bluuebunny/crossref_metadata_2025 huggingface dataset:
Multiphase Flow Modeling of Surface Equipment in Managed Pressure Drilling Operations
Authors: Deshpande Kedar M , Northam Paul , Sabhapathy Peri , Gandikota Raju , Ring Lev
Published: October 2014

Surface equipment for Managed Pressure Drilling operations handles a multiphase mixture of drilling mud, cuttings and reservoir fluid influx. It is mandatory for safe MPD operations that surface equipment be able to handle pressure surges, pressure drops as well as any phase change of the fluid without causing any safety issues. In MPD operations, the surface choke is a key surface manifold component through which the fluid passes before entering the measurement gauges or solids control processing. Depending on choke position and flow conditions, part of the fluid can change phase from liquid to gas as it flows through the chokes resulting in formation of a gaseous phase that can be problematic for the downstream flow measurement devices and equipment integrity. A detailed analysis of the phase transition of the fluid in the surface equipment is necessary that can elucidate design modifications to ensure accurate measurements for safe and efficient drilling operations.

In this work, multiphase fluid flow is analyzed numerically using 3-D computational fluid dynamics (CFD) and a 1-D hydraulics network solver to understand the effects of choke positions on the overall pressure drop, pressure surges and onset of phase transformation to ensure surface equipment safety. 1-D hydraulics network results are validated against the 3-D CFD software as well as against experimental studies. Based on extensive numerical 1-D studies, look-up tables and charts were developed that help field personnel design the best surface equipment configuration, determine associated pressure drop and guard against the possibility of phase transformation.
Good Things Come in Little Packages: Nanotechnology for Reduction in Pore Pressure Transmission
Authors: Moroni L. P. , Vickers S. , Gray C. , Davidson M.
Published: October 2014

An increasing number of wells are being drilled in formations with a high risk of well bore instability. Historically, the majority of instability was a result of drilling reactive clays with water-based fluids. This is still a common risk and is usually addressed by using oil- and synthetic-based fluids. However, we now more commonly have to overcome the problems associated with drilling depleted or weak formations which can be difficult to drill even with oil- or synthetic fluids. This is especially common in fields that have been producing for many years and where geological pressures have been altered. More and more often, stress caging techniques are being used to drill these unstable formations. Effective stress caging is relatively straight forward if all the parameters are known; however, this is rarely the case and accurate fracture and pore throat measurement in-situ is nearly impossible. To seal these fractures, which are sometimes a few microns or less, a new form of micro- or nano-sized sealant is required in addition to the conventional calcium carbonate/graphite particle blend.

This paper presents a novel drilling fluid additive that utilises particles of approximately 200nm to seal fractures and pores to stop the invasion of drilling fluid filtrate and reduce pore pressure transmission. This enables wells to be drilled in depleted formations without losses, use very high overbalances with no differential sticking, and also plug micro pores and micro fractures found in shales to reduce instability and improve hole integrity. Laboratory testing is described that demonstrates the advantages of using this technology and case histories proving its usefulness in the field are described. Utilisation of this new nanotechnology will enable many problematic formations to be drilled safely and trouble-free by reducing the risk of wellbore failure.
Refinement of Relative Permeability Measurements by Accounting for Viscous Fingering in Coreflood Experiments
Authors: Pereira B. , Shahverdi H. , Sohrabi M.
Published: October 2014

Relative permeability (kr) is a critical input data for any calculation involving multiphase flow in petroleum reservoirs. Normally, kr curves are obtained by performing coreflood experiments as part of SCAL measurements or EOR studies. The results of the experiments are then used to obtain kr values often by either analytical models (e.g. JBN) or 1D history matching techniques. These models are based on the Buckley-Leverett displacement theory, which is not applicable to unstable displacements.

In this paper, we present a simple method to calculate the relative permeability from coreflood experiments in which the displacement front could be unstable, for instance due to adverse viscosity ratio. The method proposed here modifies the JBN technique, and hence is referred to as modified JBN (MJBN), by including a viscous fingering term (η) in the oil fractional flow. In order to calculate η, we have developed a correlation between the viscosity ratio and the displacing fluid's viscosity. The correlation was obtained by producing viscous fingering with a known relative permeability and an unfavorable viscosity ratio. The relative permeability obtained by this method was then compared with the results obtained using history matching by commercial software widely used in laboratories.

The results show that η is function of viscosity ratio and displacing fluid viscosity. This means that η can be used for a wide variety of cases, with different kr, core properties or fluid properties, just by using the same plots of η versus viscosity ratio versus displacing fluid viscosity to estimate η. 1D history matching was compared with modified JBN (MJBN) for an experiment with unstable flow, resulting in a considerably better match using MJBN.

This work provides new insights into the often overlooked issue of viscous fingering, its impact on multiphase flow, and a simple way of correcting kr data for the adverse effects of viscous fingering in kr measurement experiments. The proposed method can be easily adapted by service companies and researchers interested in measuring relative permeability in order to improve the quality of measurements and the accuracy of this crucial data.
New Method for Determining Mineralogy and Matrix Properties from Elemental Chemistry Measured by Gamma Ray Spectroscopy Logging Tools
Authors: Freedman R. , Herron S. , Anand V. , Herron M. , May D. , Rose D.
Published: October 2014

Methods for predicting mineralogy from logging tool measurements have been an active area of research for several decades. In spite of these efforts, methods for predicting quantitative mineralogy including clay types from well logging data were not fully achieved. The introduction of geochemical logging tools in the 1980s offered promise; however, early versions of geochemical logging tools did not measure elemental chemistry with enough accuracy and precision to enable reliable and quantitative determination of mineralogy. Recent advances in geochemical logging tool technology now enable accurate and robust measurements of the chemical elemental concentrations that are needed to determine continuous quantitative and detailed logs of mineralogy.

This paper presents a novel approach for determining more accurate, detailed mineralogy from an elemental spectroscopy logging tool. This work was made possible by three recent developments: the introduction of a new high-performance neutron-induced gamma ray spectroscopy logging tool, a new high-quality research database consisting of chemistry and mineralogy measured on cores acquired worldwide from conventional and unconventional reservoirs, and a new model-independent inversion method that overcomes the limitations of previous model-dependent methods.

The model-independent inversion makes use of the database which includes clean sands, shaly sands, shales, carbonates, and complex mixed lithologies. The database contains laboratory measurements of dry-weight elemental chemistry and mineralogy measured by transmission Fourier transform infrared spectroscopy. The database is used to derive a model-independent mapping function that accurately represents the complex functional relationship between the elemental concentrations and the mineral concentrations. Once the mapping function is determined from the database, it can be used to predict quantitative mineralogy from elemental concentrations derived from the logging tool measurements. Unlike previous inversion methods, the model-independent mapping function does not have any adjustable parameters or require any user inputs such as mineral properties or endpoints.

The mapping function is used to predict continuous logs of matrix densities plus concentrations of 14 minerals (i.e., illite, smectite, kaolinite, chlorite, quartz, calcite, dolomite, ankerite, plagioclase, orthoclase, mica, pyrite, siderite, and anhydrite) from eight dry-weight elemental concentrations derived from the logging tool. The new method has been applied to well log data acquired worldwide in numerous conventional and unconventional reservoirs having a wide variety of complex mineralogies. The predicted mineralogies and matrix densities are generally found to be in good quantitative agreement with core-derived mineralogies and matrix densities.
Secondary Application of Low Salinity Waterflooding to Forties Sandstone Reservoirs
Authors: Law S. , Sutcliffe P. , Fellows S.
Published: October 2014

Low salinity waterflooding (LSWF), versus high salinity waterflooding (HSWF) has been the focus of significant research at various centres around the world, yet there is still considerable debate over the exact mechanism that provides incremental oil recovery. The use of the LSWF technique is not widespread in the United Kingdom continental shelf (UKCS). However, it has been announced that the Clair Ridge development will deploy low salinity waterflooding (LSWF) in secondary mode from the start of field life, and a number of companies are currently assessing the applicability of the technique through high level screening and core flooding. Forecasting the potential oil recovery under LSWF is heavily influenced by the simulation technique that is used. Presently the most widely discussed approach is the use of a weighting table with relative permeabilities representing the high and low salinity cases. As the grid block falls below threshold salinity, the simulator utilises the weighting table to assign an interpolated value of salinity. This value of salinity is utilised to represent a change in wettability. While this approach approximates the net effect of LSWF, it does not capture the oil/rock/brine interaction. This study examines the modelling approach to LSWF utilising an in-house generic Forties Palaeocene model in CMG's STARS simulator. The conventional approach of modelling LSWF using high and low salinity relative permeabilities is compared to the latest Multi-component Ion Exchange (MIE) methods by numerical simulation to assess the impact on incremental oil recovery. A sensitivity analysis is then carried out on the effects of specific parameters on incremental oil recovery, utilising published data from fields in the Forties Palaeocene fan system. A discussion is provided. The impact on secondary recovery was accessed with respect to wettability alteration; injection salinity (LSWF versus HSWF); oil viscosity and aquifer influx. The application of LSWF in secondary mode to the Forties Palaeocene Sandstones was found to be favourable for the case of mixed-wet reservoirs.
Case Studies: The Ensemble-Based Approach to History Matching and Model Parameter Estimation
Authors: Zhang Yanfen , Bhark Eric , Phale Hemant A. , Dehghani Kaveh
Published: October 2014

Multiple assisted history matching (AHM) techniques commonly applied in the oil and gas industry were benchmarked for their applicability to field studies. The benchmarking effort was aimed at exploration of the theoretical as well as practical benefits, challenges and tradeoffs of the AHM techniques as they are utilized for asset development and reservoir management.

This paper specifically discusses benchmarking of ensemble-based methods as applied for history matching of a key deepwater asset for the corporation. Two variations of ensemble-based methods are examined: the ensemble Kalman filter (EnKF) (Evensen, 2009) and the ensemble smoother with multiple data assimilation (ES-MDA) (Emerick and Reynolds, 2013). In both techniques, the ensemble of parameter estimates evolves as field data are assimilated into the reservoir characterization, either sequentially using the EnKF or iteratively using the ES-MDA. Both of these variations have been deployed with adaptive bootstrap-based screening (Zhang and Oliver, 2011) to reduce the sampling error of ensemble estimates.

One significant strength of ensemble-based methods is their ability to estimate high-resolution model parameters. In this benchmark study, however, the ensemble-based methods were applied for estimation of a group of low-resolution model parameters including regional property multipliers and pilot points. The insights gained from the inverse problem of constraining reservoir simulation models to historical production data can be particularly valuable in guiding the practitioner in re-definition of the prior model uncertainty and towards the model solution. The study shows that a major challenge in the application of ensemble-based methods is parameter over-adjustment resulting from the improper addition of observation errors associated with the actual observations. In practice, multiple experiments are required for the user to iteratively improve the optimal level of the added errors. As the number of observations grows large, the increase in computational cost and decrease in ensemble variability are additional challenges in the application of ensemble-based methods. While assimilating different types of data, a balanced proportion of these data types should be maintained. These points are illustrated and discussed in the field application section of the paper.
Pressure Transient Analysis as an Element of Permanent Reservoir Monitoring
Authors: Shchipanov A. A. , Berenblyum R. A. , Kollbotn L.
Published: October 2014

Pressure transient analysis (PTA) is traditionally used to characterize well and reservoir parameters from well tests based on shut-in periods. PTA was widely used for reservoir management and decision making before reservoir simulation became the main tool. Presently more and more reservoirs are surveyed by permanent (downhole) gauges. These gauges provide vast amount of pressure transient and rate data which may be interpreted using improved PTA approaches to gain more knowledge on reservoir dynamics. This has opened new prospects for PTA applications in field studies.

Permanent pressure and rate measurements cover both well flowing and shut-in periods occurring during normal operations. These measurements allow for analysis of time-lapse pressure transients and comparative interpretation of flowing and shut-in periods. The analysis of time-lapse data provides time-dependent description of well-reservoir parameters. The comparative interpretation gives understanding of flowing reservoir properties which are often different from those estimated from well shut-in periods as in the classical PTA. These approaches provided basis for an improved methodology of interpreting permanent pressure measurements, where the scope of the standard PTA application may be extended to integrate new data sources.

Application of the developed methodology has been demonstrated with data from fields on the Norwegian Continental Shelf. For many wells the comparative interpretation revealed significant difference in well-reservoir parameters estimated from flowing and shut-in periods. It was also found that the flow regime near a well may vary. For example, the dominance of a hydraulic fracture observed during a shut-in period may be significantly reduced during the flowing period with simultaneous changes in reservoir conductivity. Dynamic behavior of natural and induced fractures due to pressure (stress) changes, wellbore cross-flows and variable contribution of reservoir layers are considered to be possible reasons for these effects. Analysis of time-lapse pressure transients provided description of long-term changes in well-reservoir parameters, e.g. reservoir conductivity, hydraulic fracture properties and boundary effects.

The key advantage of applying this methodology is characterization of the more representative flowing, rather than shut-in, well-reservoir parameters as well as their permanent monitoring during reservoir lifetime. The monitoring may reveal ongoing changes in the reservoir characteristics, production impairment risks etc. The methodology uses data readily available for many fields and provides an updated description of well behavior and hydraulic reservoir properties. The reward may be improvement in everyday field operations and well performance optimization, reduced uncertainty of input to reservoir models and better decision making through enhanced model predictability.
Minimizing Over-Flush Volumes at the End of Fracture-Stimulation Stages - An Eagle Ford Case Study
Authors: Al-Tailji Wadhah , Northington Neill , Conway Matthew , Davidson Brian
Published: October 2014

With the growing popularity of multi-stage hydraulic fracturing treatments in horizontal wellbores, various completion systems have been utilized for mechanical isolation and staging of individual fracture treatments. One of the more popular fracture staging techniques is the plug-and-perf technique in cemented casing, which requires the lateral section of the wellbore to be free of debris and proppant so that the plug and perforation tool string can be pumped down to the desired setting depth. Proppant that has settled in the lateral can result in plugs getting stuck and prematurely setting at the wrong depth, requiring costly intervention work and delaying the progress of completing the well.

The industry standard practice to prepare a clean wellbore has been to over-flush each fracture treatment by 50 to 100 barrels in excess of the volume to the perforations. This practice has raised concerns about disturbing near-wellbore proppant conductivity and potentially harming fracture continuity with the wellbore, and thus productivity. Since operators have achieved satisfactory economics in many shale plays, this practice continues despite its controversy.

These concerns have led to experiments in minimizing excess flush volumes in wells located in the liquids-bearing window of the Eagle Ford Shale. This paper proposes a process involving the use of real-time treatment data displayed within a wellbore model simulation to adjust the flush volume of each stage based on the reduction in proppant concentration at the perforations. Over 200 stages were successfully placed with this method with no incidences of plugs sticking in the lateral. This paper contains a selection of treatment charts and wellbore diagrams from actual applications of this method. Simulated fracture profiles of different over-flush scenarios are also compared and discussed.

This paper will be useful for engineers and managers involved in well completions and stimulation, and presents detailed methodology for successfully applying this strategy in their fields. By applying these procedures, continuity between the proppant pack in the fractures and the wellbore should be improved, and fresh water usage will be reduced.
Simultaneous Operations in Multi-Well Pad: a Cost Effective way of Drilling Multi Wells Pad and Deliver 8 Fracs a Day
Authors: Ogoke V. C. , Schauerte L. J. , Bouchard G. , Inglehart S. C.
Published: October 2014

Unconventional gas or tight shale-oil plays require a high density of wells and multistage hydraulic fracturing to economically develop. This leads to the use of high density well pads to reduce land costs, associated environmental impact and well delivery efficiency through batch drilling. A pad in Shell's North American assets of Groundbirch and Fox Creek (Canada), Appalachia, Permian and Eagleford (USA) can comprise of two opposing rows of 13 - 20 horizontal wells spaced three to six meters apart.

Considering it takes an average of 14 days to drill a 5,000m well and a subsequent nine days to complete the multistage hydraulic fracturing sequence, a typical 26 well pad in the Grounbirch asset would take approximately two years from spud to first gas.

Simultaneous Operations (SIMOPS) is defined as when two or more mutually exclusive activities take place within 50m of a wellbore, or each other. The activities are classified as critical and have to be carefully planned to ensure the safety of all personnel involved and comply with regulatory spacing stipulations. This paper aims to illustrate how Shell Canada implemented SIMOPS; further highlighting how rig operations were successfully co-ordinated during a restrictive weather period (melting snow and associated road bans) and how simultaneous completion operations were utilized to achieve eight hydraulic fracturing jobs, or ‘fracs’, a day, averaging 6.2 fracs/day over 13 wells.
Maximizing Capital Efficiency by Expanding the Limiter Redesign Process to Flat Time Operations
Authors: Valenta M. A. , Walker M. W. , Pastusek P. E. , Bailey J. R. , Elks W. C. , Lewis S. B. , Mitchell N. D.
Published: October 2014

The operator's drilling efficiency program has been expanded to a Limiter Redesign Process that seeks to optimize all rig time, including flat time. As drilling efficiency gains have been achieved, flat time now accounts for roughly 80% of the total rig time and approximately 70% of the total cost of drilling and completions operations; leaving 20% of rig time for drilling. This fact led to the generation of a comprehensive Flat Time Reduction (FTR) program.

The Fast Drill Process has become a well-known workflow to identify hole-making limiters and mitigate them through "relentless redesign to the economic limit of performance". Efforts to increase drilling efficiency continue, and this process has yielded a continuous increase in the overall footage per day and a reduction in flat time within individual hole sections.

To address operations that do not include drilling of rock, the operator has launched a similar effort and workflow process which focuses on "flat time" portions of the well construction process. This has become a key focal point in the organizations approach to maximize capital efficiency. The Flat Time Reduction process provides an environment in which operations are optimized while further enhancing a workplace where "Nobody Gets Hurt."

This process is yielding significant savings globally and has been accomplished through planning, "real-time" recognition and response, collaboration with service providers, and a focus on Non-Productive Time (NPT) reduction while continuously improving safety performance. Field applications of limiter redesign are discussed in this paper. The purpose of this paper is to present the current status and specific approaches being used to reduce flat time and share the workflow process.
Digital Rocks: Developing an Emerging Technology Through to a Proven Capability Deployed in the Business
Authors: Fredrich J. T. , Lakshtanov D. L. , Lane N. M. , Liu E. B. , Natarajan C. S. , Ni D. M. , Toms J. J.
Published: October 2014

This paper describes the development of ‘Digital Rocks’ technology – in which high-resolution 3D image data is used in conjunction with advanced modeling and simulation methods to "measure" petrophysical rock properties – through to a proven capability that is sanctioned for use in the operating assets of a large, multinational oil company. Digital Rocks is a disruptive technology in that it can fundamentally alter how the industry measures the basic rock properties that are used to characterize reservoirs and help predict their performance. Whilst Digital Rocks has been the subject of a number of publications, these have been generally limited in scope, and focus on certain aspects of the underlying science, or alternatively, present a stand-alone example application. This paper describes the research and development process, summarizes the results of extensive field trials, and explains how application of this technology has produced value within the context of an established field development decision-making process.

We describe the underlying philosophy motivating the specific research that has been undertaken, and more generally, the technology development process that included extensive verification and validation. The paper describes navigating through the ‘valley of death’ – which describes the intervening terrain between research & development and the industrial application of a proven technology – a key challenge for nearly all emerging technologies. Details of the required capabilities, including experimental x-ray micro-computed tomographic imaging, image processing, numerical simulation including high performance computing, and rock physics interpretation are described.

The technology development described is specific to static rock properties, and its application to conventional oil and gas reservoirs (i.e. permeabilities of ~1 millidarcy or greater). The results of over a half-dozen field trials carried out across BP's portfolio are presented, including comparisons of image-based porosity and simulated permeability, formation factor, cementation exponent, resistivity index, saturation exponent, and capillary pressure with experimental data that have been obtained using traditional laboratory measurement techniques on core plugs. The field trials included over 100 plugs taken from cores from more than ten wells.

Digital Rocks technology can improve evaluation of reservoir quality and quantification of hydrocarbons in place, and it can help inform the development of improved recovery methods. Key advantages include reducing the cycle time for appraisal and reducing uncertainty in subsurface description.
Use of a Non-Invasive, Non-Damaging Blocking Agent for Improved Cleaning in Low Bottomhole Pressure Wells
Authors: Ananaba O. Victor , Hain Larry L. , White Jason A. , Craig Steven H. , Koch Richard T.
Published: October 2014

Solids removal from severely depleted wells remains a challenging intervention operation in the oil and gas industry. The various cleanout options that exist generally require significant expense, and may result in loss of potentially damaging fluids or permeability reduction to zones with low bottomhole pressures.

This paper will focus on several field trials in South Texas utilizing a fluid-based, formation-blocking agent as part of the cleanout circulating fluid. The blocking agent has been in use for several years in cement spacer systems as a lost circulation material (LCM) with favorable results. The blocking agent uses a modified, hydrophobic polysaccharide to form micelles. Under differential pressure the micelles adsorb and realign in a layer along the formation or perforation tunnel forming an impermeable seal effectively blocking the loss of fluids to the formation. With the formation blocked, the solids can be circulated out using a higher density fluid and at higher circulation rates than the low-pressure reservoir would support. When the well is returned to an underbalanced system, the micelles will disperse, returning the fluid to its original state and restoring permeability to near a pre-intervention level.

The case histories included in this paper are the first application of this material for well intervention operations outside a cement spacer application, and the results discussed show that the material performed remarkably well.
From Regional Depositional Architecture to Reservoir-Scale Considerations, Lower Paleozoic Baltic Basin, N Poland
Authors: Krzywiec P. , Volterrani S. , Slonka L. , Lis P. , Buffenmyer V. , Malinowski M. , Lewandowski M.
Published: October 2014

The western edge of the East European Craton in Poland has recently been the focus of intense exploration efforts for unconventional hydrocarbons, led by Polish and foreign companies. Results of early exploration wells clearly demonstrate that there are still many unknowns regarding various aspects of the unconventional petroleum system, both regional (structure and depositional architecture of the Lower Paleozoic succession) and more local (variations of shale thickness, TOC, mechanical properties etc.). In order to shed light on some of these problems high-effort regional reflection seismic survey PolandSPAN has been acquired that covered entire Lower Paleozoic basin developed above the SW edge of the East European Craton. Following regional interpretation a feasibility study devoted to seismic reservoir characterization has been completed that allowed to assess applicability of seismic reflection data for reservoir-oriented studies of the Lower Paleozoic shales in Poland.

The Lower Paleozoic basin in Poland is located above the southwest edge of the East European Craton, northwest from the Teisseyre – Tornquist Zone which is separating the cratonic plate from the West European Platform (Ziegler, 1992; Doornenbal & Stevenson, 2010). Later Late Paleozoic tectonic movements resulted in compartmentalization of the Lower Paleozoic basin into three sub-basins: Baltic Basin, Podlasie Basin and Lublin Basin (Fig. 1). During the Precambrian/Cambrian, the cratonic edge underwent extension and rifting of the Rodinia supercontinent, while Cambrian – Middle Ordovician subsidence was driven by a post-rift lithospheric thermal cooling (Poprawa et al., 1999; Poprawa, 2006a). In the Late Ordovician – Silurian, the cratonic edge was under the strong influence of the Caledonian thrust belt, and was incorporated into its flexural foredeep basin (Poprawa et al., 1999; Nawrocki & Poprawa, 2006). Deposition was dominated by fine-grained organic rich shales, generally derived from the eroded orogenic wedge and deposited in the distal foredeep basin (Poprawa et al., 1999; Poprawa, 2006b). The Silurian Caledonian foredeep basin encompassed vast areas stretching from the present-day Sweden across Estonia, Latvian, Lithuania, Russia (i.e. Kaliningrad District), Poland, Belarus, Ukraine and farther to the southeast (Poprawa et al., 1999; Skompski et al., 2008; Zdanaviciute and Lazauskiene, 2007). Presently available information regarding the Caledonian orogenic wedge is very limited and mostly indirect, based on e.g. provenance studies of the foredeep infill, as it was destroyed and deeply buried during the later tectonic phases (Poprawa, 2006b).
Structural Uncertainty Integration within Reservoir Risk Analysis and History Matching
Authors: Sabatino R. , Viviani E. , Della Rossa E. , Sala C. , Maffioli A.
Published: October 2014

Reservoir structural modelling is one of the fundamental steps in a reservoir study workflow. The impact of the structural uncertainties on the dynamic response of the reservoir is well known and not negligible, but often the reservoir shape is considered as fixed due to the complexity to manage alternative geological structures in multi-realisations simulation loop. Nevertheless, both Risk Analysis (RA) and History Matching (HM) workflows strongly require a practical and time-effective methodology for structure management with an efficient uncertain geometry parameterization. In this work, an innovative methodology for structural uncertainty handling is presented. The methodology is based on the combination of Principal Component Analysis (PCA) and Elastic Gridding. In particular, the PCA-based parameterization is able to efficiently handle the geophysical uncertainty model, consistent with the geostatistical characterization as well. Such methodology has been structured in an internally developed tool. This tool is specifically designed for a direct handling of corner point geometry grids and allows changes of surfaces, shape and size of internal reservoir layers, fault throw and fault position and even new fault placement, honouring geological constraints. One of the key points of the proposed methodology is the integration of a geologically-oriented parameterization and a statistical parameters reduction technique (the above mentioned PCA) in a workflow which includes commercial HM/RA tool and a dynamic simulator. The result is an efficient structural uncertainty management framework suitable for Risk Analysis and History Matching studies. Among the field applications performed so far, two cases have been chosen aiming at showing the potentialities of the proposed approach. The first example is a history matching exercise on an undersatured oil reservoir. A comparison between the traditional and the "structural", even if simplified, HM is herein provided, showing the improvement due to a better geologically-oriented uncertainty model. The second example is a risk analysis application on an oil field, with a strong uncertainty of the oil in place due to lack of accurate knowledge of the reservoir flanks shape. The application highlights the advantages deriving from the geophysical PCA-based workflow.
Fault Diagnosis in Oil Wells
Authors: Horowitz G. , Faundez E. , Maestri M. , Cassanello M.
Published: October 2014

A new automatic fault diagnostic method based on variable trend analysis was developed. Every time a fault is detected, the proposed method uses a local model to determine the variable trends associated to the detected fault. The fault identification is achieved by comparing the extracted variable trends with a previously generated library of faults signatures. The method was implemented and tested with a set of faults purposedly generated in an oil production well equipped with a pressure cavity pump (PCP). It was able to correctly identify all the generated faults, outperforming simpler versions of the method based on global models.
First Successful Application of Horizontal Open Hole Multistage Completion Systems in Turkey's Selmo Field
Authors: Mitchell David , Davis Justin , Appleton Joel , Watson Mark
Published: October 2014

Turkey has significant oil and gas reserves that have not been fully developed. This paper will highlight the planning, execution, challenges and production benefits of the first installations of horizontal open hole multistage completion systems in the Şelmo field. Located in southeastern Turkey and north of the prolific Zagros fold belt, which encompasses the oil fields of Iran and Iraq, Şelmo is the second largest oil field in Turkey by cumulative production, with an estimated 600 MMbbl of oil in place. An operator has recently started redeveloping the field targeting the Middle Sinan Dolomite zone by drilling horizontal wells.

Matrix acidizing is a method of stimulating carbonate reservoirs for oil and gas production. The acid treatment creates conductive flow channels which transport reservoir fluids from within the formation matrix directly into the wellbore. In matrix acidizing of carbonate reservoirs, accurate acid placement is a major challenge because the acid tends to flow preferentially toward the highest permeability areas. This can result in overstimulation at these intervals leaving the lower permeability regions untreated. A significant percentage of matrix acidizing treatments do not meet expectations because of improper job design. In some cases, increased water production is observed due to preferential stimulation of high permeability sections associated with water. This paper will provide an in depth understanding of acid stimulation of carbonate formations with both single and limited entry open hole multistage systems that can be applied to carbonate reservoirs worldwide.

The operator designed a pilot project including four horizontal wells in the Şelmo field; two wells were completed using single entry open hole multistage completion systems and the other two using batch stimulated limited entry open hole multistage completion systems. In the single entry systems, there is only one injection port per stage while in the limited entry systems, multiple injection jets are used. The jets enable controlled injection and leak off for effective flow of acid into the entire section of the interval. The designed treatment is thereby placed at an optimal rate and pressure along the stage length, maximizing the development of conductive channels throughout the entire stimulated reservoir. Results of the pilot indicate a successful stimulation and a significant increase in production from all four horizontal wells compared to offset vertical wells.

With the success achieved from the first horizontal open hole multistage completion systems in Turkey's Şelmo field, the operator plans to complete more wells using these systems to exploit its assets. The success of this project demonstrates the applicability and benefits of using open hole systems for effective matrix acidizing of carbonate reservoirs around the world.
The Relationship Between Rock Properties and Fracture Conductivity in the Fayetteville Shale
Authors: Briggs Kathryn , Hill A. Daniel , Zhu Ding , Olson Karen
Published: October 2014

Fracture conductivity in shale is largely dependent upon the shale rock properties and the formation conditions. This paper aims to explore two different vertical intervals of the Fayetteville Shale, FL2 and FL3, by comparing laboratory fracture conductivity measurements. Fayetteville Shale outcrop cores were artificially fractured, preserving the surface roughness for the conductivity measurements. Controllable parameters, such as proppant size, concentration and type, were kept consistent between the two zones. An initial unpropped experiment was run, followed by two 30:70 mesh propped experiments at 0.03 lb/ft2 and 0.1 lb/ft2 concentrations.

The FL2 consistently recorded higher conductivity values than the FL3 at closure stress up to 3, 000 psi. Therefore, each zone was evaluated using mineralogical composition, thin-section analysis and surface-roughness scans to identify rock property differences. The FL2 and FL3 rock analysis identified that the two zones are very different. Although the FL2 and FL3 samples used in the conductivity experiments had similar clay content, the FL2 contained more quartz and the FL3 contained more carbonate. Additionally, the FL2 samples were less fissile and had larger surface fragments break along the fracture surface, whereas the FL3 samples broke parallel to the bedding plane and had flaky dust fragments break along the fracture surface. The FL2 had higher conductivity values at low closure stress due to the rearrangement of bulky surface fragments and larger voids created on the surface when fragments were lost. The difference between the FL2 and FL3 conductivity decreases as the concentration of proppant increases because the voids causing unpropped conductivity differences become filled with proppant. Finally, production data was used to confirm laboratory results by providing evidence that wells in the FL3 produce less than the wells in the FL2 formation.
Case study demonstrates "Learning Through Observations" as an effective education tool
Authors: Aggour Mohamed , Hussien Hassan , Fraim Michael
Published: October 2014

Experience has shown that traditional teaching through lecturing generally results in students acquiring/remembering less than 50% of the information delivered in the lecture. Several factors contribute to such ineffective teaching/learning method. Most important among these factor is that information are merely presented at lectures as facts or finding and students are j ust spoon-fed the information. Other contributing factors are the lack of student attention in class, and the fact that students did not spend any effort to acquire the information or knowledge. We believe that students will better remember information/knowledge which they spend effort to acquire or find. Certainly, knowledge acquired as conclusions from observations would never be forgotten. Therefore, we conducted two case studies where students, for each case, were divided into two groups of equal academic strength. One group went through traditional lecturing of course materials of a specific topic, while the other was directed to conduct specific experiments under specific conditions and was asked to arrive at conclusions based on the observations. The two groups for each case study were tested under same conditions and results were compared to determine the effectiveness of the proposed teaching method, which we call "Learning Through Observations (LTO)". The study involved specific topics in two courses. We selected gas lift in the production engineering course, and cementing in the drilling engineering course. The results showed that LTO is a much more effective teaching approach. This paper presents the details of the case study.
Investigating Aperture-Based Stress-Dependent Permeability and Capillary Pressure in Rock Fractures
Authors: Huo Da , Li Boxiao , Benson Sally M.
Published: October 2014

Understanding multi-phase fluid flow behavior in fractured porous media is crucial for developing fractured hydrocarbon reservoirs, implementing hydraulic fracturing, and predicting potential leakage in gas and CO2 storage. The goal of this research is to investigate stress-dependent permeability and capillary pressure in rock fractures. Laboratory measurements of fracture aperture distributions have been made using CT scanning under various conditions of effective stress. By applying the stress-dependent aperture data, numerical simulation is employed to model the change of permeability and capillary pressure in the rock fracture as a function of the effective stress.

The stress-dependent aperture distribution data demonstrates that increasing stress results in two effects: (1); the mean aperture will decrease; (2); the variance of aperture distribution will increase. Experimental results show that permeability will drop by 73% when effective stress increases from 0.34MPa to 22.06MPa. As the variance of aperture distribution increases with stress, the plateau area of the capillary pressure curve tends to grow steeper, indicating that capillary behavior changes from more fracture-like to more porous media-like. The impacts of mean and variance of aperture distributions on permeability and capillary pressure are separately analyzed. The mean aperture decrease will reduce permeability and increase entry pressure. The variance increase will reduce permeability, the pore size distribution index and entry pressure. By analyzing the stress-dependent mean and variance of aperture distributions, this paper provides a more straightforward way for estimating stress-dependent permeability and capillary pressure in rock fractures.
Eco-Friendly Biodegradable Materials For Diversion And Zonal Isolation Of Multiple Stage Horizontal Well Completions: Case Histories From Marcellus Shale Hydraulic Fracturing
Authors: Arnold David , Fragachan Francisco
Published: October 2014

The use of mechanical diverters in the oil and gas industry has been a common practice for decades, typically deploying perf ball sealers, degradeable balls, rock salt, dissolvable flakes, and incorporating downhole equipment such as sliding sleeves or straddle-packer systems. With multiple stage operations and horizontal wells becoming the industry norm, there is a need for a more permanent and reliable technology that is easily deployable and will seal previously stimulated perforations and zones from untreated perforations. This paper describes case histories from horizontal Marcellus Shale wells treated with degradable diversion materials applicable at a broad bottom-hole temperature range, maintains integrity under treating pressures and remains in place for the entire duration of well completion operations.

There are a number of scenarios for which biodegradable materials are applicable: zonal isolation for horizontal wells with multiple perforation clusters, vertical wells treated through tubing where bridge plugs cannot be used, sealing off perforations for re-stimulation treatments as opposed to squeezing the perfs, and sealing off perforations after treating through coiled-tubing.

The results from the wells treated at the Marcellus Shale showed compelling evidence that temporary mechanical bridging agents can effectively replace bridge plugs and maintain zonal isolation. The concentrations of the diverter system used were optimized during the treatments and achieved typical pressure increases of 300–1,200 psi per stage and complete seal-off pressures of 3,600–4,000 psi. The information presented in this paper will show the capabilities of using this material and the potential applications for multiple stage stimulation treatments. The pressure responses from the treatments show the ability of the materials to remain in place throughout the treatment of the well, and the details of the successful treatment execution and production results will be presented. The production results of the candidate wells also showed production rates higher than neighboring wells and wells typical for that area.
Going Long – Overcoming Challenges in Completing 3600m Laterals
Authors: Liston R. , Lynn C. , Shell B. Layton , Fraser E.
Published: October 2014

Recent trends in unconventional oil and gas developments have seen longer horizontal wells drilled to achieve greater reservoir contact while minimizing cost and surface impact. Challenges for completing longer laterals include achieving effective fracture stimulation and performing clean out of the well bore after stimulation is complete. A case study was performed in Shell Groundbirch, an unconventional gas development in British Colombia, Canada, focusing on stimulation and extended reach cleanouts. Five long lateral wells +3600m lateral length with measured depth to true vertical depth ratio of 2.5, were drilled and completed; the resulting wells are 60% longer than the standard development well. Based on operational efficiency, coiled tubing (CT) was determined to be the preferred method for performing the millouts and well cleanup. 73.0 mm CT with an aggressive taper can reach the required set-down depths with enough weight on bit available to mill-out all completion plugs. Operational plans and milling tools were developed to maximize the probability of success. This paper outlines the technical details which contribute to an important case study that can help define and push the limits of extended reach CT interventions in industry.
The Condition of Capillary Condensation and Its Effects on Gas-In-Place of Unconventional Gas Condensate Reservoirs
Authors: Li B. , Mezzatesta A. , Thern H. , Zhang B. , Wu J. , Zhang H.
Published: October 2014

In shale gas reservoirs, the adsorption of gas can be multi-layer adsorption because of the presence of small pores and heavy hydrocarbon components in the kerogen portion of the source rock. Particularly, in unconventional gas condensate reservoirs, the gas can become condensate, filling the pores at pressures different from the dew-point pressure of the bulk fluid. The commonly used Langmuir isotherm does not provide a valid model for capillary condensation because it is based on the assumption that the adsorption mechanism is a monolayer adsorption.

To solve this problem, we developed a method to compute the adsorption isotherms of capillary condensation for multi-component hydrocarbons, based on the general Kelvin equation. However, this method was limited to pressures below the lower dew-point pressure, due to the assumption of incompressible liquid and closeness to the dew-point pressure of the bulk fluid.

In this work we extended the adsorption and gas in place models for capillary condensation to the high pressure range. Based on fundamental thermodynamic principles, we developed an iterative method to determine the dew point shift caused by pore confinement. This method is applied to determine the phase of the confined hydrocarbons, as well as to compute the hydrocarbons in place at the initial reservoir condition. Furthermore, we analyzed the properties of the confined fluid and checked the capillary condensation effects on the gas in place caused by fluid composition, pore size distribution, temperature, and pressure. This methodology is also applied to the Eagle Ford shale formation. The analysis results show that the gas in place can be underestimated with the conventional model by more than 10% if the initial pressure is lower than the shifted dew-point pressure.