bluuebunny/crossref_metadata_2025 huggingface dataset:
A New Intervention-less Completion System using Radio Frequency Identification (RFID) Techniques
Authors: Yuan Feng , Blanton Eric , Mason Jane , Murdoch Euan
Published: June 2014

With the increase in drilling activity in new subsea and deep water exploration and development, a reliable means of intervention-less completion technology has become a major consideration in helping to reduce operational risk and achieve economic exploitation of new hydrocarbon reserves. Although intelligent completion methods have been in use for some time, the communication system they require can be expensive and time consuming and the need for a simpler, more cost effective, method of intervention-less well completion and management is clearly an attractive option.

To simplify the completion process, a new system has been developed which uses the well tried and trusted communication method known as Radio Frequency Identification (RFID). RFID is a reliable well proven technology which is used in countless applications in daily life; however its applicability to the oil and gas industry is only now beginning to be recognized. In this system tubing mounted control modules, which are capable of performing a number of key completion operations, are activated by simply dropping and pumping down RFID tags or, where pumping down is not possible, by the application of pressure cycles.

This system consists of several primary components as follows: Battery powered control module with antenna and processors, motor, pumps and closed hydraulic reservoir.A circulating control valve functioning as a sliding sleeve.A hydraulic set packer.A barrier valve.

Using these modules all the operations involved in an upper well completion can be performed free of interventions.

This paper will give an introduction of RFID technology and present operational mechanism in detail for key accessories of this new intervention-less completion system; and also display one typical logic application of sequence of operations for a new intervention-less upper completion system.
IOR / EOR Operations: Can the recent developments in Intelligent Wells Technology Advance the concept?
Authors: Ahmed Usman
Published: June 2014

The short answer to the question if the recent developments in Intelligent Wells Technology Advance the concept of IOR /EOR operations as posed in the title is "yes". However, lets’ explore and allow the reader to decide for themselves. IOR / EOR operations and projects in general are expensive in nature and any cost saving opportunity and process optimization is welcome. This is the premise of this paper.

More than 70-80% of the world’s remaining conventional reserves are contained in fields that are already on production. IOR and EOR methods are needed to access even a fraction of these remaining reserves. Deployment of Intelligent wells and associated monitoring and maintenance in conjunction with IOR and EOR processes can be expensive and as such has been restrictive only to high end operations. The industry is faced with the dual edge sword syndrome: enhance productivity with lower cost system. This translates to the need for deploying efficient systems to monitor IOR / EOR operations. This paper specifically addresses this topic.

One of the ways to address the above scenario is to come up with an extremely reliable system that is electronic and IP based rather than hydraulic (the current tradition) to address the intelligent monitoring and control. Combining such system of data monitoring with the most up to-date reservoir simulation system using the Jewel Earth platform that allows the use of unstructured gridding can result in fast and accurate response to reservoir monitoring and response with the ultimate goal of enhancing the reservoir recovery factor. The paper uses field examples to illustrate the features as described.
A Real Case Study: "Efficient Monitoring and Evaluation the Superficial Production Network" - Litoral de Tabasco Asset
Authors: Mijares F.. , Molina E.. , Escalona C.. , Montes De Oca L. A. , Jageregger W..
Published: June 2014

The Litoral de Tabasco Production Asset (APLT) in Pemex southwest marine region has a technological solution of automated workflows which allow the operations department, captures all operational conditions, volumetric wells, production facilities and equipment. Furthermore, meters asset allows the generation of operational daily reports, as well as the integration of engineering workflows to estimate the production of wells daily and detection of faults of production in the wells that are published promptly on panels for monitoring the well production.

In order to support the current processes and future growth plans of APLT and standardization in nationwide PEMEX in the processes of both departments, Wells Operation (COPIE) and Design (CDE), a network model is created to integrate to existing operation data base which allows automating workflows to estimate production parameters, to evaluate scenarios and detect faults under current operation conditions.

The technological solution measures the impact caused by schedule shutdowns, increases or reduce the production in the pipelines, changes in the philosophy operation of network, incorporate the production in the flowline, backpressure or bottlenecks and provide an alternative method to estimate flowrates and pressures in each network node.

The interconnection with the existing operational data base permits the automatically update the network model, this process analyses the production facilities conditions continuously, as well as support assessment of development scenarios in order to generate recommendations to maximize profitability the Asset.
Deepwater-Reservoir Characterization by Use of Tidal Signal Extracted From Permanent Downhole Pressure Gauge
Authors: Wu Xingru , Ling Kegang , Liu Dexin
Published: June 2014

Permanent-downhole-gauge (DHG) technology has been used widely in deepwater-reservoir development in the last decade and is playing an increasingly significant role in real-time reservoir/well surveillance and management. Tidal signals extracted from this highly accurate and precise device can be used for reservoir characterization such as monitoring the changes of saturations and estimating rock/pore compressibility. Most previous works have treated tidal signals as pressure "noise," and little has been discussed on how to use tidal information in reservoir characterization.

This paper will address how to use the fast Fourier transform (FFT) to extract tidal signals and the theories and methods for processing the signal to achieve reservoir characterization. In addition, a couple of examples from a deepwater field will be discussed to illustrate how to use tidal information to estimate pore compressibility, monitor dynamic fluid-saturation change, and detect the presence of a secondary gas cap. This paper will show that FFT is a fast and reliable method for processing the DHG pressure data for tidal signals that can be used for reservoir characterization in multiple dimensions. Furthermore, the results (pore compressibility and saturation) obtained from the tidal signals are unique because they cannot be obtained in the laboratory, by simulation, or by direct measurement because of the scale affected by tides.
The Impact of Multiphase Flow on Well Testing Models in Gas Hydrate Reservoirs without Crossflow
Authors: Kome M.. , Amro M..
Published: June 2014

Gas hydrates will dissociate to gas and water at pressures below the equilibrium pressure or temperatures above the equilibrium temperature. Moreover, some hydrate reservoirs have considerable amounts of mobile gas and water coexisting with the hydrates in the formation. This implies, fluid diffusivity in such reservoirs is predominantly multiphase and hence addressing multiphase flow in such reservoirs becomes very vital.

Conventionally, most well testing models address diffusivity in porous media by assuming a single/dominant flowing phase or addressing the fluid phases separately. If a huge discrepancy exists between the fluid saturations, the fluid with the highest saturation could denote the dominant flowing phase, depending on the fraction flow model, and the correction with the multiphase model becomes trivial, as also seen with most conventional gas reservoirs with low water saturation. However, if the saturations of the different phases do not vastly differ from one another, multiphase well testing models give a more accurate prediction of reservoir behavior. The definition of the multiphase dimensionless time becomes very essential in predicting the diffusivity of the fluids and for well test designs.

The multiphase flow models developed here are based on mass balance and volumetric material balance approaches. The total mobility is derived for both the mass balance and volumetric material balance models, further related to fraction flow models. The total mobility model developed by Perrine, used by most reservoir engineering calculations is not addressed in detail for this work, as this does not fulfill mass conservation considered in this paper. Due to the non-linearity of the diffusivity equation, the multiphase diffusivity model addressed here includes pseudo-pressure and pseudo-time integrals. The solutions to the diffusivity equations for multiphase flow are given for both approaches. The differences between both models and their limitations are addressed and highlighted with illustrative examples.
Sweetspotting of the First Appraisal Campaign of Unconventional Resource Play in Kuwait
Authors: Narhari Srinivasa Rao , Al-Ashwak Samar , Kidambi Vijaya Kumar , Al-Ajmi Neema Hussain , Neog Nilotpaul , Rao Jonna Dayakar , Makki Musaed Yaseen , Narayan Acharya Mihira , Erkan Fidan , Dashti Qasem , Darous Christophe , Chakravorty Sandeep , Miller Stephen
Published: June 2014

Organic rich Kerogen layer of Lower Kimmeridgian to Upper Oxfordian age, deposited throughout Kuwait, is a TOC rich layer with varying TOC content between 2 to 20 wt% (in the vertical section) and having an average TOC of about 8 wt%. The depth of occurrence of this layer favorably places this zone to be having potential in rich gas condensate resource in the northern part of Kuwait. This layer occurs at a depth of 14000–16000 ft with a reservoir temperature of 270°–275°F, pressure of 11000 psi and average thickness of over 50ft. This is one of the main source rocks for majority of the oil and gas fields of Kuwait. This Kerogen section is penetrated through a number of vertical wells, as part of development of deeper reservoirs in this area, which offers an excellent opportunity to evaluate this section through core and open-hole log data. Because of the strong acoustic contrast with the overlying and underlying layers, this reservoir section is a very strong mappable seismic reflector.

As part of appraising the potential of this layer, as a resource play, a comprehensive success criteria has been worked out for location selection. An integration of all available geo-scientific data such as geochemical, 3D seismic attributes, petrophysical analysis, borehole image interpretations, geo-mechanical, core and mud logs has been carried out. The above data integration/analysis was combined with the success criteria, leading to selection of sweet-spots for planning the first dedicated horizontal well targeted on this layer.

This paper presents the success criteria worked out and the integration of data for high grading the locale – sweet-spots, for the first set of horizontal wells for appraising this deep HP-HT unconventional play of Kuwait.
Drainage Estimation and Proppant Placement Evaluation from Microseismic Data
Authors: Neuhaus Carl W. , Ellison Mary , Telker Cherie , Blair Keith
Published: June 2014

In this case study we outline how microseismic analysis can be used to optimize treatment design and determine the portion of the stimulated rock volume that should be productive. To begin, microseismic data was acquired with a permanently installed shallow buried array of geophones during the hydraulic fracturing of 17 wells in the Marcellus Shale. The processed results were used to conduct a multi-disciplinary study integrating geology, geomechanics, reservoir and completion engineering, and ultimately, production data. A stress inversion from focal mechanisms was performed, and correlations were made between hydrocarbon production and microseismic results. That work, in conjunction with the variability in the stimulation approach, was used to optimize the treatment design on an individual wellbore and on a field development scale. Treatment design analysis indicated optimum wellbore spacing, stage spacing and length as well as evaluated the vertical coverage of the treatment within the Marcellus. Incorporating information from source mechanisms, an event magnitude calibrated discrete fracture network (DFN) was modeled taking into account the seismic energy of the events, rock properties, the injected fluid volume and efficiency. Evaluating the placement of proppant inside the DFN enables distinction between the part of the stimulated rock volume (SRV) that contributes to production in the long term, and the part of the reservoir that was affected by the treatment but may not be hydraulically connected over a longer period of time. Finally, the permeability of the stimulated fracture system was calculated from the microseismic results. This allows for the evaluation of the drainage volume and estimation of production.
World's First Through-Tubing ESP Swap on Electric Line in Highly Deviated Wellbores
Authors: Kuck M.. , Albright J.. , Blount C..
Published: June 2014

Electric wireline and tractor equipment were chosen to perform through-tubing electric submersible pump change-outs in a remote location with limited access and equipment availability. Electric wireline was available on location where other rigless options such as coiled tubing could not be mobilized. This paper records the retrieval of through-tubing-conveyed electric submersible pumps (TTC ESPs) from three wells and their replacement in two of these wells using a highly adaptable tool string. The application of an existing tool implemented in a novel manner provided benefits to the operator and has potential applications for other operators maintaining through-tubing-conveyed ESPs in deviated wells. The pump assemblies were removed through tubing while the permanently installed equipment, such as seal, motor and cable, remained in situ. All wells contained three individual assemblies to be retrieved including a tubing stop, tubing packoff with check valve and knock-out pressure relief valve, and the pump assembly. The assemblies were re-installed in two wells and the wells placed back in production. The method described herein confirms electric wireline and tractor equipment as a viable alternative for rigless replacement of through-tubing electric submersible pumps.
The Bowland Shale in the Roosecote Borehole of the Lancaster Fells sub-Basin, Craven Basin, UK: a Potential UK Shale gas Play?
Authors: Hough Edward , Vane Christopher H , Smith Nigel J , Moss-Hayes Vicky L
Published: June 2014

A re-evaluation of the Roosecote Borehole, located in the northern part of the Craven Basin (northern England), places the Bowland Shale in a modern geological context and allows an improved understanding of basin evolution and shale hydrocarbon prospectivity. In northern England during the Early Carboniferous, rapidly subsiding sub-basins developed between local highs in the Craven Basin. Subsequently, during the thermal relaxation phase, a period of regional subsidence allowed thick accumulations, locally in excess of 500 m, of hemi-pelagic mudstone to be deposited as a transgressive systems tract.

The Roosecote Borehole is a stratotype section for the Bowland Shale Formation, located close to the northern basin- to- shelf margin of the Craven Basin. The upper part of the Mississippian (Lower Carboniferous) Bowland Shale Formation is the principal potential shale gas play in the British Isles. The Bowland Shale and other argillaceous units of the Craven Group are rich in organic matter, have a similar depositional style to coeval units in the USA including the world-class Barnett Shale of the Fort Worth Basin, Texas, USA. Throughout England, Wales and Ireland it is currently being investigated by several exploration companies, with at least 4 dedicated shale exploration wells now drilled.

Rock evaluation indicates the TOC at between 1.73 – 3.72 %. Many samples indicate a mixture of type III and IV kerogens; there was no evidence for type I or II kerogens found. Thermal maturity for the sequence is within the oil window, with results indicating liquid oil and wet and dry gas have been generated. However, an estimate of the organic matter transformation ratio of 0.36 (36% kerogen conversion to hydrocarbons being possible) compares poorly to the Barnett Shale. Consequently we conclude that the Bowland Shale within the Roosecote Borehole has some, but possibly lower, potential as a shale oil play.
Numerous Technological Improvements Slash Drilling Times in the Horn River Basin
Authors: Zafar Hammad , Ji Yiming
Published: June 2014

Drilling Performance has improved multifold in the Horn River Basin since the start of activity about four years ago. In its early days a typical well would take about 40 days to drill from spud to cementing the production casing. A range of improvements have happened over the course of last four years which have reduced the drilling time by a factor of 3 despite the wells getting more complex.

A number of different technologies have been applied in order to bring these improvements. Some of the examples are pad rig moving system, bigger drill pipe, rotary steerables, managed pressure drilling, high temperature motor elastomers along with time tested project management practices of performance monitoring and improvement by comparison with yardsticks established to challenge the status quo.

One such measure of performance is meters per day average achieved from spud to rig release. Some of the recent wells which were drilled to around 5000m accomplished 438 m/day which is an industry record in the Horn River Basin. This was not just a onetime feat. The same performance was repeated on the next two wells.

Drilling for Gas in Western Canada is challenged by the price of gas in the current economic environment. Cost cutting by performance improvement provides the means of meeting the challenges posed by this environment. In comparison to the early wells the recent performance offers a cost reduction of 40Million dollars over the course of a 20 well pad, which is significant in determining the net present value of the asset.
Logging Solutions for Completion Optimization in Unconventional Resource Plays
Authors: Wigger Eric , Viswanathan Anup , Fisher Kevin , Slocombe Robin , Kaufman Peter , Chadwick Casey
Published: June 2014

Successful United States shale plays are often used as a template for the drilling and completion strategies for newly emerging shale plays around the world. However, studies of production logs in the Barnett Shale, the Marcellus Shale, and the Eagle Ford Shale have shown that a significant percentage of perforations clusters are not producing quantifiable amounts of fluid or gas (Miller, 2011). Case studies designed to address this have shown that addressing the heterogeneity experienced near the wellbore (Wutherich, 2012) in combination with more focus on landing and staying in the best quality reservoir rock (Baihly, 2010) lead to more productive wells with a higher degree of perforation performance.

Many operators face the challenge of incorporating a completion optimization workflow into their completions that is both technically and cost effective. The desired completion system is one that incorporates as much information as needed for successful completion while being operationally unobtrusive. Refined techniques used to convey dipole sonic tools in cased laterals have been supplemented by a new generation of easily deployed tools capable of making density, neutron, resistivity, and sonic measurements in open hole. This gives operators a wide array of options that can fit into a completion optimization program.

This paper reviews the concept of optimized plug and perforation style completions as compared to the more frequently used approach of geometrically spacing stages and perforations. Reservoir quality and completion quality variables were used to design engineered completions in a multi-well study of Eagle Ford shale wells. The study used a cost effective work flow that is repeatable and portable in order to increase the effectiveness of hydraulic fracture treatments. The workflow is shown to improve overall production and well economics by increasing perforation efficiency.
Production Data Analysis of Multi-Fractured Horizontal Wells Producing from Tight Oil Reservoirs – Bounded Stimulated Reservoir Volume
Authors: Qanbari F.. , Clarkson C. R.
Published: June 2014

Multi-fractured horizontal wells (MFHWs) are the most widely used technology for producing tight oil and gas reservoirs. Production data from a MFHW may exhibit multiple linear flow periods including linear flow within the fracture, linear flow in the stimulated reservoir volume (SRV), and linear flow in the unstimulated region of the reservoir. This study focuses on an SRV containing infinite-conductivity hydraulic fractures and no fluid flow contribution from the unstimulated region. The existing analytical models for these flow periods have been developed based on the linearized form of the flow equation. However, these models introduce considerable errors in permeability estimation and production forecasts for tight oil reservoirs if they do not account for stress-sensitivity.

In previous work by the authors, the stress-sensitivity of permeability was incorporated into rate transient analysis (RTA) of tight oil reservoirs during transient flow period for wells containing a single hydraulic fracture. In this paper, the effects of stress-dependent formation permeability on the production data of MFHWs are studied. A new model is used to correct the conventional RTA techniques for these effects to improve permeability estimation and oil production forecasting.

This study shows that the conventional methods that do not account for stress sensitivity give less accurate results for MFHWs producing under a high pressure drawdown. The results show that the new method reduces the error of the conventional techniques significantly and provides a reliable strategy for RTA of MFHWs.

This study fulfills two important requirements of the tools for RTA of MFHWs; simplicity and accuracy. The strategy is to keep the conventional analysis routine unchanged, with a correction factor applied to account for the effects of the stress-sensitivity of permeability. The value of the correction factor is that it shows how far the conventional analytical methods are from the exact solutions. Further, the correction factor is used to remove the considerable error in conventional analyses.
Microseismic Waveforms and Velocity Heterogeneity: Towards Full-Waveform Location Algorithm
Authors: Angus D.. , Aljaafari A.. , Usher P.. , Verdon J..
Published: June 2014

Seismic forward modeling is an integral component of microseismic location algorithms, yet there is generally no one correct approach, but rather a range of acceptable approaches that can be used. Since microseismic signals are band limited, the length scale of heterogeneities can significantly influence the seismic wavefronts and waveforms. This can be especially important when subsurface heterogeneity is strong and/or vary on scales lengths equivalent of less than the dominant source wavelength. In this paper, we show that ray-based approaches are not ubiquitously suitable for all microseismic applications and hence we argue that for advanced imaging techniques in unconventional reservoir settings, ray-based algorithms may not be suitably accurate. Here we focus on exploring the feasibility of using one-way wave equations as forward propagators for full waveform event location techniques. One-way wave equations are capable of modeling the evolution of important and observable wave phenomena and could represent efficient full waveform modeling tools. As a feasibility study, we focus on the acoustic wave equation to explore efficiencies and compare traveltime and amplitude errors. However, the results have implications for one-way wave equations for elastic and anisotropic media.
Integrated Well Construction Approach for Exploratory Shale Gas Horizontals
Authors: Yadav Anurag , Qureshi Ahmad Shakeel , Khan Safdar
Published: June 2014

Horizontal wells with multi-stage fracturing are typically drilled in shale gas plays for them to become economically feasible to produce gas. Drilling long laterals in shale ushers wellbore stability challenges especially in build section due to hole packoff, tight hole, stuck pipe or lost circulation. These challenges result in considerable amount of nonproductive time (NPT) which needs to be minimized or effectively controlled for the play to be economically exploitable. In this paper, the authors present a multi-disciplinary integrated workflow to optimize well construction. Practical use and verification of this workflow was demonstrated by field examples where well-construction time was optimized by more than 50% on the first batch of horizontal wells drilled.
Direct and Inverse Methods for Determining Gas Flow Properties of Shale
Authors: Lorinczi Piroska , Burns Alan D. , Lesnic Daniel , Fisher Quentin J. , Crook Anthony J. , Grattoni Carlos , Rybalcenko Konstantin
Published: June 2014

Gas flow in shale is a poorly understood and potentially complex phenomenon. It is currently being investigated using a variety of techniques including the analysis of transient experiments conducted on full core and crushed shale using a range of gases. A range of gas flow mechanisms may operate including continuum flow, slippage, transitional flow and Knudsen diffusion. These processes, as well as gas sorption, need to be taken into account when interpreting experimental data and extrapolating the results to the subsurface. Several models have been published that attempt to account for these different processes. Unfortunately, these have a large number of unknown parameters and few studies have assessed the extent to which transient experiments may be used to invert for the key unknowns or the errors that are associated. Here we present a methodology in which various inversion techniques are applied to assess the viability of deriving key unknowns which control gas flow in shale from transient experiments with a range of noise. A finite volume method is developed based on the model of Civan (2010, 2011a,2011b) to mathematically model the transient gas flow in shale. The model is applicable to non-linear diffusion problems, in which the permeability and fluid density both depend on the scalar variable, pressure. The governing equation incorporates the Knudsen number, allowing different flow mechanisms to be addressed, as well as the gas adsorption isotherm. The method is validated for unsteady-state problems for which analytical or numerical solutions are available. The method is then applied for solving a pressure-pulse decay test. An inverse numerical formulation is generated, using a minimisation iterative algorithm, to estimate different number of unknown parameters. Both numerically simulated noisy and experimental data are input into the formulation of the inverse problem. Error analysis is undertaken to investigate the accuracy of results. A good agreement between inverted and exact parameter values is obtained for several parameters. However, it was found that the strong correlation between intrinsic permeability and tortuosity meant that it was not possible to accurately invert simultaneously for these two parameters. The workflow presented here can be readily applied to other gas flow models to assess the extent to which they can be applied to invert experimental data.
Assessing Mechanical and Petrographic Properties of Fine-Grained Formations From Samples Collected in Deep Oil Wells
Authors: Descamps F.. , Tshibangu J.-P.. -P. , da Silva N.. , Regnard S..
Published: June 2014

Gas shales are fine grained fissile detrital sedimentary rocks. But shale is often used as a catch-all term including different rocks with a non-negligible clay minerals content which leads to typical physical-chemical characteristics.

Several properties are generally assessed for shale gas plays (TOC, porosity…). However, regarding the access to the reservoir, drilling into the formations implies a good knowledge of their mechanical and petrographic properties. As classical cores are quite difficult to collect from deep wells, unconventional techniques using small samples are useful (Tshibangu et al. 1999). When dealing with hydraulic fracturing, the formation brittleness is to be assessed. Several estimators exist among which we propose the so named plasticity index determined from punching tests.

In the framework of a collaboration of more than fifteen years between the university and the drill bits manufacturer, samples coming from all over the World and associated with difficult drilling conditions have been collected and processed in the laboratory. This work involved thin section characterization and mechanical tests like FPMs abrasiveness, Shore hardness and punching tests. Recently, a database was then built in order to analyze the cumulated information (Descamps et al. 2013).

In the context of gas shales, this database includes various fine grained rocks like shales, claystones, fine grained sandstones (i.e. grain or crystal size below 125 microns). In this paper, two main axes are developed. First, we describe typical properties of fine grained rocks, especially when they are associated to difficult drilling environments. Then, we look to how those properties can be linked together. Particular interest will be taken on abrasiveness regarding the selection of drilling bits and on brittleness assessment in relation to hydraulic fracturing.
New Insights into Shale Fracturing Treatment Design
Authors: Gomaa Ahmed M. , Qu Qi , Nelson Scott , Maharidge Russell
Published: June 2014

Shale has certain characteristic features that make them difficult to evaluate in a traditional laboratory setting. The unique characteristics of shale formations include low permeability, existence of micro fractures, and sensitivity to contacting fluids. Advances in the testing of shale has remained relatively stagnant, which has led to the fact that many current shale fracturing practices and technologies are mainly determined by fracture model simulations, and experiences drawn from the stimulation of conventional formations. Therefore, the objective of this study is to develop an experimental setup to measure the hydraulic breakdown pressure associated with the development of fractures in shale cores, and to use this setup to study the effect of different parameters on the breakdown pressure, fracture shape development, fracture direction, from various fluid types and characteristics, injection rates, shale bedding directions, acid injection, and other variables in different systems.

Shale cores from a Mancos formation outcrop were evaluated in this study. Based on the experimental results, breakdown pressures in shale cores have a strong exponential relationship to fluid viscosity, where increasing fluid viscosity increases the breakdown pressure. Increasing the injection rate will reduce the pressure needed to breakdown the shale formation. Fracture complexity will increase by reducing the viscosity of the fluid. A shale core drilled in the parallel bedding direction was fractured at a lower pressure with a faster propagation compared to a shale core drilled in the perpendicular bedding direction. Additionally, a relationship between closure stress and breakdown pressure has been experimentally established and verified with existing mathematical models. Closure stress increases the breakdown pressure by a factor of 2.8.
Unconventional Well Completion Generates Significant Production Increase in Lateral Wells in Chicontepec Formation
Authors: Gutierrez Guillermo , Medina Eber , Perazzo Gerardo , Sierra Jose , Henriquez Carolina , Salguero Javier
Published: June 2014

Unconventional reservoirs, such as the Chicontepec basin in Mexico, require the stimulation of large volumes of reservoir rock to improve production results. A second horizontal well was completed successfully using multistage fracturing with an unconventional method in the basin. This well will be referred here as Coyotes 2H. Five fracturing stages were performed over the 900 m of lateral, each one using three spaced clusters of hydrajetted perforations. The first two stages were monitored using downhole microseismic monitoring. A 40% increase in production was achieved compared to the first lateral well completed in this field, which will be referred to as Coyotes 1H.

As the design changed from the first horizontal well, the second lateral used three times the number of perforation clusters, but the same number of fluid entry points (perforations) compared to the first completed lateral well. Five fracturing stages were pumped at 60 bbl/min placing a total of 3.2 million lbm of sand white and using 26,000 bbl of fluid; these volumes of proppant and fluid were similar to the first horizontal well. The treatment fluid was designed to improve the coverage of the reservoir using hybrid fluids consisting of linear and crosslinked gel to achieve a better stimulated reservoir volume (SRV). The first lateral was completed using crosslinked gel as the primary fracturing fluid.

Microseismic downhole monitoring allowed measuring the fracture geometry and verifying that the objectives were achieved. The main objectives were to determine if the fracturing treatments would generate upward fracture height growth into the Z-100 formation and compare the SRV measurement of Coyotes 2H to the results of the previously mapped Coyotes 1H lateral. The objectives were achieved during the treatment, and the production results were favorable because of the improvements in the completion process.
Mathematical Model for Stimulation of CBM Reservoirs During Graded Proppant Injection
Authors: Keshavarz A.. , Khanna A.. , Hughes T.. , Boniciolli M.. , Cooper A.. , Bedrikovetsky P..
Published: June 2014

A modelling-based prediction of well productivity enhancement for recently developed technology for stimulation of natural fracture systems in CBM reservoirs is presented. The proposed technology can also be used for productivity enhancement of gas wells in other unconventional reservoirs, i.e., shales and tight gas reservoirs. Injection of proppant particles with increasing size and decreasing concentration results in deep percolation of proppant into the natural fracture system, expansion of the stimulated zone and increase of well productivity index. A modified mathematical model for well indices during graded particle injection, accounting for stress changes in coal beds, is developed. The model is based on analytical solution for quasi 1D problem with coupling of axisymmetric fluid flow and geomechanics. The results of previous computational fluid dynamic studies have been used to determine hydraulic resistance due to proppant placement in the fractured system. Explicit analytical equations were derived for stress, pressure and permeability distributions, as well as for the well index during injection and production. Results of previous computational fluid dynamics studies were used to determine the hydraulic resistance resulting from proppant plugging in the fractured system. By applying the effect of proppant concentration and fracture deformation, a critical stimulation radius is introduced beyond which proppant placement decreases coal permeability and well productivity index. This model has been applied for a real field case, and the effect of injection pressure on well productivity index and stimulation radius is presented. The results show significant increase in productivity index due to graded proppant injection in CBM reservoirs.
The Application of Well Test Deconvolution to Wireline Formation Tester Pressure Buildup and Falloff Data to Improve Coalbed Methane Reservoir Characterization
Authors: Osman Magdy Samir , Thwaites Schlumberger, N.
Published: June 2014

Coalbed methane (CBM) reservoirs are a growing source of relatively clean energy in many parts of the world. CBM reservoirs are fundamentally different from traditional hydrocarbon reservoirs. Gas is adsorbed on the surface of the coal cleats and not stored in pores. Still, estimation of the permeability of the coal cleats is important in judging the potential producibility of a given coal seam.

Traditionally, CBM reservoirs are surface tested using injection or production techniques to access reservoir permeability (Clarkson and Bustin 2011). Recently, pressure buildup and falloff tests using the straddle packer module of a wireline formation tester have been used in CBM reservoirs to assess reservoir permeability successfully. However, low permeability, limited station time, or both have, in some cases, reduced the quality of the interpretation results.

Deconvolution techniques have been available for some time; however, few practical examples are available in the literature. The use of deconvolution will generally allow extracting more of the same data. The derivative response uncertainty is normally due to errors in estimating the reservoir pressure and the flow rate. Generally, wireline formation testers provide reliable measurements of the reservoir pressure and flow rate.

We applied deconvolution to pressure buildup and falloff for the first time on data acquired in a CBM environment with a straddle packer. The use of deconvolution has improved the permeability estimation from the different tests. We were also able to identify the limitations of the technique and the uncertainties in the analysis results.
Integrated Assessment of Pilot Performance of Surface to In-Seam Wells to De-Risk and Quantify Subsurface Uncertainty for a Coalbed Methane Project: An Example from the Bowen Basin in Australia
Authors: Zhao Chaobin , Xia Zhaohui , Zheng Kening , Duan Lijiang , Liu Lingli , Zhang Ming , Yang Yong , Lau Hon Chung , Sharma Vikram , Liu Xinying
Published: June 2014

This paper presents a detailed case study of using surface to in-seam wells to develop a major coalbed methane (CBM) field in the Bowen Basin of Australia. This study was novel in that special emphasis was given to quantification of subsurface property uncertainty and modeling of dynamic uncertainty. The result was the generation of recovery factor versus depth correlations which can be used to calculate the estimated ultimate recoverable.

In this work, a 3D box model around three pilot wells was extracted from the regional static model. To quantify key subsurface uncertainties such as permeability, both the Percentile and Confidence Interval Methods were used. Trends of laboratory-measured parameters like gas content, ash, Langmuir volume, permeability were established. Reservoir properties without measurements such as cleat porosity, desorption time and relative permeability were estimated based on rules-of-thumb, basin-wide analogue or educated guesses. A reservoir simulation model was built and production data from pilot wells were manually history matched. Parametric analysis was conducted to determine key parameters that significantly affect model history matching and forecasting results. Given the complexities of the coal reservoir and the non-uniqueness of the history match, Experimental Design was used to generate a population of simulation models that sampled the uncertainty range of key reservoir properties. This ensemble was reduced to include only those that matched the pilot wells’ production. With different combinations of reservoir properties thus obtained, recovery factor versus depth correlations were generated.

This study is a good example of early resource assessment critical to the field development planning of a major CBM field. It presents a systematic method to handle uneven distribution of often sparse subsurface data over a large geographic area which often confounds the CBM industry. Furthermore, this method may be extended to assess other well architectures like vertical, slant, horizontal, multi-branch, multi-lateral and hydraulically fractured vertical and horizontal wells.
Unlocking the Resource Potential of the Bowland Basin, NW England
Authors: Clarke Huw , Turner Peter , Bustin R. Marc
Published: June 2014

The Bowland Basin of NW England is a key part of the Pennine Carboniferous Petroleum System which is estimated by the British Geological Survey to hold over 1300 TCF of total original gas in place (TOGIP) of shale gas resource. The basin is a Lower Carboniferous (Dinantian) extensional basin which underwent at least two major phases of rifting and intrabasinal tectonics. The basin was inverted in late Carboniferous times and subsequent burial continued until mid or late Cretaceous time. The gas-bearing shale section is extremly thick (>6000 ft) intensly naturally fractured and relatively complex structurally. Ongoing geoscience studies are focussed on addressing the the intrabasinal sedimentary architecture of the Bowland Basin, structural configuration, reservoir properties and the current stress regime. The Preese Hall-1 shale gas discovery well provides an opportunity to assess the shale gas characteritics of the Bowland Basin and its resource potential. Based on extensive core and log data the shale gas resource is estimated to be approximately 1 TCF per square mile (29 BCM per square kilometre). The gas is methane rich with little carbon dioxide and the less thermally mature parts of the succession includes significant wet gases. The gas density (gas per unit volume) in the Bowland Basin compares favourably with producing shales in North America, however, the gas saturated succession is significantly thicker.

In this preliminary contribution we describe some of the basic properties of the basin including the stratigraphy and structure, rock properties and structural configuration along with our approach to the modelling the petroleum system and estimation of TOGIP. The gas resources of the Bowland Basin alone could make a significant contribution to UK energy supplies. Unlocking this resource potential requires understanding of the complex set of geological variables and devising a development strategy compatible with the social issues surrounding shale gas development.
An Overview of the Completion Challenges in a Tight-Gas Formation in Saudi Arabia
Authors: Leal Jairo , Duarte Jorge , Soriano Eduardo , Lopez Alfredo , Fatkhutdinov Damir
Published: June 2014

Tight gas refers to natural gas reservoirs that have very low porosities and permeabilities. Most of the tight-gas reservoirs presently being developed are sandstone formations, although carbonate rocks can also be tight-gas producers. The standard industry definition for a tight-gas reservoir is a rock with matrix porosity of 10% or less and permeability of 0.1 millidarcy or less, exclusive of natural fracture permeability. Unconventional gas resources, including tight sands, constitute some of the largest components of remaining natural gas resources in the Middle East and North Africa. Developing unconventional and tight-gas reservoirs will allow Saudi Arabia to better meet rising domestic energy needs.

During the past decade, conventional formations were stimulated successfully in Saudi Arabia using conventional completion techniques. However, as the development of existing fields continues into deeper formations and the exploration of new reservoirs is mainly toward unconventional reservoirs, new challenges are now faced, especially considering that lower permeabilities, higher stresses, and higher temperatures are experienced. An evaluation of the current techniques is necessarily in order to overcome the challenges in these extreme conditions.

This paper reviews the successful application of specific completion techniques and technologies being implemented in the development of tight-gas reservoirs currently being exploited in Saudi Arabia.
Microresistivity Image Driven Inversion of Nuclear Logs for the Evaluation of Unconventional Reservoirs
Authors: Whetton J. A. , Elkington P. A.
Published: June 2014

Density, photoelectric, neutron, and gamma ray logs are key inputs to the evaluation of unconventional resources. Each has a finite spatial resolution, and the properties of beds thinner than this cannot be measured directly but are (in principle) available from inversion if the logs’ response functions are known, and the thickness of each bed is known from an independent high-resolution source. An inversion method is described for beds with apparent dip angles less than about 60 degrees which uses pre-computed response functions from measurement-specific nuclear particle transport code models, combined with bed boundaries picked automatically from high-resolution microresistivity images rendered using a new technique developed for high dynamic range data. The method has application in thinly-bedded formations in general and has particular relevance in coal bed methane reservoirs where multiple thin high-contrast beds are common. Inversion results are known to be sensitive to uncertainty in bed thickness values, and constraining the inversion with information from high-resolution images is found to be highly advantageous in producing reliable results in beds as thin as 0.075m; this compares to the resolution of about 0.6m for standard porosity logs, and 0.2m for the high-resolution field logs. Inverted density logs show good agreement with core density values, and the integrity of inverted photoelectric, neutron porosity and gamma ray logs is judged to be good based on the similarity between field logs and logs reconstructed from inverted results, plus the high degree of agreement with properties of known marker beds. Inverted logs are also shown to provide improved differentiation between litho-types defined from combinations of logs using principal components analysis. The paper addresses an important source of uncertainty in the estimation of reservoir properties - namely finite spatial resolution - and in so doing reduces bias in volumetric calculations and associated net pay calculations.