bluuebunny/crossref_metadata_2025 huggingface dataset:
Chemostratigraphy and Sequence Stratigraphic Investigation of the Lower Silurian - Upper Ordovician Hot Shale, Southeastern of the Sichuan Basin
Authors: Wright Milly , Mu Guoyan , Wang Shiqian , Liu Bao , Davies Emma , Singh Navpreet
Published: November 2013

Abstract

The southeastern Sichuan Basin is potentially one of the most prolific Shale Gas play in China. There is an obvious and pervasive stratigraphic correlation (high Gamma reading) at the lower Longmaxi Formation, which has been defined as the Hot Shale interval. However, it is difficult to make a meaningful detailed geological correlation within the Hot Shale interval due to relative poor data coverage of seismic and petrophysical log signatures.

Chemostratigraphy under the right geological setting is a proven tool that uses changes in bulk elemental composition to understand controls on reservoir quality, such as sediment provenance (proximal or distal) and paleo-environment in order to establish a chemostsratigraphic correlation for a given interval. For this study, a total of 377 cuttings and 20 core samples from the Upper Longmaxi, Lower Longmaxi to Wufeng (Hot Shale) and Linxiang/Baota formations of 4 exploration wells have been analyzed using ICP-OES and ICP-MS. Final integrated analyses have been made by combining with petrophysical logs, TOC, X-Ray Diffraction (XRD), petrography and Scanning Electron Microscope (SEM) data.

Prior to any interpretation, cutting sample quality was checked by comparison between chemical gamma (using U, K and Th data from the sample) and downhole gamma which suggested the cutting samples were largely representative of the formation drilled. Elements and element ratios can be directly linked to the XRD data which reflects the influence of sediment lithology/ mineralogy variation, it also demonstrates the elemental data is qualified to be used.

The enrichment factor of vanadium (EFV), which is sensitive to changing paleo-environments, suggests the lower Hot Shale was deposited in an overall more anoxic environment compared to the overlying and underlying formations. Within the Hot Shale interval, there is a positive relationship between TOC and EFV, indicating that TOC preservation is predominantly controlled by changes in paleo-environmental settings in the southeastern Sichuan basin. It further implies that EFV can also be used as a proxy for modeling TOC to assist in predicting lateral changes of paleo-environment between widely spaced data points.

Changes in the relative amount of terrigenous input (TiO2 + Al2O3 + K2O + Na2O) and biogenetic silica (SiO2/Zr) are also modeled, the former being related to changes in sediment provenance and the latter to depositional conditions. Terrigenous input increases upward with the lower Hot Shale having lower terrigenous content indicating a period of sediment starvation in relatively deep water. The high biogenic silica contents in the lower Hot Shale interval are consistent with the pervasive presence of sponge spicules in the microscope view of thin sections. The high biogenetic silica contents results in the sediments being more brittle, thus favorable for Hydraulic Frac Stimulation.
Post-Shutdown Recovery Behavior of Horizontal Coalbed Methane Wells in the Bowen Basin
Authors: Gilbert Tonna , Ali Ehtesham , Mazumder Saikat
Published: November 2013

A number of coalbed methane (CBM) to liquefied natural gas (LNG) projects are currently advancing in Australia, among which is the Arrow LNG project. To ensure reliable supply to an LNG plant, production availability of the integrated CBM system consisting of a large amount of wells and production facilities needs to be understood, including the behavior of CBM wells after planned and unplanned shutdowns. This paper provides an analysis of post-shutdown recovery behavior of horizontal CBM wells based on a large volume of field data. There is no known published work on shutdown recovery for CBM wells to date, so there are no comparison data.

Arrow Energy has produced CBM for domestic consumption since 2004 and currently supplies about 20 per cent of Queensland's gas from fields in the Bowen and Surat basins. A shutdown recovery analysis is conducted on Arrow's Moranbah Gas Project (MGP) in the Bowen Basin. Field data for 6,436 shutdown periods are used, including: gas rates, water rates and bottomhole pressures (BHP). The following effects on recovery times are analyzed: shutdown duration, pre-shutdown water rate, pre-shutdown gas-water ratio, and pre-shutdown producing days.

The results indicate that approximately 70% of wells, shutdown for one day, return to 90% of their previous gas rates within one day. Approximately 20% wells recover in a week and the remaining 10% wells come back to 90% of original rates within 2 months. Furthermore, shutdown periods longer than five days have significantly higher recovery times. Wells with a lower water rate and higher gas-water ratio before the shutdown return to their pre-shutdown gas rate faster than wells with a higher water rate and lower gas-water ratio. Also, late life wells recover faster than wells in early production life.

These findings are critical for planning well shutdown and ramp-up strategies (well classifications and priority lists) to manage required gas supply during the operational phase of integrated CBM-LNG projects.
Unconventional Oil Production from Underground Coal Gasification and Gas to Liquids Technologies
Authors: Perkins Greg , du Toit Ernest , Koning Bert , Ulbrich Andreas
Published: November 2013

The combination of underground coal gasification and gas to liquids technologies offers the potential to produce high quality synthetic oil and associated products from deep coal reserves that are unsuitable or uneconomic to extract using conventional methods. This paper provides a summary of achievements made over the past five years at the world's only Demonstration Facility where UCG and GTL technologies have been successfully integrated and operated to produce synthetic oil products. The process of UCG is described, along with the key features of the proprietary technology developed and operated by Linc Energy. A number of the experiences gained from operating multiple underground gasifiers over several years are outlined. The GTL facility at the Demonstration facility is described, along with selected results from operations of the gas conditioning unit and the synthesis of liquid hydrocarbons using the Fischer-Tropsch process. The products generated from the facility are summarised. In the second half of the paper an outline is provided of a commercial UCG to GTL facility and some of its characteristic performance parameters. Technology selection and project execution considerations for commercial scale plants are discussed. Finally, the global potential of UCG as a method for producing unconventional gas from deep coal is discussed and some of the challenges and opportunities for producing unconventional oil via integration of UCG and GTL are summarised.
Alternative Polysaccharide Fracturing Fluids for Harsh Reservoir Conditions
Authors: Zhou Jia , Legemah Magnus , Beall Brian , Sun Hong , Qu Qi
Published: November 2013

Guar and its derivatives are the most commonly used gelling agents in fracturing treatments. In the last few years, enormous price swings and supply shortages of guar have posed major challenges for service companies and operators. In addition, the fluid volumes in fracturing treatments have increased substantially, while water supply has become more of a public concern. Rather than paying to treat and dispose of produced and flowback water, operators would like to recycle it in subsequent stimulation operations. Carboxymethylcellulose (CMC) has been recommended as an effective alternative to guar system. However, CMC system can only be crosslinked under low pH environment and their application is limited with formation temperature up to 250°F and also in high quality water.

A readily available polysaccharide, Carboxymethylhydroxyethylcellulose (CMHEC) is presented in this paper to address the challenges of making a fracturing fluid in harsh reservoir conditions like high formation temperature and high-TDS produced water. Using a produced water sample with TDS over 200,000 ppm and total hardness as CaCO3 over 40,000 ppm as representative water, laboratory testing has demonstrated that the new polymer can be fully hydrated within 3 minutes, similar to the hydration rate of guar in fresh water. Furthermore, the resulting linear gel can be crosslinked with metal crosslinkers to achieve excellent rheology at various formation temperatures. The crosslink can also be delayed to minimize pipe friction. The fluid is compatible with other common stimulation additives, including scale inhibitors. Conventional oxidizing breakers can be used to effectively break down the fluids, leaving no formation or proppant pack damage.

This paper will discuss the evolution of the technology and present rheology results at various formation conditions.
Integration of Quantitative Rock Classification with Core-Based Geologic Studies: Improved Regional-Scale Modeling and Efficient Exploration of Tight Shale Plays
Authors: Marino Sonia , Herring Shanna , Stevens Kimberly , Petriello John , Handwerger David , Suarez-Rivera Roberto , Woodruff William
Published: November 2013

Assessments of unconventional plays typically rely on single property to property relationships to define drivers for economic success. These may include fracture corridors, organic-rich facies, and high thickness-permeability products. Unfortunately this concept has been rather elusive. To a large extent, the industry uses conventional reservoir thinking to explain unconventional field observations. This results in great confusion and the generation of local experience that cannot be transferred elsewhere. A new mental picture of tight shale plays is proposed which recognizes the role of geology to generate substantial variability in material properties across seemingly similar depositional units. Understanding that subtle changes in rock composition and texture associated to geologic processes (deposition, tectonics, and diagenesis) are responsible for substantial changes in reservoir quality and completion quality properties, and understanding that log responses are also affected by rock composition and texture allow defining a new pattern for relating geology, material properties, and logs, quantitatively.

A regional evaluation of reservoir quality, completion quality, and production potential was developed for the Haynesville shale over an area of 7,185 square miles. The study was supplemented with comprehensive core studies including measurements of petrologic, geochemical, petrophysical, and mechanical properties across all facies. Rock classes with unique properties of reservoir quality and completion quality were identified based on high-resolution logs, and related to the geologic model built from core observations. The distribution of the rock classes was then tracked throughout the basin. This approach allowed mapping the reservoir potential in a very effective manner.

Integrating geology with material properties on a rock class by rock class basis provides remarkable knowledge needed for the field development. While core extractions and seismic surveys are often conducted in isolated areas, this method also provides background information for selecting the most strategic locations for supplemental cores and seismic data. This methodology can optimize the early exploration phase of unconventional plays.
Recycling redundant coreholes
Authors: Young S. R. , Norton G. F. , Foo K. J.
Published: November 2013

In 2009, QGC (a BG Group business), began developing coal seam gas (CSG) feedstock for its new Liquefied Natural Gas (LNG) plant and required a subsurface model and field development plan to underpin the project's investment case. Fundamental to the modeling process was acquiring appropriate data to calibrate subsurface models and enhance confidence in their predictive quality. As part of an integrated reservoir surveillance strategy, specific pressure and temperature monitoring wells were required.

This paper describes the successful lab and field implementation of an innovative completion technique that converts suspended coreholes into reservoir and aquifer monitoring wells. The coreholes are re-entered and vibrating wire piezometers (VWP) attached to capillary coil tubing, are positioned and cemented in place alongside selected reservoir intervals. The well is then "plugged and abandoned" and the lease remediated to leave only a small surface footprint for the data logger and telemetry. The cement is effectively impermeable to fluid movement but possesses sufficient permeability to transmit reservoir pore pressure to an adjacent piezometer.

Recompletion of coreholes provides a cost-effective means of acquiring valuable downhole data while eliminating the need to drill a bespoke monitoring well in the same vicinity. Data over the reservoir interval (the Walloon Coal Measures) can inform and help resolve reservoir properties on a regional scale, understand contribution to flow and provide data points to pressure-match a reservoir model. Data over the aquifers within Springbok Sandstone and Gubbermunda Sandstone enables estimates of any CSG production effects on groundwater.
Regulatory Concerns for Sub-Surface Modeling of Unconventional Reservoirs
Authors: Tyson Stephen
Published: November 2013

Since computer modelling of petroleum reservoirs was developed in the late 1980's, the technique has become almost ubiquitous. But, most of the experienced geoscientists that really understand the capabilities of these models are sceptical about the predictive capability of reservoir modelling and acknowledge that even their best models are either highly subjective or are quantified guesses. In recent years a trend has been emerging in which reservoir models are increasingly demanded by regulatory authorities prior to development approval which raises the question: "What is a good reservoir model?"

This paper considers the concept of a ‘good model’ since, without clear guidelines on good models it is difficult to determine who is qualified to build a model or who is qualified to audit a model. The process of verification and validation of reservoir models is then considered and petroleum industry practices are compared with computer modelling in other industries. There is increasing public concern over the development of unconventional resources, and industry concern over possible litigation, so this paper suggests a set of acceptance criteria for sub-surface models with the aim of identifying procedures that are auditable, defendable and robust for adoption by regulators.

During the development of these criteria, a number of key areas in modelling workflows were identified as being of critical concern to the construction of a ‘good model’; model scope, prior elicitation, scale issues, and multiple scenarios. These four areas are discussed in detail and their impact on model quality and predictive capability are assessed. It is hoped that the topics highlighted in this paper encourage enlightened discussion, and ultimately consensus, on the concept of good quality sub-surface modelling of unconventional resources between the regulators and the industry.
Waterflooding in the Eagle Ford Shale Formation: Experimental and Simulation Study
Authors: Morsy Samiha , Sheng J. J. , Soliman M. Y.
Published: November 2013

Waterflooding is the cheapest and most profitable secondary recovery method that has been used for more than seventy years for conventional oil reservoirs. However, few studies have been done on its viability on unconventional tight formations especially shales. The objective of this paper is to study the potential of waterflooding in Eagle Ford shale formation through water imbibition experiments on reservoir rock samples and simulation study using Eagle Ford shale published data. In the experimental study, distilled water and 2% KCl brine solutions were examined to recover oil from different Eagle Ford shale reservoir samples. The samples were 2.54 to 3.81 cm in diameter and 0.762 to 5.08 cm in length. First, we studied the porosity of samples using CT Scanning. The average porosity of the studied samples varied from 1% to 5%. Second, we studied the spontaneous imbibition of the different used samples in distilled water and 2% KCl for one week. During the spontaneous imbibition, the maximum oil recovery was 19% from the samples placed in distilled water against 12% from the samples placed in 2% KCl brine solution. The higher recovery achieved by the distilled water was due to cracking from clay swelling which was not observed with the 2% KCl brine solution. The samples exposed to distilled water for one week during the spontaneous imbibition experiment showed more tendency to break down when low confining pressure was applied due to clay swelling. The simulation study using Eagle Ford reservoir fluid and rock data along with completion data revealed a good potential for waterflooding using closer spacing between the oil producer and the water injector fractures that forced the injected water to invade the hydraulic created fractures, natural fractures, and the reservoir matrix as well, which maximized the oil recovery. Collectively, our experimental and simulation study showed a good potential of waterflooding in Eagle Ford shale formation.
Determining Physical Properties of Unconventional Reservoir Rocks: from Laboratory Methods to Pore-Scale Modeling
Authors: Gerke Kirill M. , Vasilyev Roman V. , Korost Dmitry V. , Karsanina Marina V. , Balushkina Natalya S. , Khamidullin Ruslan , Kalmykov Georgy A. , Mallants Dirk
Published: November 2013

With the rapid progress of imaging methods it is now possible to obtain detailed rock structure information on different scales, ranging from nanometers to micrometers. Such knowledge facilitates use of pore-scale modeling approaches to predict numerous physical properties based on three dimensional structural data. Pore-scale modeling approaches can simulate different processes in the rock under natural conditions (pressure, temperature, etc.), which are more difficult to simulate in the laboratory. This is especially important for unconventional reservoir rocks such as the Bazhen formation siliceous rocks (black shales) used in this study. Based on X-ray microtomography and SEM imaging we develop a detailed categorization of different types of porosities (including micro, i.e. larger than µm size, and nano, i.e. sub-micron size, porosities) for samples of Bazhen siliceous rocks. Standard pore-scale modeling techniques do not account for different flow regimes within different pore sizes. Thus, we develop a pore-network model with different physics of gas flow for micro- and nanoporosity. High-resolution images are used for stochastic reconstructions of 3D structure and subsequently used for modeling of gas permeability. Resulting permeability values are in a good agreement with gas permeabilities measured for Bazhenov siliceous rocks. Finally, we present a framework to model gas permeability of unconventional reservoir rocks using multi-scale 3D structure information based on microCT scans and high resolution SEM/FIB-SEM imaging techniques.
Technical Aspects of Risking and Valuation of Shale Reservoirs
Authors: Ingsoy P. B. , Chandler A. S. , Lie O.. , Hashemi N..
Published: November 2013

This paper focuses on valuation of shale based opportunities, arguing that the valuation process should be decision driven and model based, grounded in Bayesian principles. Risk should be controlled in order to maximize value. Using a decision tree to structure the valuation, we demonstrate that a method based on hypothesis testing can be utilized to determine the probabilities associated with chance nodes. It is shown that the probabilities depend on the scope and quality of the appraisal program. The risk level posterior to a chance node is discussed and calculated by Bayesian inversion. It is shown that the model underpinning the valuation must be updated posterior to chance nodes according to Bayes theorem. Failure to do so may lead to underestimating the value of the opportunity. Finally we discuss the use of simple truncation as an approximate method for updating the model after a pilot production phase.
A North American Review of Commercial Shale Plays; Have We Learned Anything Besides Serendipity?
Authors: Shelley R. F. , Mullen M. J. , Minner W. A.
Published: November 2013

When evaluating mud rock completions one is quickly struck with the complexity of the task. Mud rock "shales" by their very nature can be problematic to evaluate given the wide variation in geology, rock properties, and reservoir characteristics, not to mention the effect of multi-fractured horizontal well completions. Quite often, the reservoir characteristics between an economic well and an uneconomic well are very similar, further compounding the problem. So, what can we learn by taking another look at North American shale plays to help identify the more productive shales, improve economics and reduce the cycle time bringing this resource to market globally? Sometimes, the simple measurements we make at the wellsite can be very indicative of the things we don't measure very well, like the degree of natural fracturing and the interconnectedness of porosity. The subject material and the information discussed in this review was derived from the study of the characteristics and data from hundreds of completions with production results for shale wells in North America.

The findings presented show the results of formation evaluation and analytical evaluation which have proven to be good indicators of well productivity and hydrocarbon recovery. Many of these methods have been underutalized by the industry for shale evaluation and completion optimization.

Past successes in unconventional resource arenas are sometimes viewed as the result of seredipity. However, that has not been the case – past successes have evolved, in some cases over periods of years. A comparison of learnings from the Bakken and Eagle Ford show some interesting commonalities that help identify economic wells from subeconomic wells, as well as the most productive completion intervals in lateral wellbores. These findings and evaluation methodologies can readily contribute to the global hunt for unconventional reservoirs, and evaluation / optimization of their development strategy..
Calibrated Mechanical Earth Models Answer Questions on Hydraulic Fracture Containment and Wellbore Stability in Some of the CSG Wells in the Bowen Basin
Authors: Pallikathekathil Zachariah John , Puspitasari Ratih , Altaf Iftikhar , Alboub Mohamed , Mazumder Saikat , Sur Subhodip , Scott Michael , Kubenk David , Gan Thomas
Published: November 2013

The Coal Seam Gas (CSG) industry is currently focused on the large-scale development of a number of Liquefied Natural Gas (LNG) projects in Queensland, Australia. Arrow Energy is one of four proponents undertaking to develop such a project, with a focus on the Surat and Bowen basins. Arrow Energy also supplies gas to power stations, mineral refining facilities and ammonium nitrate plants in north Queensland. They are committed to maintaining the supply to these domestic customers and to the growing international gas market through the LNG project at Gladstone, Australia through its CSG projects.

The wells discussed in this paper are situated within Arrow Energy's tenements in the northern Bowen Basin. The targeted coal measures in the region usually occur at depths between 230m to 500m below the surface. A number of wells have been drilled in these coal measures and completed either by open-hole, horizontal drilling or, less frequently, hydraulic fracturing. To maximize the productivity, and thus success of these projects, there is a distinct need to understand the wellbore stability of horizontal wells as well as the potential for hydraulic fracture containment in the target formations.

Rigorous one-dimensional Mechanical Earth Models (1D MEMs) were constructed utilizing:

A complete suite of wireline logs, processed and interpreted for the purpose of construction of the models; Rock mechanics laboratory tests; Closure pressures obtained from Diagnostic Fracture Injection Tests (DFIT); Drilling-induced borehole failures when drilling the wells.

The 1D MEMs were constructed for utilizing data acquired specifically for the construction of the models. The models reveal the variation of maximum horizontal stress direction, coal properties in the various layers and contrast in stresses between the coal seams and inter-burden formations.

This paper presents the workflow used in the construction of the 1D MEMs for the CSG project applications, and the results obtained. The particular focus is on the following:

Data acquisition strategy (logs that were acquired for the construction of the 1D MEMs). Rock mechanics laboratory tests performed, the results obtained, and how these results were utilized in calibrating the 1D MEMs. Closure pressure estimates derived from well tests (DFITs), and how these results were utilized in calibrating the minimum horizontal stress. Borehole image log interpretation and characterization drilling-induced features (break out and drilling-induced fractures) that yield the direction of maximum horizontal stress and for calibrating the wellbore stability models. Predominant strike of fractures in the coal from advanced sonic tool.
Investigating Hydraulic Fracturing in Tight Gas Sand and Shale Gas Reservoirs in the Cooper Basin
Authors: Scott M. P. , Stephens T.. , Durant R. H. , McGowen J. M. , Thom W. W. , Woodroof R. A.
Published: November 2013

The majority of discoveries in the Cooper basin have been structural traps on regional highs, with significantly less information available from the deep tight sand and shale plays. Recently, exploration and appraisal of the large, prospective gas resources in the deep troughs began. While these plays have been known for some time (Hillis et al. 2001), data has only recently been presented detailing the unconventional targets in the Nappamerri trough (Pitkin et al. 2012). This paper focuses on unconventional reservoirs within the southern Cooper basin, specifically, a southern extension of the Nappamerri trough and the Mettika embayment, part of the Tenappera trough.

Senex Energy began to review the potential of the unconventional reservoirs in its Cooper basin acreage in 2010. This paper focuses on three wells, Skipton 1, Kingston Rule 1, and Hornet 1, which were hydraulically fractured in early 2013. In the well planning stage of the project, it was identified that sufficient data needed to be collected to characterize both the formation and hydraulic fracturing behavior. The requirement for fracturing diagnostics was critical because of the complex nature of hydraulic fracturing within the Cooper basin. To manage these unknowns, the data that were collected included core testing, diagnostic injection tests on most intervals, surface tiltmeters to measure fracture azimuth and orientation, radioactive (RA) tracers to infer fracture height, and chemical tracers to estimate the flowback contribution from each stage.

The results showed high treating pressures and near-wellbore pressure loss (NWBPL) in many stages of the fracture treatments. Generally, the lower the fracture gradient, the easier the job was to place and the better the reservoir quality. The RA tracers showed good containment in the one well in which they were used, with heights of 20 to 60 ft. The main barriers to height growth appeared to be changes in lithology. The surface tiltmeter results showed an azimuth that was different than expected from borehole breakout data in the basin. This has been seen in other studies in the Cooper basin. While the exact reason for this requires additional work, possible explanations are discussed within the paper.
Application of Open-hole Diagnostic Fracture Injection Test Results to Regional Stress Interpretation in Bowen Basin Coals
Authors: Scott M.. , Mazumder S.. , Gibson M.. , Probst P..
Published: November 2013

Diagnostic fracture injection testing (DFIT) has become an established method of well testing in low permeability unconventional reservoirs – particularly in shales and coal seam gas (CSG). As well as providing in-situ measurements of permeability and reservoir pressure, the test allows estimation of the closure pressure (and fluid loss characteristics) for the formation under investigation, which is assumed to be a measure of minimum horizontal stress (σh).

Arrow Energy is currently conducting a wide-scale exploration and well testing programme in the Bowen Basin region of Queensland, Australia, in support of its planned CSG to liquefied natural gas (LNG) project. This programme is mainly focussed on evaluation of formations within the Moranbah and Rangal Coal Measures; these are typically present as thick, low permeability zones.

Traditional Drill Stem Test (DST) and Injection Fall-Off Test (IFOT) results have proven unreliable within such low permeability and under-pressured reservoirs. The limited drawdown generated by DSTs in such formations has historically been an issue for these, and other, reservoirs. Similarly, difficulties have been encountered with regard to the appropriate management of IFOT injection rates in the Bowen Basin coals, which can fracture at very low rates; the resultant diagnostic typecurves needed for analysis of such a "failed" test have tended to introduce an unnecessary level of uncertainty in the results.

At present, the preferred exploitation method for these formations is extended-reach, open-hole, horizontal in-seam wells. As such, very few instances of cased-hole completions are available. Whilst the DFIT technique has previously been widely applied in cased-hole completions, largely due to its prevalence as part of hydraulic fracture stimulation treatment in North America, its application has been extended successfully to open-hole testing as part of this programme. Arrow has to date completed over 140 open-hole DFITs in this region, with an approximately 80% success rate in interpreted parameters with reasonable confidence.

The results of this programme have been incorporated into a basin-wide interpretation of regional stresses and subsurface properties. These results have been used, in combination with Mechanical Earth Models (MEM), to evaluate optimal lateral well orientation, hydraulic fracture treatment design, as well as the mapping of variable stress gradients in an effort to better understand the distribution of permeability trends across different geo-domains.
Fracturing Stimulations Improve Oil Well Performance in Deep Tight Glutenite Reservoirs of the Shengli Oilfield
Authors: Guo Jianchun , Gou Bo , Liu Yuxuan
Published: November 2013

The glutenite oil reservoirs with target stratum between 3400 and 4000m TVD in Shengli oilfield in China are low core permeability within the range of 0.015-0.3mD, which needs to be stimulated to achieve commercial production. These reservoirs have thick pay intervals (gross pay thickness up to 80 meters in some wells), and the massive hydraulic fracturing (MHF) was widely applied with high-rate and large-scale proppant volume since 2007. However, post-fracture production responses showed the MHF weren't always effective in these reservoirs.

This paper shows a new technique to stimulate these tight reservoirs with better economic results. It involves two steps including perforation optimization and MHF with proppant density varying. Due to the difference of reservoir properties in the vertical direction, it is required to perforate the pay section within a short interval to ensure that the fracture could penetrate the pay zone. Besides, MHF with low, medium and high density proppant improves the proppant placement in the vertical direction, owing to the difference of proppant falling velocity and the proppant convection among carrying fluid. This method will enhance fracture conductivity comparing with using the same density proppant.

The novel technique has been successfully applied to four wells in Y104 Zones of the Shengli Oilfield. The five wells have better post-production than the other three wells with single density proppant. Net pressure matching and post-fracture pressure build-up testing were conducted to evaluate fracture geometry and conductivity. The results of post-fracture analysis and post-production evaluation demonstrate the benefits of this new fracture treatment.

This paper presents a field case of a novel stimulation method in tight glutenite reservoir with large thickness. The proposed method solves one of the key fracturing technology difficulties in these reservoirs and improves stimulation performance, effectively promoting the economical development of such oil filed in China.
Coal Seam Gas Field Management: Well Performance and Production Forecasting During Shutdown and Recovery Operations
Authors: Magee S.. , Ogilvie T.. , White C..
Published: November 2013

This paper presents the results of a study into the post-shutdown recovery behaviour of coal seam gas (CSG) wells and its application to estimating long-term field turndown capacity incorporating the impact of well performance recovery postshutdown.

Queensland, Australia is currently host to a number of CSG to liquefied natural gas (LNG) projects under development. These projects aim to develop Queensland's vast CSG resources to supply domestic and international gas markets. However, the need to build field deliverability prior to the availability of export gas markets presents a significant challenge. CSG wells must be dewatered while gas production may be constrained. The ability to manage and forecast production performance in field turndown scenario is therefore critical.

A study of production data from CSG production interruption events was conducted to determine how wells reacted to turndown of gas production rates. The study considered various production management strategies including partial choking and complete shut in of selected producers.

Implications of the work include identification of criteria for selecting wells that are suitable for long-term turndown, the formulation of operational guidelines for minimising adverse post-shutdown production impacts, and estimation of long-term field turndown capacity through the application of the study results to a field production model.
Best Pumping Practices to Optimize Dewatering in CBM wells: Lessons Learned Developing Raniganj East Field, India
Authors: Pant Himanshu
Published: November 2013

Dewatering is required to remove water from the coal seams so that bottomhole pressure (BHP) is reduced to a critical point where gas will begin to desorb from the coal. Production Data analysis of over 100 wells which includes both vertical and deviated in Raniganj East Coalbed Methane (CBM) field, India indicates that wells were not dewatered continuously. This was mainly due to the fact that the wells go on workover and extended periods of pump downtime result in re-saturation of the cleat and fracture system with water, thereby inhibiting gas production. So starting and stopping pumping resets the hydrostatic back pressure and water saturation profiles to initial conditions in the reservoir while the gas content remains unchanged, thereby requiring more pumping to achieve the previous level of gas production.

An attempt was made to analyze the problem and through production surveillance of past four years production history, various reasons why continuous dewatering was not achieved were pump failures due to high torque, low torque, low pump efficiency and erratic loading conditions. The causes of these pump failures were gas locking, rod/tubing unscrew, stator damage, hole in tubing, plugged intake screens and insufficient motor cooling, etc.

This paper discusses best practices to dewater CBM well after rich experience gained by operator in CBM Raniganj East field from series of trial of artificial lift ESP and PCP pump run in individual wells with design modification by using tailpipes and provides specific recommendations and pump operating parameters to dewater effectively and continuously from both vertical and deviated well.
Influence of Fracturing Fluid and Reservoir Temperature on Production for Complex Hydraulic Fracture Network in Shale Gas Reservoir
Authors: Cohen Charles-Edouard , Weng Xiaowei , Kresse Olga
Published: November 2013

Production from shale reservoirs depends greatly on the efficiency of hydraulic fracturing treatments. Cumulative experience in the industry has led to several best practices in treatment design, which have improved productivity of these reservoirs. Nevertheless, shale reservoirs still bring challenges to stimulation engineers, due to the complex physics involving interactions with natural fractures, stress shadow effects and proppant transport in complex fracture network.

One of the challenges regards fluid and proppant selection, in particular, the issue is how to achieve the desired fracturing fluid viscosity inside the fracture for optimum proppant placement into an expanding complex fracture network. The rheological properties of the fracturing fluid depend on its temperature history, hence understanding the temperature distribution in the hydraulic fracture network is a key consideration for a successful treatment and a more accurate fracture prediction.

This paper investigates the relation between reservoir temperature, fracturing fluid properties and production through fracturing-to-production simulation workflow. The paper first presents a temperature model implemented into the UFM model, which is a comprehensive complex fracturing simulator for shale reservoirs, accounting for interaction with natural fractures, stress shadow effects, and proppant transport in a complex networks. Based on the fracture geometry, proppant placement, and reservoir properties, a semi-analytical production model UPM is used to estimate the production.

This workflow is used to first understand the temperature distribution in the expanding fracture network and understand its evolution as a function of several parameters such as reservoir temperature and rheological properties of the fracturing fluid. Then the associated production forecast provides guidelines on how to achieve optimum proppant and fluid selection based on the reservoir temperature for maximizing production.
The Microseismic Monitoring of Hydraulic Fracturing of a CBM through Simultaneous Use of Downhole Monitoring Tools in the Stimulated and an Offset Well A Case Study – Sanga Sanga CBM, Mahakam Delta, East Kalimantan
Authors: Halinda D.. , Weatherall G. D. , Sesaro A. W. , Nugraha H.. , Collecott D. J.
Published: November 2013

Microseismic hydraulic fracture monitoring uses state-of-the-art downhole seismic tools to record microseismicity from multi-staged hydraulic fracture stimulations in Coal Bed Methane (CBM) completions. This method uses an acoustic method to map in three dimensional space and time the geometry and propagation of fractures during a hydraulic fracture stimulation treatment. The technique has been used for some time in monitoring fracture stimulation in shales and other formations but has had limited use in coals for CBM production.

Microseismic monitoring of hydraulic fracture stimulations in coal seams presents significant challenges as the ductility of coal produces low intensity individual microseismic events which can be difficult to record. Using an offset well to record the microseismic events may result in some uncertainty due to varying degree of attenuation by the coal seam. Additionally, successful recording of fracture stimulations in CBM wells typically requires the monitoring well to be relatively close to the well being stimulated and this often prevents downhole monitoring being applied to these wells. A microseismic monitoring tool that can be placed in the treatment well during the fracture stimulation provides additional information and potentially improves the data quality. Furthermore, two monitoring tools which simultaneously record microseismic events in the in-well and offset wells provide independent data for comparison and increase the quality and confidence of spatial location data.

The Sanga-Sanga Block which is as a very large conventional gas producer in East Kalimantan is now growing as a potential CBM resource. The coal seams in Sanga-Sanga, East Kalimantan are contained in a complex formation of interbedded sandstone, siltstone, carbonaceous shale and coal and have been subject to initial attempts to stimulate the coals for CBM production by hydraulic fracturing.

This paper examines the operational challenges of the simultaneous use of in-well and offset well microseismic monitoring tools in the Sanga-Sanga coal in Indonesia and compares the techniques and overall results and makes recommendations and suggestions for future microseismic coal monitoring.
Comparative Study of Open Hole and Cemented Multistage Vertical Completion Technologies in the Permian Basin
Authors: Keener Brett , Lohoefer Darrell , Snyder D. J. , Ezeldin Saiff
Published: November 2013

The Permian Basin is one of the top five resource plays in the United States and consists of a number of stacked pay zones. Two of these formations, the Wolfcamp shale and Bone Spring (Wolfbone), together deliver a pay zone thickness of 1,000 to 1,500 ft. They are made up of several different layers of organic rich shales intermingled with sandstone and siltstone. Horizontal completions in the shales are just beginning and have yet to be proven; however, operators are successfully exploiting the reserves through vertical wells.

While a mature exploration area, the completion of the thick shale intervals is a new target formation. To date, two vertical completion methods have been utilized to gain access to hydrocarbons: open hole multistage (OHMS) fracturing systems and the conventional cemented liner, "plug and perf" (CLPP) method. This paper compares 30-, 60-, 90-, and 180-day production results from 12 vertical wells in Reeves County, Texas completed with OHMS systems and 33 offset wells completed with the CLPP method. The system details, fracture methods used, as well as the cost and operational differences are discussed.

By comparing these two methods, this paper highlights OHMS as a long-term solution for operators completing vertical wells in stacked pay. The production, operation and cost comparisons of the two completion methods will provide theoretical and practical arguments to assist in designing a completion. The results of this study contribute to the technical conversation of how to economically produce a vertical well.
Coupled Water Flow and Heat Transport in Seasonally Frozen Soils with Snow Accumulation
Authors: Kelleners T.J.
Published: November 2013

A new numerical model was developed to calculate coupled water flow and heat transport in seasonally frozen soil and snow. Separate equations were presented to describe both unsaturated and saturated soil water flow. The effect of dissolved ions on soil water freezing point depression was included by combining an expression for osmotic head with the Clapeyron equation and the van Genuchten soil water retention function. The coupled water flow and heat transport equations were solved using the Thomas algorithm and Picard iteration. Ice pressure was always assumed zero, and frost heave was neglected. The new model was tested using data from an existing laboratory soil column freezing experiment and an ongoing field experiment in a high‐elevation rangeland soil. A dimensionless impedance factor describing the effect of ice pore blocking on soil hydraulic conductivity was treated as a calibration parameter for both cases. Calculated values of total water content for the laboratory soil column freezing experiment compared well with measured values, especially during the early stages of the experiment, as was also found by others. Modeling statistics for the rangeland field experiment showed varied performance for soil water content (RMSE = 0.02–0.06 m3 m−3; modeling efficiency [ME] = −4.06 to +0.72) and excellent performance for soil temperature (RMSE = 1.0–2.1°C; ME = 0.93–0.98), in accordance with earlier results with an older version of the model.
Pedophysical Models for Resistivity and Permittivity of Partially Water‐Saturated Soils
Authors: Wunderlich Tina , Petersen Hauke , Attia al Hagrey Said , Rabbel Wolfgang
Published: November 2013

Geophysical field surveys can be used for mapping soil properties such as clay and water content. For this the choice of adequate geophysical pedo‐transfer functions (GPTF) is a still debated question because of ambiguities of influencing factors. To investigate the applicability of different GPTFs to typical central European soils, we conducted laboratory measurements on 23 samples. The results are datasets of electrical resistivity and dielectric permittivity as a function of water content and partly temperature. We used these data to validate and improve existing GPTFs. For the relationship between permittivity and water content, we applied published empirical regressions, volumetric mixing, and effective media models. All models show low RMSE (0.3−6.8l%, v/v), but the curvatures of the data points are not reproducible by the empirical models. The volumetric mixing and the effective media models can fit the trend of the data points for sandy soils but not for clayey soils. To improve these models, we propose a modification to the Hanai–Bruggeman‐type effective media approach. It uses the permittivity of almost dry soil as a background and embeds stepwise increasing amounts of water. It turned out that our approach yields satisfying fits with respect to both data trends and RMSE (0.3–1.5l% v/v). Based on this approach we define a joint model for permittivities and resistivities, which yield RMSE of only 0.7 to 1.4% (v/v)—better than most published models. Our validations show that the temperature effects on electrical resistivity can be reliably corrected using existing empirical relationships.
Two‐Dimensional Coupled Hydromechanical Modeling of Water Infiltration into a Transversely Isotropic Unsaturated Soil Region
Authors: Wu L.Z. , Selvadurai A.P.S. , Huang R.Q.
Published: November 2013

The partial differential governing equation governing fluid infiltration into an unsaturated transversely isotropic porous medium was developed by considering mass conservation, Darcy's law, and the elastic deformability of the porous skeleton. Analytical solutions for two‐dimensional coupled infiltration in an unsaturated porous medium of finite extent were obtained using a Fourier transform technique. The analytical formulation was used to examine the two‐dimensional infiltration and evaporation problem for a transversely isotropic unsaturated porous medium. This study provides a comparison between the analytical solution and computational estimates for a two‐dimensional coupled infiltration problem in a transversely isotropic deformable porous region where there is recharge at the surface. The results indicate that the pressure head changes occur most rapidly when the unsaturated porous medium is hydraulically isotropic.
Soil Water Dynamic Modeling Using the Physical and Support Vector Machine Methods
Authors: Lamorski Krzysztof , Pastuszka Tomasz , Krzyszczak Jaromir , Sławiński Cezary , Witkowska-Walczak Barbara
Published: November 2013

Comparison of long‐term daily prediction of soil water content at different depths of soil coming from two models, one physically based (HYDRUS‐1D) and the other being soft‐computing technique (Support Vector Machine), has been done. The models used provide quite accurate prediction for soil moisture content, especially in the most important layers for crop growth—those close to the surface. The RMSE of estimations of the volumetric soil water content in topsoil made by the Support Vector Machine (ν‐SVM) based model was 0.035, 0.030, and 0.021 cm3 cm−3 for depths of 5, 10, and 25 cm, respectively, while the physically based model had RMSE values of 0.042, 0.049, and 0.045 cm3 cm−3 for the same depths. Our results showed that the ν‐SVM modeling approach can be used for estimations of soil water content changes in time with the accuracy comparable of to the one of the physically based models.