bluuebunny/crossref_metadata_2025_split huggingface dataset:
Shale Plays in The Netherlands
Authors: Bouw Sander , Lutgert Jan 
Published: March 2012

Abstract
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

Abstract
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

AbstractIn 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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.