paper is to address the time-dependent response of shale under hydraulic stimulation, more specifically, to monitor fracture parameters change and deformation at crack tip area depending on the lag time between stress and strain.

In this paper, an innovative method to analyse time-dependent deformation of material at fracture tip and its effect on propagation of hydraulically induced fractures by incorporating visco-elastic behaviour is presented. To characterise fracture state, J integral is revised and implemented in the framework of finite element model. The fracture is treated explicitly with refined mesh around the crack tip in order to obtain detailed information in static state. During loading condition, visco-elasticity and visco-plasticity is not differentiated for practical purposes.

The results show that under a centain hydraulic pressure a crack creeps rapidly and possibly propagates. It is shown that stress intensity factor and revised J integral has a rapid changing gradient at the beginning and becomes stable over time. The crack tends to be wider and shorter in creeping shale. Propagation process is hindered by viscous energy dissipation and successive cohesive force. In simulation the experimental data from US shale plays are used to study fracture propagation behaviour under viscoelastic behaviour. Results of this study allow industry gain a better understanding of deformational behaviour of shale when fracturing. The know-how derived from this study will assist planning effective stimulation program in the development of shale gas reservoirs.
Sweet Spot Identification and Prediction of Frac Stage Performance Using Geology, Geophysics, and Geomechanics - Application to the Longmaxi Formation, China
Authors: Yang X.. , Wang X.. , Aoues A.. , Ouenes A..
Published: November 2015

Microseismic data is evaluated with surface seismic and analyzed in addition to treatment data to understand the variance in performance of frac stages at three wells drilled in the Longmaxi formation, China. In well H1, the microseismic is dominated by fault reactivations, and is of little use in analyzing the performance of individual frac stages. In the wells H2 and H3, the use of maximum curvature derived from surface seismic showed strong qualitative correlation with microseismicity. To quantify the effects of shale properties on the frac stage performances, seismic attributes were used to derive geologic models of porosity, total gas, fracture density and Poisson's Ratio which were combined to form the Shale Capacity. The comparison of the Shale Capacity with the production log of H1 demonstarates how the model explains the performance of the frac stages away from the faults. The same observations could be made using the extent of good Shale Capacity away from the faults to explain the important difference in production between H2 and H3. Given the importance of the faults and their geomechanical impact on the performance of the frac stages, a geomechanical workflow able to simulate the interaction between the hydraulic and natural fractures is applied to the H1 well. The resulting strain and J Integral are able to explain the performance of the frac stages in H1 thus confirming the importance of the natural fractures and the need to account for their geomechanical effects.
Optimal Core Retrieval Time For Minimizing Core Decompression Damage
Authors: Hoeink Tobias , van der Zee Wouter , Arndt Stephan
Published: November 2015

The ability to obtain detailed physical measurements from subsurface samples in a controlled laboratory setting crucially depends on the quality of the retrieved core. The key to maximize core quality is to limit avoidable damage during drilling, retrieval, handling, transport and analysis. This paper focusses on the retrieval process, where core integrity can be compromised when the core is retrieved too quickly without allowing sufficient time for pore pressure equalization. Core integrity, in particular avoiding decompression damage, is a distinctive concern for low-permeability shales. A common notion is to retrieve slowly to allow for pore pressure equilibration. Operational considerations, on the other hand, demand the shortest possible retrieval time. This paper discusses a resolution to these two conflicting requirements by identifying the optimal core retrieval time using finite-element modeling and optimization techniques.

In this paper, a core retrieval effort is modeled using an axisymmetric, finite-element representation of a core with pore fluid that is subjected to successively decreasing external pore-pressure boundary conditions and pressure loads. The modeling results are analyzed for the maximum pore-pressure difference and compared with rock strength criteria to predict potential core damage.

The optimal retrieval time for given geometric and material parameters is determined with an optimization algorithm. The combined use of finite element modeling and optimization techniques in a reliability study enables the determination of core damage probability. This technique provides an analytical-based guideline for the shortest core-retrieval times without compromising core quality due to decompression.
100% in the Sweet Section: An Effective Geosteering Approach for Silurian Longmaxi Shale Play in Sichuan Basin
Authors: Liang Xing , Wang Lizhi , Zhang Jiehui , Xian ChengGang , Wang Gaocheng , Zhao Chunduan
Published: November 2015

A new geosteering approach significantly improves effectiveness and efficiency of geosteering in shale gas fields such as the Silurian Longmaxi gas shale in the south Sichuan basin, China. This formation presents more challenges than in classical sand/shale formations even when logging while drilling (LWD) imaging is available because of the cyclic gamma ray (GR) response of the targeted shale formation, subseismic microfaults with unknown displacements, and sudden structure changes from subseismic microstructures.

The new approach introduces more geosteering elements including correlation in the true stratigraphic thickness (TST) domain with considerations of the cyclic nature of shale gas zones; conducting multi-scenario modeling to verify the most likely scenario fitting the overall structural trend and the cyclic features; using an 3D geological model as the overall guidance of structural variations; and using a key bed detection strategy when the above methods can't precisely determine structural position.

The sweet section of Longmaxi shale has five sub-zones with respectively regressive or transgressive sequences, and the bottom zone with extremely high GR readings. The cyclic nature often resulted in inconclusive structure correlation based on changes of GR readings only. Field experiences showed numbers of subseismic microfaults with unknown fault displacement, and sudden changes of structural dips due to sub-seismic microstructures can be encountered, which can make the standard geosteering method insufficient to judge the actual position of the horizontal lateral. The new approach especially the multi-scenario modeling method in TST domain and the downward detection geosteering strategy to track the bottom high GR marker shale zone can clarify in-situ geology and minimize potential out-of-zone risk. The new approach has ensured all drilled horizontal wells was implemented 100% in the sweet section during the pilot and factory drilling phases. This paper demonstrates several examples to highlight its capability to handle complex situations for effective geosteering in contrast to the standard approach. The field practices also show this new approach can help to reduce unnecessary changes of drilling directions to ensure a smoother wellbore for subsequent operations. Our experience suggests iteratively updating the 3D geological model with improving accuracy must be treated as part of the overall geosteering strategy. Also a real-time decision making scheme throughout all involved segmens must be ensured for seamless operation.
Architecture of the Fracture Network of Shale Reservoirs by Tracking Exchangeable Cations
Authors: Roshan H.. , Sarmadivaleh M.. , Iglauer Stefan , Curtin U..
Published: November 2015

The structure of the fracture network formed by hydraulic fracturing operation is one of the key parameter in production from unconventional shale reservoirs. The standard approach to obtain such information is usually through well-testing coupled with micro-seismic monitoring. Unfortunately, the micro-seismic mapping is not always carried out and the conventional well-test techniques often fall short in describing the flow in shale reservoir in particular the contact area of the fractures open to flow.

The other alternative technique to get insight into structure of the fracture network is to use chemical tracer tests. In this study, we propose a new simple and cost efficient technique to estimate the fracture contact area by tracking the major exchange cations in shale reservoirs.

The idea behind the proposed technique is to replace the major cations on fracture surfaces in shale by increasing the concentration of one of the major cation in fracturing fluid. The current technique is satisfied the industry standard practice as the high concentrated K+ is part of hydraulic fracturing fluid composition and therefore cation exchange with other major cations (Na+, Ca++ and Mg++) is expected to occur.

In order to test the feasibility of the proposed techniques, a set of laboratory tests were conducted where a shale sample was milled and sieved to three different sizes to have different contact area. They are then placed in a high pressure cylinder (built for this study) and were washed by concentrated NaCl solution under high pressure and controlled temperature. The effluent was collected successively and analysed for major cations using ICP-MS. Correlation relating the cation exchange mass content to contact surface is proposed and calibrated using the data obtained from laboratory tests.
Taking the Heat out of the Burning-ice Debate: Potential and Future of Gas Hydrates
Authors: Decourt B.. , Alias S.. , Debarre R.. , Askew P..
Published: November 2015

Finding gas hydrates to be a controversial, polarizing subject, the SBC Energy Institute (SBC-EI) developed a fact-based report, presenting: the key concepts; the status of exploration and production technologies; the status of research, development and demonstration (R,D&D); and the environmental and safety challenges associated with the potential exploitation of this resource. In addition to leveraging the long involvement of Schlumberger in gas hydrates R,D&D, the SBC-EI performed a literature review and engaged experts in the gas-hydrate field. The SBC-EI also analyzed patents from 50 offices worldwide, using the Thomson Derwent World Patents Index, and conducted a survey of gas-hydrate stakeholders to present the state of R,D&D and a faithful picture of current thinking among academics and industry players involved in the field. Among various types of deposits, gas hydrates hosted in sand-dominated sediments both within permafrost and offshore stand out as the only resources that may be recovered in the near term. Contrary to common belief, these deposits can largely be identified using existing exploration technologies, with small adjustments. Stakeholders widely agree that depressurization is the best technology for producing gas hydrates from sand reservoirs, whereas interest in CO2-CH4-exchange production techniques have lost momentum. Nevertheless, gas-hydrate exploration and production raise significant technical challenges that, unresolved, could undermine the resource's commercial viability. R,D&D remains a vital part of assessing the potential and economic viability of gas hydrates, and of addressing environmental and safety concerns. It is unlikely that gas hydrates will become competitive in gas-rich areas. But there is a much stronger possibility of commercial development in energy-deficient regions such as Asia, where gas-hydrate projects could alleviate energy-security concerns and strenghten energy independence. This would have revolutionary consequences for the energy sector. However, before this is possible, long-duration production tests are required. Japan is leading the way in this area and is aiming to achieve commercial operation by the end of the decade. This paper provides a fact-based review of existing knowledge on gas hydrates as a potential energy source. It is supported by two innovative analyses: (i) a comprehensive survey of gas-hydrate experts; and (ii) an in-depth examination of worldwide patents of gas-hydrate technologies.
Effect of Suspension Fluid Chemistry on Fracture System Stimulation Using Micro-Sized Proppant Placement
Authors: Keshavarz A.. , Badalyan A.. , Carageorgos T.. , Johnson R. L. , Bedrikovetsky P. G.
Published: November 2015

The physical model and experimental data support the beneficial technology of graded proppant injection into naturally fractured reservoirs to stimulate natural fracture permeability. Injection of particles with increasing size, at poroelastic and hydraulic fracturing conditions, yield deeper penetration and gradual filling of natural fractures with a resulting increase in permeability. This work expands on the concepts and outlines steps to maximize the benefit of graded proppant injection to enhance coal seam gas stimulation by focusing on the effect of the chemistry of injected fluid on the overall performance and the use in conjunction with hydraulic fracturing.

Low productivity indices can be observed in many moderate- to low-permeability coal bed methane (CSG) reservoirs due to low aperture and poor connectivity of natural cleats. Graded proppant injection in CSG environments can: stimulate a stress sensitive cleat system below the fracturing pressure as well as enhance a fracturing treatment by invading cleats, lowering fluid leakoff, and maintaining aperture during production. Further, periodic or remedial treatments could to counter effective stress on the cleats improving production by maintaining cleat aperture.

Laboratory tests on coal core flooding by water under increasing pore pressure with proppant injection at the maximum pressure have been carried out under different salinities of the injected water. Proppant-proppant and proppant-coal Derjaguin-Landau-Verwey-Overbeek (DLVO) total interaction energies were calculated to optimise the condition for successful proppant placement. Results on the DLVO total energy of interaction showed that conditions favourable for successful proppant placement in coal cleats are suspension ionic strengths between 0.05 M and 0.1 M NaCl. At these conditions no proppant agglomeration and proppant-coal attachment are observed, allowing deeper penetration of proppant into the natural coal cleat system. Lower suspension ionic strengths can lead to natural coal fines migration, cleat plugging and coal permeability reduction.

Based on the experimental results and previously developed model a case study has been conducted to evaluate the productivity enhancement using this technique. The results show about four-fold increase in well productivity index at injections below fracturing pressures and may further improve the stimulated reservoir volume when used in conjunction with low permeability coal hydraulic fracturing treatments.
Measurement of Shale Anisotropic Permeability and Its Impact on Shale Gas Production
Authors: Pan Zhejun , Ma Yong , Danesh Nima Noraei , Connell Luke D. , Sander Regina , Down David I. , Camilleri Michael
Published: November 2015

Gas shales act as both the source rock and reservoir for the petroleum. One of the important characteristics of the reservoir is its low permeability, making gas production difficult. Although economic shale gas production has been achieved through horizontal drilling and multistage hydraulic fracturing, shale reservoir permeability is still one of the critical parameters in the evaluation of a shale gas play. In the present work, experimental measurement of shale anisotropic permeability is determined using a cubic shale sample in a triaxial cell. Anisotropic permeability was measured at a series of gas pressures and confining pressures. A permeability model incorporating stress and Klinkenberg effect was applied to describe the data. The model was applied in the reservoir simulator SIMED IITM to investigate the impact of anisotropic permeability and its change on shale gas production. Results are compared between using the vertical permeability, horizontal permeability, or anisotropic permeability as the reservoir permeability. The results show that using vertical permeability will significantly underestimate the gas production rate. This demonstrates that measuring directional permeability and using the most appropriate one is important for evaluating shale gas production and development of shale gas assets.
Hydraulic Fracturing Simulations in Zhahaquan, Qaidam Basin, P.R. China: Can Early Screen-Outs be Avoided With Model Based Design?
Authors: Weng Dingwei , Falser Simon , Ding Yunhong , Xu Yun , Liang Hongbo , Wang Liwei , Lin Hai
Published: November 2015

The Zhahaquan tight oil field is located in the late tertiary siltstone of the Qaidam Basin, Gansu Province, P.R. China. The field's conventional and tight reservoirs are currently being appraised with an aggressive drilling campaign. Despite an average plug permeability of about 0.3 mD and a modestly overpressured reservoir (12–16 kPa/m), hydraulic fracturing (HF) stimulations are deemed necessary to produce the light oil (31° API) at commercial rates. Stress modelling and fracture diagnostics confirm a predominately normal faulting stress regime throughout the basin, but vertical stress contrasts between formation layers highlight no potential frac barriers.

Initial hydraulic fracturing stimulations in 8 vertical wells resulted in 6 out of 11 stages screening out prematurely, while the remaining 5 could only be completed with light proppant concentrations below 10% of fluid volume, resulting in only modest production rates. Subsequent well stimulations were designed based on refined modelling results, with which screen- outs could be avoided and initial production rates tripled.

This study puts forward the modelling and execution of one horizontal well with 27 perforation clusters divided into 10 stages, in which the effects of fluid rheology, proppant concentration and injection rate on the resulting fracture geometry are highlighted. The study further shows that unlike in preceding simulations, the cluster- and stage spacing were optimised with respect to the stress interference between parallel fractures.
The Influence of Cleat Demineralisation on the Compressibility of Coal
Authors: Balucan Reydick D. , Turner Luc G. , Steel Karen M.
Published: November 2015

The natural fracture system of coal is the primary conduit for gas flow. Low permeability is in many cases attributed to low fracture porosity and/or connectivity. Mineral occluded coal cleats are known to considerably reduce coal permeability. Whilst cleat demineralisation has been found to increase coal permeability, its influence on compressibility is poorly understood.

In this study, we investigated the influence of mineral dissolution and secondary mineralisation on the compressibility of coal (Cf) following acidification with hydrochloric and hydrofluoric acid (HCl-HF). In-situ HCl core flooding and core immersion in 3% and 15% HF yielded a less compressible core (Cf = 0.006 from 0.020 bar-1) with sustained, enhanced permeability to brine (k = 0.40 from 0.10 mD). We attribute improved stress resilience and better fluid flow characteristics to the dissolution and subsequent secondary mineralisation of the core's circumferential periphery.

Predictive geochemical speciation using OLI Analyzer 9.1, for surveying mineral solubilities and precipitation tendencies, identified the formation of radio-dense neofluoride salts K2SiF6 and CaF2 Structural modifications and mineralogical changes detected from scanning electron microscopy-electron diffraction spectroscopy (SEM-EDS), confirmed the presence of these salts. Results suggest that mineral alteration and subsequent secondary mineralisation of the core periphery following HCl-HF acidisation yielded well-formed crystalline salts, apparently serving as in-situ generated proppants buttressing newly created void spaces for enhanced fluid flow and improved resistance to increasing confining stress.
Evaluation of Molecular Diffusion Effect by Using PVT Experimental Data: Impact on Gas Injection to Tight Fractured Gas Condensate / Heavy Oil Reservoirs
Authors: Ohata Tomoya , Nakano Masanori , Ueda Ryo
Published: November 2015

Molecular diffusion is one of the most important factors to be considered when predicting oil recovery by application of gas injection. In this paper, a fluid characterization methodology including the estimation of molecular diffusion coefficients, which directly express the effect of molecular diffusion under reservoir conditions, is presented. In addition, the impact of diffusion on oil recovery by considering gas injection to a tight fractured gas condensate / heavy oil reservoir is also examined. We estimated the Fickian molecular diffusion coefficients from a combination of experimental data using a PVT cell and simulation matching based on coefficients calculated by the Leahy-Dios and Firoozabadi (2007) equation. As a result, we successfully estimated the coefficients and found that they largely deviated from the anticipated values. By an extension of a published study (Imai et al., 2012), using actual field oil and methane under different pressure conditions, we found that diffusion coefficients were smaller under higher pressure conditions. This implies that the higher the density and viscosity of the oil, the smaller the coefficients. Moreover, the diffusion processes in heavy oil systems were almost 10 times slower than those in light oil systems. Considering a tight fractured gas condensate reservoir and a heterogeneous heavy oil reservoir, a flow case study with gas injection accounting for the tuned coefficients was numerically simulated. The simulation study showed that the fractured case with molecular diffusion resulted in an oil recovery improvement of almost 10% as compared to the case with no molecular diffusion. The improvement was, moreover, larger than that in the case without experimentally tuned coefficients. This result implies that accurate estimation of the molecular diffusion coefficients under reservoir conditions is crucial for estimation of oil recovery with gas injection.
An Innovative Technique for Estimation of Permeability of Shale Gas Reservoirs
Authors: Yuan Yudong , Rahman Sheik , Wang Junjian , Doonechaly Nima Gholizadeh
Published: November 2015

Characterization of flow processes in multi-scale porous system (nanopores to mesopores) in tight rocks, such as the shales, is challenging because of the coexistence of various flow regimes in the porous media. Although some methods based on dusty gas model (DGM) have been applied to determine the apparent gas permeability of shales (Javadpour 2009, Freeman et al. 2011, Sakhaee-Pour and Bryant 2012, Chen et al. 2015), they fail to describe gas flow process in nanopores in detail. In this paper, we present an innovative methodology for estimating apparent gas permeability of shales by coupling multiscale flow mechanisms. The Lattice Boltzmann Method (LBM) with effective viscosity and a general second-order boundary condition is used to analyze the various flow regimes involved in the single microchannel. The desirable agreement between the simulation results and that from the DSMC studies for the rarefied flow prompts the application of the derived correction factor for estimating permeability of shale gas reservoirs. In order to realize this, the porous medium is represented by a bundle of capillaries with diameters determined by mercury injection capillary pressure (MICP) curves. The porous flow is simulated by Darcy's law with derived correction factor; the surface diffusion of adsorption gas in kerogen pores is simulated based on Langmuir model and Fick's law. An extensive integration based on fractal dimension is performed to estimate the total flow rate and thereby the apparent permeability of typical shale samples. MICP and a transient pressure pulse technique are employed on 7 shale samples to obtain the pore size distribution and permeability. The result shows that the estimated gas permeability matches well with the measured permeability with a 20% variation, indicating that the physics based model presented in this paper is highly effective in predicting gas permeability of tight formations, such as the shales.
Effects of Sample Holding Time, Storage and Preservation on Sample Integrity for Source Rock Analysis: Experimental Results
Authors: Bhosle Balaji , Crozier Peter , Flynn Kevin
Published: November 2015

The effects of sample holding times, sample storage, and sample preservation in the laboratory have considerable effects on the final results of standard SRA (source rock analysis). This research was primarily directed to determine the potential effects of delay in processing and analysis. For example, over time; will the volatile hydrocarbon content (S1) and hydrocarbon generative potential (S2) [which is used to calculate Hydrogen Index (HI) and Production Index (PI)] show consistent results? In total fifteen samples were analysed for source rock analysis using the industry standard SRA-TPH/TOC instrument to test the effect of wait time on SRA results.

Results from experiments conducted for variations in the sample holding time in shale rock samples show statistically meaningful changes. The samples that were processed and analyzed within one to three days show significant S1 and S2 values whereas the same samples analysed after four weeks and subsequently after three months show declining trends. The change between the four week and three month analysis is almost negligible. The noted average change in S1, S2 and S3 values ranges between 2% to 14%, 1% to 9% and 0% to 12%, respectively. Since the HI and PI are calculated from the S1 and S2 values, they also show lower values, averaging 5.26% and 3.75%, respectively.

The same samples were also analyzed for clay contents and brittleness. The samples with high clay content and lower brittleness index show greater decline in the S1 and S2 values, and conversely, low clay content at higher brittleness show less decline in the S1 and S2 values. Therefore, more lithified/cemented samples show less variability over long holding times. In addition, the experimental results obtained indicate that sample holding time also demonstrate there are considerable effects on the final results when the S1 and S2 values are especially high.

In order to avoid the sample degradation and data consistency issues, there is an industry-wide need to reassess sample collection, storage, processing, and analysis time. Although the data set analyzed may not be sufficient to make broad conclusions concerning the changes in the data, as there are several other confounding factors to take into account. However, the approaches demonstrated in this study will assist future researchers with more comprehensive data sets.
Production Simulation of Complex Fracture Networks for Shale Gas Reservoirs Using a Semi-analytical Model
Authors: Jia Pin , Cheng Linsong , Huang Shijun , Xue Yongchao , Ai Shuang
Published: November 2015

Interacting with the pre-existing natural fractures, multi-stage hydraulic fracturing along horizontal wells creates complex fracture networks. Gas flow for these fracture networks in shale gas reservoirs is significantly complex due to more flow mechanisms, including the interplay of flow between the interconnected fractures, seepage, diffusion, adsorption/desorption and stress-dependent permeability within the fractures. The objective of this paper is to present a semi-analytical model for production simulation of complex fracture networks coupled with above processes in shale gas reservoirs. The fractures within the networks are represented explicitly rather than idealized as a dual-porosity medium. The model dynamically couples a numerical fracture network model with an analytical reservoir model. This approach allows us to simulate the networks with complex geometry and varying fracture conductivity. Seepage, diffusion and gas adsorption/desorption in the matrix are taken into account. Fracture deformation is implicitly coupled with numerical network flow model to reflect stress-stress dependent of fracture permeability. A synthetic fracture network is simulated in the rectangular reservoir. The results indicate that for the same fracture network volume a very low conductivity will generate very large pressure drops in the fractures surrounding the wellbore resulting in less effective fracture network compared to high conductivity. The contribution of diffusivity flow of the matrix is not appreciable on the log-log plot for transient response for km=10−4md. The adsorption compressibility has a great influence on the middle and later production periods and gas recovery may be significantly enhanced by adsorption/desorption. When the fracture is closed with pressure drop, the permeability is still sufficient to transmit the volume of fluid available to flow due to the infinite-conductivity effect compared with the shale-matrix for km=10−4md. Finally, a field example from the Barnett Shale shows the capacity of the model to simulate more complex fracture networks in shale gas reservoirs.
Plugging CSG Wells with Bentonite: Review and Preliminary Lab Results
Authors: Towler Brian F. , Firouzi Mahshid , Mortezapour Amin , Hywel-Evans Paul D.
Published: November 2015

Oil and gas wells are required to be plugged when the production of these wells is no longer economical. Cement is the current standard method for plugging wells. However, this process has limitations because cement is expensive and prone to cracking and unsealing. This paper aims to review and investigate the use of a naturally occurring clay called bentonite to plug CSG wells in Queensland as well as oil and gas wells in general. Bentonite is cheaper and easier to handle and when hydrated it creates a more reliable plug because it is malleable and self-healing when disturbed.

We also experimentally and theoretically investigate the mechanisms for failure of bentonite plugs. The plug failure mechanisms can be determined by comparing the measured dislodgement pressure and the predictions of the theory developed in our group. Based on our preliminary results we found that the hydrated plugs can be made significantly stronger by restricting the expansion space. This allowed us to measure the internal swelling pressure at 8 MPa which corresponded to measurements reported in the literature at a reduced density of 1.6755 g/cm3.
The Next Generation of Water and Fluid Management for Unconventional Exploration and Appraisal: Building on the Successes of Queensland Coal Seam Gas
Authors: Hudson Nick
Published: November 2015

Water for the unconventional Exploration and Appraisal (E&A) lifecycle, from Spud to Plug and Abandon, has always presented a fundamental challenge. None more so than the recent major unconventional play of Queensland's (QLD) Coal Seam Gas (CSG).

Water management has always been an important surface component of E&A, from supporting drilling and stimulation effort, through to managing production water. However, in Queensland, water became a critical obstacle, initially driven by compliance and stakeholder issues. It became apparent methodologies from North America and even the conventional Central Australia experiences did not offer solutions to the challenge. Water issues from both regulator and landholders were more significant than expected. The consequence of this led to delays in data acquisition and significant cost escalation of planned E&A activity. Ultimately the boarder industry responded to the challenge by understanding the issues, then applying a fair amount of innovation.

Moving forward the general challenge still stands for new unconventional plays. Solving this requires recognition that water management is often a localized issue. Particularly as many new unconventional resources are in remote and isolated areas, with little supporting infrastructure. The McArthur Basin Shale Gas Play, in Australia is an obvious example.

This paper presents the challenges and learnings in E&A water management from the QLD CSG experience. One of the key learnings is that planning was critical. In recognition of that fact, a simple five-part water field development planning tool is proposed to support successful E&A. With costs of E&A now more important than ever, and not withstanding the enduring need to maintain the operator's license to operate (both regulator and community), getting all aspects water management right is a fundamental key to success.
An Evaluation of Coiled Tubing Fracturing Compared to Traditional Completion Techniques in Horizontal Wells
Authors: Lewis Bryan J.
Published: November 2015

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.
Isotherms, Gas Contents and Diffusion Coefficients of Coals and Shales
Authors: Gray Ian , Wood Jeff , Shelukhina Iuliia , Zhao Xiaoli
Published: November 2015

The measurement of gas content of coals has been dominated by the standard methods of core desorption described by ASTM D7569 and AS3980 (1999). In this paper the limitations of these procedures are discussed with particular reference to the partial gas pressure the gas content is being referred to. Because the gas content is always quoted as an absolute value measured to an undefined gas partial pressure as opposed to a value at atmospheric pressure it brings into question the nature of the isotherm model being used at pressures below atmospheric. The generally accepted Langmuir model is found to be lacking at these lower pressures and alternative options are considered.

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.
Geological and Petrophysical Characterization of Tight Oil Reservoirs: A Case Study from Upper Triassic Yanchang Formation, Ordos Basin in North China
Authors: Zhao Huawei , Ning Zhengfu , Zhao Tianyi , Yu Lei , Zhang Rui , Dou Xiangji , Hou Tengfei
Published: November 2015

To evaluate the exploration potential of tight oil reservoirs in the Upper Triassic Yanchang Formation, a combined research was done to investigate the source rock distribution, diagensis, pore systems, petrophysical parameters. To begin with, the horizontal distribution and vertical thickness of the reservoir were clarified with data from well drilling and regional geological background. After that, X-ray diffraction and scanning electron microscopy experiments were conducted to study the pore types and morphologies. Then the pore size distribution was calculated based on mercury injection capillary pressure data. Finally, porosity and permeability were tested. Also, the causes of the tight sandstone, the controlling factor of petrophysical parameters and the fracability were discussed.

The Upper Triassic Yanchang Formation is rich in tight oil reserves and shows good exploration potential. Horizontally, reservoir is accumulated at the centre of the lake deposit with an area of 7.5×103 km2; vertically, reservoir is in Chang 6, Chang 7 and Chang 8 member with total depth 25–80m, among which Chang 7 member acts as the main source rock. Sediments are mainly fine grained sand, cements including clays, calcite and dolomite. After early stage mechanical compaction and late stage cementation, the reservoir becomes quite tight. Pores are classified into four types, residual interparticle pores, intraparticle grain pores, clay dominated pores, and micro fractures. Residual interparticle pores and clay dominate pores are main pore types for storage and flow; existence of micro fracture can improve permeability and is a good indication of fracturing potential. Porosity is between 6.12–13.80% and air permeability normally smaller than 0.3 mD, the early stage compaction is the main reason of porosity reduction, while combination of compaction and cementation results in dramatic decreasing in permeability. This reservoir can be commercially developed with horizontal well and hydraulic fracturing stimulation.

This study provides a workflow to fully characterize the storage and transport properties of a tight oil reservoir, and the workflow can act as reference to other similar reservoirs.
Effect of Wettability Alteration on Productivity Enhancement in Unconventional Gas Reservoirs: Application of Nanotechnology
Authors: Naik Saurabh , You Zhenjiang , Bedrikovetsky Pavel
Published: November 2015

In unconventional water-wet gas reservoirs with very low permeability, water entrapment or blockage can occur near the wellbore due to the capillary end effect, resulting in low gas production. A reduction in capillary forces through wettability alteration of reservoir rock surface is proposed as an effective approach to reduce water blockage and enhance gas production. The method can be applied to accelerating dewatering and preventing drilling and fracturing fluid leak-off as well. Analytical models for steady-state water-gas linear and radial flows are developed in the current paper. The effects of contact angle on capillary pressure and relative permeabilities have been included. The new model is validated using experimental data. Applications to fully and partially treated regimes show the competition between viscous and capillary effects on productivity of gas and water, which leads to an optimal contact angle for the maximum productivity index for each phase. This study shows the potential for optimising unconventional gas productivity through wettability control. Application of nanotechnology to rock wettability alteration is proposed.
Applicability Comparison of Nuclear Magnetic Resonance and Mercury Injection Capillary Pressure in Characterisation Pore Structure of Tight Oil Reservoirs
Authors: Zhao Huawei , Ning Zhengfu , Zhao Tianyi , Che Fei , Zhang Rui , Hou Tengfei
Published: November 2015

Applicability of experimental techniques is critical to accuracy of results. In this paper, a comparison was made between nuclear magnetic resonance and mercury injection porosimetry to clarify their applicability in pore structure characterization of tight oil reservoirs. Five tight sandstone core samples from the Upper Triassic Ordos Basin in China were collected for nuclear magnetic resonance, pressure-controlled porosimetry and rate controlled porosimetry. The T2 relaxation time distribution of nuclear magnetic resonance was compared to the pore size distribution calculated by a combination of pressure-controlled porosimetry and rate-controlled porosimetry.

The T2 distribution of sample Z211-1, N78-3 and T2-1 show three peaks, i.e. ~ 1 ms, ~100 ms and ~1000 ms. However, the T2 distribution of sample Z147-2 shows unimodal and that of sample Z117-3 shows bimodal, and the amplitudes are much smaller. For pressure-controlled porosimetry, the average final intrusion mercury saturation exceeds 80%, while the extrusion efficiency is low, indicating large pore-throat radius discrepancy. For rate-controlled porosimetry, the final intrusion mercury saturation averages 48.20%, and most of the mercury enters throats. The nuclear magnetic resonance T2 distribution and pore size distribution by a combination of pressure-controlled porosimetry and rate-controlled porosimetry show reasonable agreements. Rate-controlled porosimetry tends to overestimate the radius of pores, while some clay dominated pores are not water saturated. These might be the causes of differences between the nuclear magnetic resonance T2 distribution and the mercury injection porosimetry pore size distribution.

It is concluded that a combination of PCP and RCP can provide more accurate pore size distribution of tight sandstone, while nuclear magnetic resonance seems to be a fast and economical method.
Successful Utilization of Surface Jet Pumps at Gas-Oil Separation Plants
Authors: Al-Khalifa H. H. , Peeran S. , Koleshwar V. S.
Published: November 2015

Gas-oil separation plants consists of two or three separation stages to separate oil, water and associated gas. Oil flows to the stabilization plants and water to injection wells, while associated gas is sent to gas plants for further processing. At Plant A, the high-pressure (HP) gas has adequate pressure to freely flow to gas plants without compression; however, gas from intermediate pressure (IP) and low-pressure (LP) stages flows to a nearby stabilization facility to be compressed along with gases released from stabilization and sent to the same gas plant where HP gases were directed to.

Utilizing a surface jet pump (SJP) at Plant A was found to be an energy saving and economically attractive alternative as it enabled sending the IP gases directly to the gas plant without gas compression by using HP gas as a motive fluid.

This paper will discuss in detail the design basis of this application and few challenges faced during the test. Also, it will cover the wide range of operational envelop that the surface jet pump covered during the validation trial. The application was found to be successful and resulted in substantial savings in compression cost.

Advantages of using SJPs include using already available fluid energy within a process stream, no moving parts, zero maintenance, zero power or fuel gas usage, small footprint and varying layout configurations. SJPs are well suited to liquid ingestion and to changes in process conditions (without greatly affecting performance).
Unique Technology for 3D Integrity Monitoring of Subsea Pipes
Authors: Instanes Geir , Pedersen Audun , Simonetti Francesco
Published: November 2015

This paper discusses the latest developments in non-invasive corrosion/erosion monitoring with guided wave tomography for subsea and topside asset management. There are many technologies available for corrosion/erosion monitoring topside, but much fewer subsea. The subsea environment is difficult to access for instrument maintenance and verification of monitoring data, and many pre-installed systems have proven to be of little use. A technology for non-intrusive wall thickness monitoring based on ultrasonic guided waves has been available for permanent installation topside and subsea for some years. A subsea retrofit solution has also been delivered. The system utilizes ultrasonic guided Lamb waves to monitor wall thickness over extended areas; much larger than any spot measurement system with a comparable number of transducers. The ClampOn CEM® received a Spotlight on Technology award at the 2012 OTC. Monitoring data from this instrumentation platform are well suited as basis for tomographic processing to produce two-dimensional wall thickness maps of pipe sections. A technique has been established that holds promise of unprecedented capability for wall thickness monitoring, offering previously unavailable real-time imaging of eroding wall surfaces. Points of minimum wall thickness can be located, their depths can be measured, and their developments over time can be tracked.
Surface-Enhanced Raman Spectroscopy for Rapid and Cost-Effective Quantification of Amines in Sour Water
Authors: Benhabib Merwan , Tran Kim P. , Kleinman Samuel L. , Zherebnenko Natalya , Peterman Mark C.
Published: November 2015

Organic amines are corrosion control agents that increase pH and scavenge corrosive contaminants. Their presence in sour water can lead to the formation of heat-stable salts, resulting in potentially corrosive deposits. The measurement and monitoring of amines in sour water requires chromatographic techniques, with corresponding complexity, training, and expense. A rapid, field-deployable method to measure amines in refinery process waters would speed testing time, increase the temporal data resolution, and allow for immediate response and process adjustment. We present a new approach to amine measurement using Surface-Enhanced Raman Spectroscopy. By mixing a pH-adjusted sample with gold nanoparticles, a strong amine signal is obtained with a potential for sub-100-ppb detection. An optimized approach for ppm-level detection reports 27.8±3.9-ppm and 76.4±5.1-ppm for ~25-ppm and ~75-ppm samples, respectively, with more than one-hundred tests per sample over a three-month period. This method is at least as accurate, sensitive, and repeatable as ion chromatography, yet can be performed in the field in under five minutes.