bluuebunny/crossref_metadata_2025 huggingface dataset:
Computer‐Assisted Densitometric Image Analysis of Digital Subtraction Images: In Vivo Error of the Method and Effect of Thresholding
Authors: Brägger U. , Bürgin W. , Fourmousis I. , Schmid G. , Schild U. , Lang N.P.
Published: March 2012

The aim of the present study was to assess the in vivo error of the method as well as the effect of thresholding when obtaining and evaluating standardized periapical radiographs for computer‐assisted densitometric image analysis (CADIA). Twenty healthy volunteers participated in an experimental gingivitis study in which neither mechanical nor chemical plaque control was performed for 21 days. Two pairs of standardized periapical radiographs were taken at days 0 (baseline) and 21 (follow‐up), one from a maxillary area (15 volunteers) and one from a mandibular molar/premolar area (17 volunteers). Each baseline radiograph was digitized and its image displayed on a monitor. The follow‐up radiograph was then superimposed and digitized as well. After gray level correction, subtraction radiographic images were produced. The difference in gray level between the baseline and the follow‐up image was calculated within each region of interest (ROI) at each picture point (pixel). In bone ROI, changes in density reflected the amount of change due to methodological errors plus the basic bone remodeling over 3 weeks. For gingival ROI, changes in density reflected the methodological error plus a possible change in soft tissue density during the experimental gingivitis. Within all of the ROI, some pixels indicated a change in gray level. A change in gray level was then thresholded; i.e., only changes >5 and then >10 gray levels were registered and used for calculation of the CADIA values. With a threshold of 5, 44/45 maxillary bone ROI and 60/66 mandibular bone ROI showed a change in density, while 41/45 maxillary gingiva ROI and 26/66 mandibular gingiva ROI indicated a change in density. With a threshold of 10, 16/45 maxillary bone ROI and 12/66 mandibular bone ROI indicated a change in density, while 13/45 maxillary gingiva ROI and 1/66 mandibular gingiva ROI indicated a change. The amounts of changes in density calculated in the various ROI were low even when applying no threshold, ranging from −0.279 to 0.621. Applying a threshold of 5, the CADIA values ranged from −0.234 to 0.727. With a threshold of 10, the changes in density ranged from −0.318 to 0.133. In vivo, CADIA of standardized radiographs indicated change in density due to methodological errors. Application of thresholds may avoid false‐positive diagnoses. When applying CADIA in clinical research, the range of change to be expected due to methodological limitations as well as the threshold for true change should be evaluated. These thresholds may differ in various areas of the mouth, i.e., bone or gingival, maxillary/mandibular, anterior/posterior ROI. J Periodontal 1998;69:967–974.
Maximize Placement of Wells and Production in Unconventional Reservoirs: Part 2
Authors: Holdaway Keith Richard
Published: March 2012

Over the past decade, significant supplies of natural gas have been discovered in shale. While the development of new technologies has driven down the cost of gas extraction, pursuing natural gas in shale continues to be risky and capital-intensive.

Producers seek the most productive zones in their unconventional basins, as well as continued improvement in hydraulic fracturing processes. Decreasing costs and reducing risk while maximizing gas production necessitates innovative, advanced analytical capabilities that can give you a comprehensive understanding of the reservoir heterogeneity in order to extract hidden predictive information, identify drivers and leading indicators of efficient well production, determine the best intervals for stimulation, and recommend optimum stimulation processes and frequencies. Modeling, simulating and predicting well productivity requires integrated exploratory, predictive and forecasting capabilities underpinned by advanced analytical models to unlock the true potential of each wellbore. Without the critical insight enabled by integrated analysis to pair productivity analysis with economic feasibility, companies face significant risk and uncertainty when developing new wells or optimizing production of extant wellbores.

This paper walks through a case study implemented in the Barnett asset in the United States, exemplifying data mining workflows that successfully improved hydrocarbon production. We shall detail analytical methodologies to explicate the optimization of these assets as additional to those workflows expanded upon in SPE paper 149784 presented in Abu Dhabi at the Middle East Unconventional Gas Conference and Exhibition.1
Stimulation Unlocks Coalbed Methane: Lessons Learned in India
Authors: Pooniwala Shahvir Aspi
Published: March 2012

Although gas production from coalbed methane (CBM) wells has become an important source of energy in North America over last couple of decades, it still remains an upcoming area in India. India has the fourth-largest proven coal reserves in the world and therefore considerable prospects exist for exploration and exploitation of CBM. Development of CBM and other unconventional gas sources are currently a priority for India to meet its growing energy demand.

An effort has been made in this paper to review the lessons learned from the stimulation and production of Raniganj CBM field in India. Experiences from large number of CBM operations in the US and Australia have been useful in this regard, however several constraints specific to India had to overcome to make the campaign successful: India is an extremely cost-sensitive market.Location sizes are limited, making the logistics very challenging.Land acquisition problems, resulting in different drilling and field development strategies employed.Seasons/weather challenges in the northeastern part of India, where most of the CBM blocks are located.Proppant flowback is a problem due to lower closure stress.

This paper will review over 150 recent hydraulic fracture treatments in CBM wells in India. It will summarize different drilling and perforation strategies, completion practices, hydraulic fracturing design considerations, job execution, difficulties faced and solutions employed in India to overcome the difficulties. It will conclude with lessons learned that can be applied in future wells.
Casing Centralization in Horizontal and Extended Reach Wells
Authors: Sanchez Alfredo , Brown Christian F. , Adams Whitney
Published: March 2012

Long laterals being drilled today present new challenges in getting casing to bottom and achieving good zonal isolation. Casing centralizers play a key role in achieving these objectives and should be evaluated differently than they have been in the past.

A comprehensive methodology for evaluating, selecting, and running casing centralizers is described. This method is based on analyzing downhole conditions (formation type, borehole stability, etc.) in conjunction with specific drilling practices (bottom hole assembly design, hole cleaning procedure, etc.) to arrive at an optimum casing centralization program that will meet cementing objectives.

A manufacturer and an operator share their experience in the application of comprehensive centralization placement and torque and drag modeling. Also discussed is the evaluation and selection of casing centralizers including practices to increase the accuracy of these simulations. Particular emphasis is given to rotation while running and cementing casing. Post job analysis of actual rig data is discussed in an effort to arrive at more accurate friction factors for future wells.

In addition, custom laboratory testing and evaluation of running and restoring forces of bow-type centralizers is discussed.

The approach described in this paper can help reduce the compromise between getting casing to bottom and achieving good zonal isolation.
Testing Tight Gas and Unconventional Formations and Determination of Closure Pressure
Authors: Soliman M. Y. , Gamadi Talal
Published: March 2012

Experience indicates that applying the conventional testing techniques such as drawdown-buildup tests to unconventional reservoir may lead to non-unique answers. Diagnostic testing approach is now more commonly used in tight gas formations and unconventional reservoirs. Testing unconventional reservoirs, particularly hydrocarbon-bearing shale formations, presents considerable challenges. In addition determination of the fracture closure pressure is sometime elusive. This paper reviews those challenges faced in analysis of testing of tight gas and unconventional reservoirs both liquid and gas. Conventional testing and analysis methods, although applicable, are often impractical because of excessive test duration. Diagnostic fracture injection test (DFIT) has become the preferred option for unconventional formations. Several methods may be used for interpreting DFIT data. We examine those methods in detail and explore their relative strengths while interpreting field data. We also show ways to determine the fracture closure pressure under various reservoir and fracture conditions.
Effect of Sand Lens Size and Hydraulic Fractures Parameters on Gas in Place Estimation Using ‘P/Z vs Gp Method’ in Tight Gas Reservoirs
Authors: Bahrami Hassan , Rezaee Reza , Hossain Mofazzal , Murickan Geeno , Basharudin Naqiuddin , Alizadeh Nasser , Fathi Afshin
Published: March 2012

Low permeability and complexities of rock formation in tight gas reservoirs make it more complicated to predict well production performance and estimate gas recovery. To produce from the unconventional reservoirs in the case that formation rock is not sensitive to damage caused by liquid invasion, hydraulic fracturing is the most common stimulation treatment to improve the production to the excepted economically rate. In term of reservoir geometry, tight sand formations are normally consisted by the stacks of isolated lenses of sand bodies that are separated by impermeable layers (e.g. shale). Each sand lens varies in shape and size and acts as a trap for original hydrocarbon accumulations. The sand lenses parameters such as length and width can play important role in controlling gas recovery from hydraulically fractured tight gas reservoirs.

This study shows the effect of drainage pattern of the lenticular sand bodies on production performance, gas in place (GIP) estimation using P/Z vs Gp method, and ultimate gas recovery in tight gas formations. Numerical simulation approaches are used in order to understand the effect of hydraulic fracture parameters and also attribution of sand lens size and shape to the drainage pattern and gas recovery in hydraulically fractured tight sand gas reservoirs.

The results highlighted that in tight gas reservoirs, sand lens size in the direction perpendicular to hydraulic fracture wings has the major impact on gas recovery. Drainage of gas from the reservoirs is controlled by the sand lens width, and the size of sand lenses in the direction parallel to the hydraulic fracture wings does not have significant effect on gas recovery. The drainage area of the tight gas reservoirs is limited to the area perpendicular to the hydraulic fractures wings, and therefore P/Z vs Gp method may underestimate the value of GIP calculated for the lenticular/elliptical shape sand lenses.
Diagnosing Fracture Network Pattern and Flow Regime Aids Production Performance Analysis in Unconventional Oil Reservoirs
Authors: Rasdi Faisal , Chu Lifu
Published: March 2012

Many tight or shale gas wells exhibit a linear flow regime that can last for years. However, production analysis in unconventional oil reservoirs, such as the Bakken, shows that the linear flow regime is not the only dominant flow regime. Field data suggest that the duration of boundary-dominated flow influenced by the stimulated-reservoir volume (SRV) and compound-linear flow generally overshadow the early-time linear flow regime. Depending on the fracture network or SRV patterns, formation linear flow in unconventional oil reservoirs may only last for a few months but contribute about 30% of the total estimated ultimate recovery (EUR).

This study develops a procedure for identification of different fracture network patterns and inference of related flow parameters based on analytical methods. The reservoir description so derived is transported to a numerical reservoir-flow simulation model to capture the effects of compaction, multiphase flow behavior, and various flow regimes in an unconventional oil reservoir system.

This coupled approach helps illuminate reservoir performance, which allows insights into history matching. In particular, we demonstrate (a) fracture network patterns and flow regime diagnosis through rate-transient analysis; (b) coupled numerical reservoir simulation with analytical modeling results for performance-constrained history matching; (c) sensitivity analysis on the heterogeneity effect, compaction effect, and multiphase flow effects; and (d) field application of the proposed procedure on Bakken wells.

This proposed method demonstrates that analytical methods should be used before undertaking a detailed numerical reservoirflow simulation study. This understanding paves the way for much improved reservoir characterization in unconventional oil reservoirs.
New Inflow Performance Relationship for Coalbed Methane Wells
Authors: Feng Qihong , Shi Hongfu , Zhang Xianmin , Du Peng , Zhang Jiyuan
Published: March 2012

The inflow performance relationship (IPR) plays an important part in well completion, well production optimization, nodal analysis calculations, and artificial lift design. The production of coalbed methane is different from the conventional gas. For coalbed formation, permeability is sensitive to changes in effective horizontal stress which includes a cleat compression term and a matrix shrinkage term that have competing effects on cleat permeability. Therefore, the conventional method to calculate IPR curve is not completely appropriate for coalbed methane.

The production of under-saturated coalbed methane reservoir can be divided into three distinct stages-: single water phase, multiphase gas and water, and single gas phase. Previous literatures either neglect the matrix shrinkage which results in increasing production rate at a given bottom hole pressure or only focus on the last single gas phase stage.

This paper presents a new method to calculate the IPR curve for coalbed methane reservoir in the presence of permeability dynamics with pressure based upon P&M or Shi model. A second objective of this paper is to develop an approach for multiphase flow which requires a relationship between relative permeability and pressure, analogous to Fetkovich’s method for oil and gas flow.

The methodology is further validated with field data from Qinshui Basin in China. The results indicated that the tool proposed here provides reservoir enginners with a quicker and easier way to estimate the performance of coalbed methane well.
Modelling Of Hydraulic Flow Characteristics In Depleting Tight Gas Reservoirs
Authors: Albrecht D.. , Reitenbach V..
Published: March 2012

Fluid flow properties of tight Rotliegend sanstones show a strong sensitivity to stress conditions. To improve the understanding how fluid flow properties depend on the stress situation experimental measurements have been conducted on low to ultra-low Rotliegend sandstone samples from a North-German gas reservoir under simulated reservoir stress conditions. The measurements have been performed in the project DGMK 593-9/4 in the framework of the tight gas program of the DGMK (German Society for Petroleum and Coal Science and Technology). From the results of the experiments models could be derived, which describe the stress dependency of permeability and porosity.

The experimental study improves the understanding of stress dependence behavior of low permeable North-German sandstones and provides relevant reference data for simulation of flow processes. The correlation models based on the experimental results presented enable the evaluation of representative in-situ effective stress, permeability and porosity in low permeable Rotliegend sandstones from routine laboratory permeability and porosity data as well as depletion effects during the gas production.
Perforating on Wireline – Weak-Point Load Prediction
Authors: Baumann Carlos , Benavidez Marcia , Martin Andy , Salsman Alan , Williams Harvey
Published: March 2012

Thousands of wireline conveyed perforating jobs are executed every month around the world; however certain jobs have a higher risk of weak-point breakage due to dynamic pressure loads, known as gunshock loads. Gunshock loads result from pressure waves in fluids and stress waves in structural components. Perforating under all conditions (i.e. static/dynamic overbalance or underbalance) can produce pressure waves and/or reservoir surge of large magnitude leading to wireline weak-point (WWP) failures and/or cable damage. These risks are assessed as part of the job preparations. In this paper we focused on Dynamic Underbalance (DUB) because perforating with DUB can deliver clean perforations with very low risk of gunshock damage when properly planned.

For any perforating job on wireline, the magnitude and duration of pressure and stress waves depend on job parameters that can be adjusted, such as type and size of guns, shaped charges, gun loading layout, wellbore fluid, placement of packers and plugs, and cable size. For perforation damage removal we need a job design to generate a DUB of enough magnitude, using the right gun types and loading to produce a DUB of large-amplitude but short-duration, thus removing perforating rock damage while minimizing gunshock loads on the WWP. Perforating job designs are evaluated with software that predicts the transient fluid pressure waves in the wellbore and the associated structural loads on the cable and tools. All aspects of well perforating are modeled including gun filling, wellbore pressure waves, wellbore and reservoir fluid flow, and the dynamics of all relevant solid components like cable, shock absorbers, tools, and guns.

When planning perforation jobs that may have a significant risk of weak-point breakage, we predict the peak dynamic loads on the cable and weak-point during the design process, and when necessary we make design modifications to reduce the peak load on the WWP. The software’s predictive capabilities are demonstrated by comparing downhole fast gauge pressure data (110,000 data points per sec), shock absorber deformation, and cable tension logs with the corresponding simulated values. Fast gauge pressure data from perforation jobs shows that the software predictions are sufficiently accurate to evaluate the gunstring dynamics and the associated peak tension load on the WWP as part of the job planning process. Residual deformation of shock absorbers correlate well with predicated peak axial loads at the WWP, and available cable tension logs from vertical wells show that the cable surface tension is well predicted.

The simulation software described in this paper is used to minimize the risk of unexpected release of tools and guns due to perforating dynamic loads, thereby minimizing the probability of non-productive time (NPT) and fishing operations.
A New Approach for Numerical Modeling of Hydraulic Fracture Propagation in Naturally Fractured Reservoirs
Authors: Keshavarzi R.. , Mohammadi S..
Published: March 2012

Hydraulic fracturing of a naturally fractured reservoir is a challenge for petroleum industry, as fractures can have complex growth patterns when propagating in systems of natural fractures that leads to significant diversion of hydraulic fracture paths due to intersection with natural fractures which causes difficulties in proppant transport. In this study, an eXtended Finite Element Method (XFEM) model has been developed to account for hydraulic fracture propagation and interaction with natural fracture in naturally fractured reservoirs including fractures intersection criteria into the model. It is assumed that fractures are propagating in an elastic medium under plane strain and quasi-static conditions. The results indicate that hydraulic fracture diversion before and after intersecting with natural fracture is strongly controlled by the in-situ horizontal differential stress and the orientation of the natural fractures as well as hydraulic fracture net pressure. It is observed that hydraulic fracture net pressure increase leads to decreasing induced fracture diversion and in-situ horizontal differential stress decrease results in increasing induced fracture diversion before intersecting with natural fracture. In addition, potential debonding of sealed natural fracture in the near-tip region of a propagating hydraulic fracture before fractures intersection has been modeled which is one of the phenomena that has been rarely taken into account, as debonding of natural fracture before fractures intersection is of great importance that may lead to diverting the induced fracture into double-deflection in natural fracture and can explain hydraulic fracture behaviors due to interaction with natural fracture at different conditions. Also, it’s been observed that at low angles of approach with low to high differential stress, the induced hydraulic fracture opens the natural fracture while at high to medium angles of approach, natural fracture opening and crossing both are observed depending on the differential stress. Comparison of the numerical and experimental studies results has shown good agreement.
Permeability Upscaling for Carbonates from the Pore-Scale Using Multi-Scale Xray-CT Images
Authors: Khalili A. D. , Arns C. H. , Arns J. -Y , Hussain F.. , Cinar Y.. , Pinczewski W. V. , Latham S.. , Funk J..
Published: March 2012

High-resolution Xray-CT images are increasingly used to numerically derive petrophysical properties of interest at the pore scale, in particular effective permeability. Current micro Xray-CT facilities typically offer a resolution of a few microns per voxel resulting in a field of view of about 5 mm3 for a 20482 CCD. At this scale the resolution is normally sufficient to resolve pore space connectivity and transport properties. For samples exhibiting heterogeneity above the field of view of such a single high resolution tomogram with resolved pore space, a second low resolution tomogram can provide a larger scale porosity map. The problem then reduces to rock-typing the low resolution Xray-CT image, deriving viable porosity-permeability transforms from the high resolution Xray-CT image(s) for all rock types present, and upscaling of the permeability field to derive a plug-scale permeability.

In this study we characterize spatially heterogeneity using overlapping registered Xray-CT images derived at different resolutions spanning orders of magnitude in length scales. A 38mm diameter carbonate core is studied in detail and imaged at low resolution - and at high resolution by taking four 5mm diameter subsets, one of which is imaged using full length helical scanning. Fine-scale permeability transforms are derived using direct porosity-permeability relationships, random sampling of the porosity-permeability scatter-plot as function of porosity, and structural correlations combined with stochastic simulation. A range of these methods are applied at the coarse scale. We compare various upscaling methods including renormalization theory with direct solutions using a Laplace solver and report error bounds.

We find that for the heterogeneous samples permeability typically increases with scale. Conventional methods using basic averaging techniques fail to provide truthful vertical permeability due to large permeability contrasts. The most accurate upscaling technique is employing Darcy’s law. A key part of the study is the establishment of porosity transforms between high-resolution and low-resolution images to arrive at a calibrated porosity map to constraint permeability estimates for the whole core.
Shale Plays in The Netherlands
Authors: Bouw Sander , Lutgert Jan
Published: March 2012

The Netherlands is a mature hydrocarbon province. EBN, the Dutch state participant for hydrocarbon exploitation and exploration, has identified shale plays as one of the contributors to add reserves and to maintain production at the current level.

The main source rock for the limited amount of oil accumulations in The Netherlands are the Lower Jurassic (Toarcian) oil-prone shales. Lower Carboniferous (Namurian) hot shales have often been suggested as possible contributor to oil and gas Formation in The Netherlands as well, but this has not been proven to date. Recent discoveries of gas in the time-equivalent Bowland shales in the UK have encouraged interest in the production potential of these shales in North-western Europe.

In this paper the geological and geomechanical properties of the Lower Jurassic and Lower Carboniferous are presented in a shale play context. The assessment methodology is subdivided in three sections: 1) the overall geology of the play, 2) the type and quantification of hydrocarbons present and 3) the production characteristics. New and specific measurements on core and cutting material include pyrolysis, methane adsorption, mineralogy, texture, porosity, permeability, static and dynamic geomechanical properties, hardness and fracture conductivity.

The two identified plays show very distinctive properties. The Lower Jurassic samples indicate to be mostly thermally immature for dry gas implying that liquids can be expected. The Lower Carboniferous samples show areas that are overcooked. Mineralogical and geomechanical data suggest that different stimulation strategies may be necessary for these two plays to produce hydrocarbons effectively. The source rocks of Lower Jurassic age qualify as relatively soft while the Lower Carboniferous shales with high TOC content classify as very hard. Comparing the results of the assessment to known shale plays in the US, the plays position themselves in the opposite extremes of the productive shale play spectrum.
Impact of Geomechanics on Microseismicity
Authors: Agarwal Karn , Mayerhofer Michael J. , Warpinski Norman R.
Published: March 2012

The proper interpretation of microseismic event patterns to estimate hydraulic-fracture geometries is critical for understanding well performance in unconventional reservoirs. Besides factors such as microseismic event location uncertainty, advanced interpretations should also include a proper understanding of the geomechanical context in which these events take place and the underlying mechanisms that link the hydraulic fracture to the microseismic events. In this paper we investigate the different mechanisms that can cause microseismic activity around a hydraulic fracture from the viewpoint of a 3D elasto-static model to explain the behavior of microseismic event patterns. Stress perturbations caused by the opening of hydraulic fractures, opening of extensional branch fractures, and leakoff-related effects are considered. Multiple transverse fractures as well as dilated natural fractures orthogonal to the hydraulic-fracture direction are modeled under different sets of reservoir and treatment conditions to gain insight into the importance of different mechanisms.

An important observation is that stress changes alone caused by tensile opening behind the hydraulic-fracture tip cannot cause microseismic events under any set of reservoir conditions normally encountered in practice. The results indicate that tip effects, propagation of extensional branch fractures, and activation of natural fractures upon intersection should be the main drivers of microseismic activity in shale-gas plays. The modeling shows that microseismic events are expected to occur very close to the hydraulically activated fractures or planes, thus enhancing the value of microseismic monitoring. The modeling also showed that under certain conditions (critically stressed formations), the shear zone caused by tip effects can extend fairly far ahead of the fracture tip, which needs to be considered in the interpretation of fracture geometry. The presented results help to constrain and enhance the interpretation of microseismic data, from a geomechanical perspective.
Improving Completion And Stimulation Effectiveness In Unconventional Reservoirs - Field Results In The Eagle Ford Shale Of North America
Authors: Pope C. D. , Palisch Terry , Saldungaray Pedro
Published: March 2012

In an unconventional reservoir, the success of a project is driven by the completion. Unconventional plays have become the primary area of development in the US, and shale formations dominate the current rig activity. Most shale wells are drilled utilizing long horizontal wellbores, and completed using cemented or uncemented casing strings. To be economic, they require large hydraulic fracture treatments in multiple stages along the lateral.

Total well costs are driven by the cost of fracturing, often representing as much as 60% of the total well cost. This requires the operator to select the best completion method which includes casing and wellhead selection that is based on stimulation needs. The stimulation is regulated by injection rates, treating pressures, the volume of the stimulation, type of fluid, proppant selection, perforations, and the number of stages.

This paper focuses on several areas that are critical in a successful completion such as: casing size and pressure rating, wellhead selection, treatment design, spacing of the perforations and stages, linear verses cross-linked fluid, and the impact of proppant selection. With over 1800 wells completed and stimulated so far, a comparison of successful treatments and the cause of unsuccessful treatments will be provided. A review of actual field applications will be presented where possible, and a method for identifying best completion practices will be discussed.

Those working in or considering developments in unconventional plays around the world will be able to compare their current completion techniques to those presented in the paper. In addition, while no two resource plays are the same, the findings in this paper can be used by engineers as a guide for moving up the learning curve more quickly in other unconventional plays.
Novel Water Based Mud for Shale Gas, Part II: Mud Formulations and Performance
Authors: Riley Meghan , Stamatakis Emanuel , Young Steve , Hoelscher Katherine Price , De Stefano Guido
Published: March 2012

Shale-gas plays and other unconventional resources have gained significant importance worldwide. Historically, synthetic based drilling fluids (SBM) are used in these plays when no environmental concerns are in place and are preferred when wellbore stability is necessary. In this paper, we study the use of an improved water based drilling fluid (WBM) that is simple in formulation and maintenance that shows excellent rheological properties, maintains wellbore stability, and a good environmental profile. A combination of well-known and economically affordable materials is combined with new technology to achieve desired rheological properties and wellbore stability.

The use of nanoparticles to decrease shale permeability by physically plugging nanoscale pores holds the potential to remove a major hurdle in confidently applying water-based drilling fluids in shale formations, adding a new advantage to the studied fluid. Silica nanomaterials were investigated for this purpose. Due to their commercial availability, these materials can be engineered to meet the specifications of the formation. Characterization of the nanoparticles was completed with Transmission Electron Microscopy (TEM), dynamic light scattering, and X-ray-photoelectron spectroscopy. Rheological properties and fluid loss are studied together with other important properties such as shale stability and anti-accretion properties. The authors will describe new laboratory methods used to investigate these properties, from a modified API fluid loss test to the Shale Membrane Test that measures both fluid loss and plugging effects and illustrate additional future research that includes adding reactive species, and anchoring them to the pores, thus stabilizing the shale further.
Reserves and Performance Comparisons of Multi-Fractured Spearfish Horizontal Wells, to Various Fracturing Techniques and Well Spacing Configurations
Authors: Chodzicki John
Published: March 2012

The light oil bearing, low permeability, Spearfish formation, in Southwest Manitoba, Canada, has been a recent target of extensive horizontal drilling and fracture stimulation. An extensive completion database, along with historical production data, is available in the public domain. It is beneficial to review what the production trends illustrate about this play, in order to optimize the development of other similar types of low permeability sandstone plays, with regards to horizontal well spacing and fracture design.

Decline analysis was performed on over 120 horizontal wells that had sufficient completion information available, to study the effects of varying fracture spacing and size. The emphasis was to review the longer term production histories of the oil wells, as well as the predicted ultimate reserves, and see if there were any discernible trends, when production was compared to various fracture parameters.

Both the initial production rates and the ultimate reserves, showed significant data scatter when compared with fracture size, and number of fractures per well. It was difficult to make strong conclusions about initial production rates, being a function of varying fracture parameters. Closer analysis of individual wells, suggests that ultimate reserves appears related to the moveable oil-in-place, within the drainage area that a horizontal well produces from. It appears that well spacing effects and localized reservoir properties, must be taken into consideration, when analyzing the long-term performance of multi-fractured horizontal wells.

It seems that caution is required, when drawing long-term conclusions from initial production results. The basic reservoir engineering principle of an oil well draining a defined reservoir volume, are still applicable to low permeability reservoirs. There appears to be a finite number of horizontal wells that can be drilled in any given area, and an optimum number of fracture stimulations that can be placed per well.
Production Data Analysis in Eagle Ford Shale Gas Reservoir
Authors: Xu Bingxiang , Haghighi Manouchehr , Cooke Dennis , Li XiangFang
Published: March 2012

Eagle Ford shale in South Texas is one of the recent shale play in US which the development began in late 2008. So far many horizontal wells have been drilled and put into production using hydraulic fracturing. Production behaviour in shale gas reservoirs unlike conventional reservoirs is different in various plays and there are no published reports for production data analysis in Eagle Ford shale.

We have used the linear dual porosity type curve analysis technology to analyse the production behaviour and to estimate the essential parameters for this reservoir. This type curve was constructed based on transient production rate with constant well pressure in a closed boundary of stimulated reservoir volume (SRV) with double porosity approach. In order to analyse the early production data we used Bello’s and Nobakht’s approach to account for apparent skin.

In this study, three flow regimes were identified consisting of 1-bilinear flow; 2-matrix linear flow; and 3-boundary dominated flow. For the analysis of early flow regime, two possibilities of transition flow and apparent skin have been considered. First, the fracture permeability was estimated to be around 820 nano Darcy based on transition flow analysis. Second, the matrix permeability was estimated to be either 181 or 255 nano Darcy based on two different approaches in matrix linear flow regime. Furthermore, original gas in place (OGIP) and SRV were estimated from the boundary dominated flow regime. To validate the estimated matrix permeability, a single porosity numerical model with high permeability transverse fractures was built to match the production history. The permeability from simulation was in a good agreement with type curve analysis.

Production forecasting has also been carried out using different adsorption isotherms. The results showed that the effect of desorption depends on the reservoir pressure and the shape of adsorption isotherm curve. In early time of production, desorption is usually not effective, however, for long-term production forecasting, it is necessary to account for this phenomenon by providing an accurate isotherm.
Demonstrating the Value of Integrating FPWD Measurements With Managed Pressure Drilling To Safely Drill Narrow Mud Weight Windows in HP/HT Environment
Authors: Umar L. , Azian I. , Azree N. , Ali A. R. , Waguih A. , Rojas F. , Fey S. , Subroto B. , Dow B. , Garcia G.
Published: March 2012

The HPHT Exploration field is located in Block PM on the Northern side of the Malay Basin, Malaysia, and is notorious for its steeply rising pressure ramp, narrow drilling operation window with only 0.5ppg-0.6ppg in the 14-3/4?? and 9-1/2?? sections and inter-bedded sand/coal and shale formations

Block PM is still at the exploration and appraisal stage and therefore there is limited petrophysical information. Well SBD-2 was the second attempt to reach and cross the F & H sands of this basin.

This paper will detail how Formation Pressure While Drilling (FPWD) and Managed Pressure Drilling (MPD) were successfully applied to drill this HPHT exploration well with a very narrow safe mud weight window. FPWD provided a direct pressure measurement while drilling to set the lower boundary and the Dynamic Formation Integrity Tests (FIT) with MPD provided the upper boundary.

All the benefits of using a fully automated managed pressure drilling system were necessary to reach Well TD for the first time in this field; including Early Kick Detection (EKD), Dynamic Formation Integrity Tests (FIT), Dynamic Flow Checks and Constant BHP control within a narrow pressure margin.

The result of the combined technologies and operational procedures is safely drilling the first successful HPHT well in Malaysia drilled with MPD constant bottomhole pressure application. This well is so far the deepest gas discovery for the north Malay Basin.
Successful Use of Managed Pressure Drilling (MPD) in Low Pressure, High Pressure, and Deeper Reservoirs in Mexico South
Authors: Gomez E. , Chavarria M. , Beltran J. C. , Lupo C. , Duno H. , Casaos J.
Published: March 2012

Proper planning and front-end engineering, in a Biphasic MPD operation to drill a high temperature depleted reservoir in Mexico south area, demonstrated the real added value of the Constant Bottom Hole Pressure (CBHP) technique to overcome risks associated with a nuisance gas zone, hole cleaning and geo-mechanic issues which caused the loss of the original 5 7/8?? hole by failure of the BHA during a pipe work operation in tight hole.

Annular velocity is considered as the most critical factor affecting hole cleaning condition in a high angle well in the absence of pipe rotation and cuttings bed deposition is an escalating problem to be overcome too. This situation is aggravated when a biphasic system is used, because density, phase and viscosity change with pressure and temperature in multiphase flows. Also, flow regimes in multiphase flow are more complex, and do not lend themselves to simple characterizations such as laminar and turbulent flow and they are dependent upon the angle of inclination as well as the phase behavior of the fluids. On this way, the velocity of the fluids, the temperature of the surrounding formation, geometry, inlet temperature, specific heat of the fluids and surrounding material among others impact the temperature profile.

A complete MPD program that included flow chart decision trees associated with all lessons learnt from the original hole was performed, to improve hole condition through operational practices but also to handle gasification while drilling and tripping. In addition to this, a Hazard Analysis and Risk Control (HARC) was done as well as all contingency plans to mitigate and/or avoid these high potential problems.

Thanks to an elaborated MPD program, state-of-the-art equipment, constant adaptation of the fluctuating conditions of the open hole and experienced decision makers, the side track using low head MPD was successfully performed to drill and complete an un-drillable deeper well with minimum operational problems, increasing the production of this mature field.
Successful Controlled Pressure Drilling Application in a Geothermal Field
Authors: Sammat Essam , O'Shea Stephen , Innes Gareth , Kemenyfy Julio Gustavo , Piscevic Darko
Published: March 2012

This paper describes the successful application of Control Pressure Drilling (CPD) in the Kirchweidach geothermal project located in Bavaria, Germany. Wells located in the field and other offset wells in the area had faced drilling problems including severe mud losses and differential sticking in the reservoir formation. The project consists of a pair of wells, one of them to be used as producer and the other one as an injector. Which well will be used as producer or injector will be decided after the well tests. The first geothermal well was drilled using Controlled Pressure Drilling equipment in the reservoir section from the beginning; the underbalanced borehole pressure was achieved by pumping various rates of nitrogen and fresh water with polymers which can significantly reduce NPT and formation damage. For the second well it was decided to use the controlled pressure drilling equipment after mud losses appear.

Extensive engineering and development of procedures were carried out prior to spud the first well. The GT 1 well was originally drilled to 4503 m MD using two runs in the 9½" reservoir section and then tested. This was short of the original planned TD set at 4719 m MD. Two additional runs increased the TD to 4937 m MD. The primary purpose of employing underbalanced drilling methods was to avoid total loss scenarios and reduce formation damage by losing cuttings into the formation. Additionally, CPD techniques allowed reduced differential sticking problems, potentially faster ROP and less total drilling days.

CPD greatly reduces formation damage. Due to the fluctuation from conventional to underbalance conditions, some reservoir invasion inevitably occurred. This will be greatly reduced by virtue that there were no solids from drilling fluid additives. Nevertheless, some cuttings injection is likely to have occurred. This was further remedied by continuous and prolonged flowing of the reservoir. The planning, development and execution phases of the CPD project are detailed in this technical paper.

The GT2 well and GT2a side track were drilled conventionally as mud losses remained during drilling at manageable levels (15 m3/hr).
Simulator and the First Field Test Results of an Automated Early Kick Detection System That Uses Standpipe Pressure and Annular Discharge Pressure
Authors: Mills Ian , Reitsma Don , Hardt Jesse , Tarique Zaurayze
Published: March 2012

A new automated method of detecting an influx or losses using standpipe pressure (SPP) and annular discharge pressure (ADP) has been tested while drilling a tight gas well in Canada with approximately 200 hours of operational time being logged. While tight gas reservoirs may seemingly pose a low well control risk, they are typically drilled underbalanced to increase the rate of penetration and to eliminate a casing string which is required when using a higher mud density in order to protect upper formations due to low kick margin tolerance. The operator’s experience was that previous kicks went undetected until a significant volume had been produced due to the closed loop system having fluid retention without accurate flow measurement, resulting in slower pit volume measurement, extended well control time and requiring the casing to be set deep enough to protect the weaker formations from high shut-in pressures. Delta flow using flow meters has been in use for over 15 years for early kick detection (Haeusler et al 1995), however for tight gas drilling this method has not proven suitable due to cost, complexity and measurement disruption due to high gas fractions in the drilling fluid. A comparison of using a high resolution flow meter and pressure sensors prior to the field test will be discussed in addition to the field trial results. Benefits of using this new system, what was learned during the trial and improvements to the system will also be discussed along with how the system can be applied to Managed Pressure Drilling applications where the system is augmented using choke position and with conventional drilling applications.
A Thixotropic Barrier Fluid Used To Prevent the Commingling of Fluids While Tripping on Managed Pressure Drilling Wells
Authors: Riker R. , Turner J. , Lovorn R. , Kale T.
Published: March 2012

The use of high density "mud cap" tripping pills to provide adequate hydrostatic pressure downhole for well control is a common practice on managed pressure and underbalanced drilling operations. However, placing a high density tripping fluid on top of a lower density drilling fluid is an attempt to defy gravity, and too often the result is large volumes of the two fluids comingling, ruining the potential reuse of both. Viscosifying the tripping pill itself has been tried with some success, but problems encountered have included more difficult movement and storage of the tripping fluid, along with the risk of increasing the well’s bottomhole pressure while pumping the large, viscous pill into place. A better solution to the comingling issue is to place a physical barrier between the two fluids to prevent their mixing.

A novel fluid with robust thixotropic properties was developed to serve this barrier fluid function. The shear thinning properties of this fluid allow for ease of placement in the wellbore prior to tripping, and when the high density "mud cap" is displaced on top of the barrier fluid the comingling of the tripping fluid and the drilling fluid is prevented. After tripping the drillstring back to the top of the barrier pill, the pill can be washed through and disposed of at surface, leaving a clean drilling fluid in the wellbore. The development and initial use of this barrier fluid are the subjects of this paper.
Utilizing MPD To Drill HPHT Deepwater Exploration Well
Authors: Scoular T. , Hathaway K. L. , Abd El Moneim W. , Costa K. K. , Johnson S. A. , Rawcliff A. , Phillips A. W. , Burton D.
Published: March 2012

A successful use of MPD techniques from a semi??submersible rig in an HPHT drilling operation offshore Egypt is described. Included is a discussion of the MPD techniques and experience developed on jack??up HPHT drilling operations and how these were successfully transferred across to the floating rig operation. The presentation will discuss the rig modifications required to install the MPD equipment on the semi??submersible, including installation of the rotating head in the marine riser. It will also review the operations carried out utilizing MPD techniques, and give examples of how the equipment was used in the drilling of the last 3 hole sections. Some key areas considered essential to the success of this technology on a floating rig in a demanding HPHT environment and the benefits associated with the MPD operation are highlighted.