bluuebunny/crossref_metadata_2025 huggingface dataset:
A New Cost Effective Well Testing Methodology for Tight Gas Reservoirs
Authors: Jacques Antoine , Brouard Benoît , Bérest Pierre , Boutaud de la Combe Jean-Luc
Published: February 2011

Obtaining formation characteristics in a tight-gas environment is highly challenging: formation tester tools run during open-hole logging are often unsuccessful, and conventional well tests are not appropriate as no gas flow is commonly observed before hydraulic fracturing. This paper presents a new well testing methodology adapted from techniques used in the salt industry and successfully applied to Tight Gas Reservoirs, using only wellhead pressure gauges and surface flow meters without downhole tools. It delivers an injectivity index profile along the open hole, allowing better identification of the zones with the best potential and optimization of the hydraulic fracturing strategy. The test typically consists, after having run a tubing string, in continuously displacing the annulus mud by a heavier and less viscous fluid such as brine. During the test, the mud/brine interface rises up along the borehole as a result of pumping brine down the tubing at constant pressure and circulating out mud from the annulus. As viscosities and densities are contrasted, brine and mud injection rates in a given layer are also expected to be contrasted. The differences between brine and mud flow rates provide a continuous injectivity indicator along the wellbore. A different procedure, involving stationary step-by-step measurements, can also be performed. The fluid interface is displaced to a predetermined depth, at which step the entire wellbore is pressurized and a fall-off resulting from fluid leak-off across the open hole is recorded and analyzed to derive a layer productivity index.

To date, three well tests have been carried out in various types of wells, showing good correlations with conventional logs. To go a step further than a qualitative tool, a deconvolution of the time-dependent and interface-depth-dependent permeation flows is necessary. An inversion process accounting for the injection history in the various layers is being developed with the objective of deriving a continuous kh and skin profile. This new method still needs to be qualified against conventional kh data. In particular, it must be demonstrated that the test provides access to the kh of the undamaged zone of the wellbore.
A Coreflood Investigation of Low-Salinity Enhanced Oil Recovery
Authors: Rivet Scott M , Lake Larry W. , Pope Gary A
Published: February 2011

Many researchers have observed an increase in ultimate oil recovery by injecting low salinity brine in laboratory and field experiments.

In this work, linear laboratory corefloods were conducted to study the effect of low salinity waterflooding on oil recovery rate, residual oil saturation and relative permeability. We conducted 21 different waterfloods using nine brines, three crude oils, six outcrop Berea cores and two oil reservoir cores. Every core used was at least 11 long and pressure taps were use to measure pressure drop across sub-sections of the core.

Increase in ultimate recovery of crude oil with decrease in salinity of injected brine was observed in several, but not all, cases. These results suggest that that injecting low salinity brine changes the wetting state of some cores from mixed to water-wet and that this change improves the ultimate oil recovery. This hypothesis of a changing wettability is supported by the following observations: (1) When low salinity injection produced higher oil recovery, the end-point water relative permeability kw° decreased and post-waterflood end-point relative permeability to oil kro° increased. (2) Injecting low salinity brine produced a persistent wettability alteration (toward water-wet) that eliminated oil recovery salinity dependence in subsequent floods. (3) The oil recovery salinity dependence noted in (2) could be restored by extended aging (thus restoring mixed-wetness). (4) Injecting low salinity brine improved recovery by delaying breakthrough, suggesting an improvement in displacement stability.
Chestnut: A Successful, Innovative Development of a Small, Marginal North Sea Oil Field
Authors: Yale David P. , Meier Steven W. , Leonardi Sergio A. , Joyce Gina M. , Kushnick Arnold P. , Wang Jianlin
Published: February 2011

A large-scale laboratory for testing a wide range of petroleum recovery processes has been designed and built to provide a test bed for understanding the detailed physics of processes and calibrating numerical models. The system, dubbed LARGE for Large-scale Apparatus for Reservoir and Geomechanical Experimentation, is centered around a 50 ton, 2100 psi rated pressure vessel that allows testing of processes on a "physical model" of the reservoir that is 2.1 m in diameter and up to 50 cm thick. Key specifications for the system include an "overburden" spacer to mimic the deformation and stresses applied by the real overburden on the reservoir, pumps and "feed" vessels to simulate injection and production in up to 10 wells, over 450 sensors to measure and image real-time the progress of processes occurring in the vessel. The main rationales for the system are to test flow processes in three-dimensions and with sufficient instrumentation to fully understand the physics and chemistry processes and the ability to test at a large enough scale so that reasonable geologic heterogeneity can be incorporated in the "physical model" of the reservoir. The system can be used for a wide range of processes but early work will focus on reservoir processes in shallow, heavy oil reservoirs and overpressured unconsolidated sand reservoirs.
Chestnut – A Successful, Innovative Development of a Small, Marginal North Sea Oil Field
Authors: Wood P. , Coghlan G.
Published: February 2011

The Chestnut field, discovered in 1986, is located in license block 22/2a in the UK Central North Sea. The reservoir is a high quality, deepwater sandstone in the Eocene-age Nauchlan Formation. Appraisal drilling confirmed a complex sand distribution and constrained volumes of ca.30° API oil. The sands are relatively thin, though of high quality (several Darcies), of limited predictability and occur in a flat structure with a short oil column.

In 2001 a keeper, horizontal appraisal well was drilled and an extended well test performed to investigate OIIP and the dynamic reservoir/well behaviour. Performance was towards the low end of expectations and consequently the commercial challenges led to the withdrawal of most of the original participants in the joint-venture.

Venture Production (now Centrica Energy) began building its interest during 2001 taking a majority stake and operatorship in 2003. A novel development strategy was required to manage the many commercial risks of such a marginal project. Capex and opex exposure were mitigated by identifying the potential of a cylindrical FPSO design solution, then working closely with its developer, Sevan, the relevant authorities and field partners to achieve the right design for a North Sea deployment.

A Field Development Plan was approved in late 2005 using the Sevan FPSO design with tanker shuttle export. The initial development used the 2001 appraisal well and one water injector drilled in 2006. Initial reservoir pressure was only slightly above saturation pressure and pressure maintenance is required to minimise gas evolution in the reservoir. First oil was produced in September 2008 and injection started in December 2008. An additional producer was drilled, completed and put on production in Mar. 2009

This paper will outline the approaches that evolved to manage multiple, irresolvable, subsurface uncertainties so that a field investment decision could still be made against a background of capital constraints.
A Pragmatic Approach to Frac-Pack Tool Erosion Qualification Testing
Authors: Clem Nicholas J. , Hammer Aaron C. , O'Connell Maria M. , Amaral Anderson da
Published: February 2011

Frac packing tool erosion is a growing concern as more high-profile deepwater wells are completed using this technique. Today many deepwater wells require frac pack pump rates of at least 40 barrels per minute (bbl/min) with proppant loads reaching 300,000 lbm. As zone lengths are increased and multizone operations are performed, jobs requiring 60 bbl/min pump rates with proppant loads reaching 1,500,000 lbm are becoming more typical. The current frac packing tool designs must be optimized to accommodate the higher pump rates and proppant volumes required to complete these deepwater wells.

Extensive research and development, including computational fluid dynamics analysis and scale-model erosion testing, have led to the development of a new series of sand control tools that have been optimized for ultra-high-rate frac packing applications. Analyzing various patterns such as velocity, fluid path, erosion, and sand concentration at high rates helps identify critical areas within the system that require design optimization.

Results from full-scale erosion qualification testing of this new series of sand control tools are discussed. The qualification tests are designed to simulate extreme applications for tools in terms of pump rate, treatment volumes, and proppant properties, while testing conditions remain consistent with actual job specifications. The qualification test parameters were chosen to emulate and, in some cases, exceed the parameters of frac pack treatments currently being planned for the deepwater Gulf of Mexico. Erosion properties of the crossover, extension, and casing will be discussed, and depicted.
Friction Pressure Performance of Commonly Used Viscous Gravel-Packing Fluids
Authors: Jain Samyak , Gadiyar Bala , Stamm Bryan , Abad Carlos , Parlar Mehmet , Shah Subhash
Published: February 2011

Gravel packing is increasingly used in long horizontal wells and challenging environments. Key to successfully executing the gravel-pack job is selecting an appropriate gravel carrier fluid. Friction pressure loss exhibited by gravel packing fluids is an important consideration in their selection. This paper discusses the friction pressure performance of commonly used gravel packing fluids in the industry today which include Visco Elastic Surfactant (VES) type fluids, Xanthan and Hydroxyethyl Cellulose (HEC).

In wells with long horizontal section or narrow margin between pore pressure and fracture gradients the friction pressure loss exhibited by these fluids in the washpipe and washpipe/basepipe annulus governs whether these wells can be gravel packed without fracturing the formation. In gravel packs with alternate path configuration (shunts) the friction pressure loss through the shunts controls the maximum length that can be gravel packed.

This paper discusses in detail the fluid friction pressure performance while pumping these fluids through various conduits including circular pipe, eccentric annuli and rectangular tubes (shunts). These data were generated in field-scale yard tests under controlled conditions, both for ambient and elevated temperatures. The paper also discusses the rheological properties of these fluids at ambient and elevated temperatures. The effect of factors such as surfactant/polymer concentration, addition of gravel, and temperature on the friction pressure loss of these fluids is presented which will help in fluid selection/optimisation under different scenarios.
Real-Time Long-Distance Teaching: The Texas A&M DL Experience
Authors: Teodoriu C. , Barrufet M. , Epps M. L. , Falcone G. , Reinicke K. M.
Published: February 2011

This paper presents the experience gained while using a commercial web based tele-teaching technique which includes live participation of the DL students. Unlike the recorded classes, the on-line interaction offers a better knowledge transfer and teaching process control.

We show the advantages of this new concept and the student response to the teaching process for a highly sophisticated petroleum engineering class delivered to students located world-wide from our offices in College Station, Texas (server location) and Clausthal-Zellerfeld, Germany (teacher location). The experience over two years of tele-teaching using this web package has resulted in enthusiastic student acceptance. This paper is a following up of our previous paper that was presented at the ATCE 2009 and enjoyed a tremendous interest of the audience, and gives answers to some of their questions.
Innovative Field Camp for Education and Industry-Academic Collaboration in Geology-Based Reservoir Model Building for Carbonate Reservoirs in the Middle East
Authors: Gupta Anuj , Poppelreiter Michael
Published: February 2011

Jebel Fuwairit, Qatar, is a unique geological site where an active and fossil coastal spit are developed next to each other. It offers opportunities to study active carbonate forming processes and map the fossil formations. Heterogeneities of carbonate depositional systems and early facies related digenesis are available for investigation on multiple scales: bed-body-reservoir. It provided a unique opportunity to establish a training section and digital model for education and training/collaboration site for professionals in industry.

Primary objective is to provide students experience in measurements/ research methods for developing a digital model of an oil/gas reservoir based on an outcrop study. Another objective is to establish a hands-on training opportunity for professionals/ students to learn the process of rock based reservoir model building.

Field camps were conducted to collect GPS mapping of key surfaces, cross-beds and several sedimentological sections in combination with rock samples, and facies/ microfacies descriptions. Photo panels of several cliff sections were created. CT-scan and porosity/permeability measurement of hand samples were conducted to understand the pore architecture for such carbonates. Work continues on integrating measurements at different length scales in a 3D digital model of the reservoir.

Jebel Fuwairit outcrop has never been described before. This work will create the first 3D digital geology model for Qatar and unique educational experience for students. This outcrop in Qatar, studied jointly with geologists and reservoir engineers from industry, is a beach-bar complex that is an analog for Upper Jurassic Arab and Lower Triassic Khuff Formations (K2/K1 sequence), which hold most of the oil/gas reserves in the Middle-East.
The Hydrocarbon Systems of the Vienna Basin and Their Characterization
Authors: Potsch K. , Zach C.
Published: February 2011

When exploring within the same basin one is tempted to assume that there is a main source rock from which the reservoir fluids originate. This work analyses the fluids of the discovered reservoirs in the Vienna Basin firstly by their traditional parameters like saturation pressure, stock tank liquid density, gas-liquid ratio etc. This leads to one set of categories of the reservoir fluids.

Another way is to analyse the "plus-fraction". Its shape gives an indication whether it is a mixture of different "source"liquids. Liquid chromatography is the basis for this approach. It allows for determining the amount of higher components (carbon numbers). Using that analysis on can build the properties of the pseudo-fractions that are essential for reservoir simulation. Usually only density and molecular mass are known of the C6+ fraction that mainly constitutes the stock tank liquid. For gas injection processes a more detailed fluid description is desired to carry out compositional simulations. This paper presents investigations of a variety of liquid hydrocarbon distributions. They show that it is not possible to fit one general type function by matching a few constants. Different types of functions are required for a proper fit, among which is the well known Gamma-function.

Having found the best fitting function, one can firstly find a very good estimate of the pseudocomponent properties. Secondly, the fitted function helps in case of contamination by oil based mud. Thirdly, it might even help to classify oils according to their origin if one has access to a wide data base.
Challenges in Designing, Planning and Execution of Well Completions for Highly Depleted Reservoirs, and High Differential Pressure Between Reservoirs
Authors: Imran T. N. , Al Izudin A , Natasha M. S , Samsudin N. , Rameli M. F. , Hamid A. A. , Elliott C. , Khalid M. Z. , Zeidan A. A.
Published: February 2011

As part of the second stage development of a mature oil field offshore Malaysia, deeper reservoirs in Field S were identified from four different blocks. In order for the wells to be economically viable, up to eleven (11) sands were planned to be completed. This proved to be challenging due to the high differential pressures between reservoirs, highly depleted zones above the target sands, and pressure and reserve uncertainties of the target sands.

This paper covers design, planning, and execution of the well completion for four (4) infill wells where the differential pressure between zones was predicted to be up to 1,700 psi (Pounds per Square Inch). Some of the zones were highly depleted, and the most depleted zone was 0.216 psi/ft (Pounds per Square Inch per Foot). Even with the lowest brine weight of 8.5 ppg (Pounds per Gallon), the over balance was about 1,800 psi.

The completion was designed to maximize the number of sands in each well (eleven (11) sands with six (6) zones) to gain maximum production, while at the same time the short string needs selectivity. One of the challenges was the production casing design could not be larger than 7". To facilitate selectivity on the short string, the upper completion was designed with a Y-block.

To avoid significant losses from high overbalance and differential pressures, stage-by-stage perforation was planned. However, the challenge was to achieve the required under balance across all the zones since there was no stimulation planned. Both static and dynamic under balance perforation techniques were used for perforation.

With all the upfront planning and design, the well completion operation was successfully executed with less than 1% Non Productive Time (NPT) recorded, which was an excellent achievement considering the complexity of the completion design and operation.

In conclusion, the post-analysis showed the production rate target was successfully attained - indicating the formation damage was minimal even though the wells were drilled and completed with more than 1,000 psi overbalance.
New Perspective on Gas-Well Liquid Loading and Unloading
Authors: Veeken C. A. , Belfroid S. P.
Published: February 2011

This paper discusses the multiphase flow mechanism responsible for gas-well liquid loading. It shows that the conventional idea of droplet flow reversal (Turner et al. (1969)) does not capture reality and that actual observations are better described by film flow reversal. This paper subsequently explores how film flow reversal changed views on existing gas-well liquid unloading techniques such as continuous foam injection, and discusses new manners of gas well deliquification that specifically aim to delay film flow reversal. The benefits of different types of tubing wall modification have been evaluated via small-scale lab testing. Most promising, hydrophobic coating of tubing reduces the gas rate below which liquid loading occurs by about 50%. The benefits of hydrophobic coating are translated to representative field conditions.
Downhole Vibration Measurement, Monitoring, and Modeling Reveal Stick/Slip as a Primary Cause of PDC-Bit Damage in Today
Authors: Ledgerwood L. W. , Hoffmann Olivier J. , Jain Jayesh R. , El Hakam Carmel , Herbig Christian , Spencer Reed W.
Published: February 2011

Since backward whirl was discovered as a severe cause of PDC bit failure, our industry has made great strides toward creating whirl-resistant bits and operating practices. But is whirl still the major cause of PDC bit damage in today's applications? This paper reports on a recent field study in which downhole vibrations were measured using a newly available in-bit vibration-monitoring device. The focus of this study was to understand today's North American vertical conventional rotary applications. In addition, four wells were also drilled using a research drill rig in Oklahoma. In these tests, PDC bits, BHAs, and operating parameters were varied to document their effect on downhole vibrations. In these four wells, vibration measurements from the new in-bit measuring device were validated against a commercially available and industry-proven MWD vibration monitoring service. Also, a computer model that accounts for the coupled response of bits and BHAs was run for selected tests in field wells and the research drilling rig. The models agreed well with the measured cases in both whirl and stick-slip. The model also allowed the authors to confirm that high-frequency torsional oscillations (4-9 Hz) which we observed were, as a previous industry paper suggests, due to BHA torsional resonance.

The results of this study indicate that the most common field vibration today in hard rock PDC drilling is stick-slip, not whirl, in the target test region. In field tests, stick-slip was almost exclusively observed. For typical field applications with a surface rotary speed of about 70, we have measured peak downhole RPM during the slip phase as high as 500. This paper will report on these findings, document damage resulting from stick-slip, and suggest potential solutions to mitigate downhole vibrations.
A New Technique for Accurately Measuring Two-phase Relative Permeability Under Non-Darcy Flow Conditions
Authors: Lai Bitao , Miskimins Jennifer L.
Published: February 2011

A new steady-state technique for determining gas-water relative permeability curves for proppant packs under high confining stress conditions is presented. In this technique, a time domain reflectometry (TDR) device that can measure the saturation inside the proppant pack instantly and efficiently is introduced. De-aired water and nitrogen gas are simultaneously injected into the proppant pack under a desired confining stress, and the pressure drop and saturation are measured when steady-state conditions are reached. Two different proppant mesh sizes, 12/18 and 20/40, have been tested under four confining stresses ranging from 10004000 psi with repeatable and accurate results.

In the majority of published techniques, two-phase relative permeability curves are determined by using Darcy's law. This might be accurate enough for low permeability formations under low flow rate conditions, but in high permeability fracture proppant packs, the non-Darcy flow effects, or inertial effects, cannot be neglected. Thus relative permeability curves neglecting inertial effects may lead to inaccurate predictions. In this paper, three flow models: the classic generalized Darcy ‘s Law, the generalized Forchheimer flow model, and the two-phase Barree and Conway model (Barree and Conway, 2007) are employed to calculated and compare the relative permeability results. The experimental results show that the non-Darcy flow effects on gas relative permeability are higher than those calculated using Darcy's Law. In addition, the various confining stress effects on water and gas relative permeability curves are also presented. A significant decrease in gas relative permeability and minor effects on water relative permeability occur as the confining stress increases. These results help to further understand the effects of multiphase flow in porous media.
Amplifier/Booster Joint Positioning Framework Design for a High-Speed Wired Telemetry System in MWD/LWD Downhole Tool Environment
Authors: Rath Sumit , Mandadi Sharath , Thamizhmani Vivek , Samuel Robello
Published: February 2011

Data transmission from downhole tools to the surface is extremely important to drilling engineers for real-time decision making and well economics. With new advances and innovations in downhole technologies, particularly in the areas of drilling optimization and MWD/LWD technologies, the current data transmission rates are insufficient for the complete use of all downhole data that can be acquired. Digitization of transmission systems can increase the overall efficiency and accuracy of data acquisition systems. The benefits include increased reliability and large volumes of data on which to base current and future decisions. With its innovative technology, a high-speed wired telemetry drill pipe system can achieve this. The network, consisting of embedded wires along the drill string, can achieve higher transmission rates from downhole tools to the surface in real time; it enables the complete use of technological advances in approximately the same amount of rig time as is required with mud pulse or electromagnetic telemetry systems. This paper presents a study of the wired telemetry system and describes the importance of placing an amplifier/booster system to efficiently enable the data signal transmission from downhole to the surface systems. An accurately placed amplifier/booster system is an essential part for the success of the wired telemetry system. It will address signal losses and can ensure that the integrity of essential signal parameters (such as bandwidth, bit accuracy, signal strength) remains consistent throughout the transmission path. This paper presents case studies of the factors responsible for the losses in the telemetry system and the design an optimized amplifier/booster placement system to overcome those losses to achieve the objective of efficient transmission of acquired data from downhole tools.
Vibration Analysis and Control with Hole-Enlarging Tools
Authors: Samuel Robello , Yao Dongping
Published: February 2011

In high-risk, high-cost environments, such as ultra-deep waters, refining advanced technologies for the successful completion of wells is paramount. Challenges are still very much associated with complex bottomhole assemblies (BHAs) and with the vibration of the drillstring when used with hole enlarging tools. These tools with complex profiles and designs become additional excitation sources of vibration. The more widespread use of downhole tools for both directional telemetry and logging-while-drilling (LWD) applications, as part of the front line data acquisition system within the drilling process, has made reliability a prime area of importance. This paper presents and validates an existing model to predict severe damaging vibrations. It also provides analysis techniques and guidelines to successfully avoid the vibration damage to downhole tools and to their associated downhole assemblies when using hole enlarging tools, such as hole openers and underreamers. The dynamic analysis model is based on forced frequency response (FFR) to solve for resonant frequencies. In addition, a mathematical formulation includes viscous, axial, torsional, and structural damping mechanisms. With careful consideration of input parameters and the judicious analysis of results, we demonstrated that drillstring vibration can be avoided by determining the three-dimensional vibrational response at selected excitations that are likely to cause them. In addition, the analysis provides an estimate of relative bending stresses, shear forces, and lateral displacements for the assembly used. Based on the study, severe vibrations causing potentially damaging operating conditions that had been a major problem in nearby wells were avoided. Simple guidelines are provided to estimate the operating range of the drilling parameter to mitigate and avoid the downhole tool failures. Extensive simulations were performed to compare the data from the downhole vibration sensors; this paper includes severe vibration incidence data from three case studies in which the model estimated, predicted, and avoided severe vibration.
Novel Approach to Quantifying Deepwater Laminated Sequences Using Integrated Evaluation of LWD Real-Time Shear, Porosity, Azimuthal Density and High-Resolution Propagation Resistivity
Authors: Yared Katerina , Pelorosso Mauro , Altintutar Ismail , Buster Derek , Manuel Ela , Doyle James , Russell Charles
Published: February 2011

Accurate reserve volume determination is crucial in the early stages of a project since planned subsurface capacity is dependent on reserve expectations. The fundamental method of calculating reserves uses bulk formation resistivity and bulk porosity to determine water saturation. This approach cannot accurately quantify reserves in laminated sand-shale sequences where the sensor resolution is insufficient to characterize the fine laminae. A tensor petrophysical model can determine laminar shale volume and laminar sand-fraction conductivities reducing the problem to a single dispersed shaly sand model. Combining this with sand-fraction porosities can lead to accurate reserve quantification.

Identification and quantification of hydrocarbons within low-contrast, low-resistivity formations can be difficult when using conventional log data. This is primarily due to the presence of laminar shale and the inherent vertical resolution of measurements acquired by wireline and logging while drilling (LWD).

A Gulf of Mexico deepwater example is used to demonstrate this novel approach in quantifying hydrocarbons in laminated sand-shale sequences. Real-time shear slowness is used in conjunction with LWD triple-combo data to identify potentially productive low-contrast reservoirs. Then, advanced resistivity post processing extracts the vertical component of resistivity, enabling calculation of sand-fraction resistivity. Sand-fraction resistivity, combined with normalized sand-fraction porosity, yields sand-fraction water saturation. Shale volume, porosity and water saturation cut-offs determine the net hydrocarbon volume. The LWD-calculated hydrocarbon volumes in place are then compared to results obtained from a wireline logging suite.

This approach demonstrates that the use of conventional empirically derived bulk-volume porosity and saturation methods in laminated sand-shale sequence formations results in underestimation of the reservoir producibility and hydrocarbon reserves. Vertical resistivity, derived from LWD-acquired propagation resistivity and electrical anisotropy sensitivity, can be used to quantify reserves in these environments.
Integrating Core Data and Wireline Geochemical Data for Formation Evaluation and Characterization of Shale Gas Reservoirs
Authors: Quirein John , Witkowsky Jim , Truax Jerome , Galford Jim , Spain David , Odumosu Tobi
Published: February 2011

When core data, such as mineralogy, porosity, total organic carbon, and elastic properties, are available from a large multiwell database, it is possible to extract meaningful statistical relationships between the data. These relationships can then be applied in other wells with limited or no core data. X-ray diffraction (XRD) mineralogical data is unique in that it can readily be transformed to synthetic wireline geochemical elemental data, such as the weight fractions, aluminum, silicon, and calcium. This transformation establishes a relationship between the mineralogical data and the synthetic wireline geochemical data, which can be applied to "real wireline" geochemical data to select an appropriate set of minerals for prediction from the wireline geochemical data. Statistical optimization based approaches are generally used to perform this prediction of mineralogy from wireline data.

The most difficult aspect of predicting mineralogy from wireline geochemical data is the selection of the proper mineral model. The proposed approach assists the analyst in the selection of the proper model. In addition, this paper shows how core XRD mineralogical data can be used to establish constraints between the predicted mineralogy, such as percent clay fraction illite greater than 60%. An accurate prediction of mineralogy from wireline geochemical data can be transformed to an accurate prediction of grain density, enabling an accurate prediction of total porosity (corrected for kerogen effects).

The workflow described in this paper provides an effective approach for establishing and predicting mineralogy, grain density, and porosity from wireline geochemical data. This paper presents results for a Haynesville shale example. Finally, the proposed approach helps to maximize the value of the core data for shale gas plays.
Borehole Quality Design and Practices to Maximize Drill Rate Performance
Authors: Dupriest F. E. , Elks W. C. , Ottesen S. , Pastusek P. E. , Zook J. R. , Aphale C. R.
Published: February 2011

In 2005 the operator implemented a workflow that ensured drilling performance limiters were identified, redesigned, and extended continuously. The use of mechanical specific energy surveillance to address bit limiters and dysfunction has previously been published. The purpose of this paper is to discuss additional practices that have been developed to extend the non-bit performance limiters, particularly those related to borehole quality.

There have been over 40 non-bit performance limiters identified and redesigned globally. While these are diverse, those with the greatest global impact were found to be tied directly to borehole quality. Consequently, in 2008 the performance management workflow was modified to increase awareness of borehole quality as a performance limiter. The result was that acceptable borehole quality became defined as that which would not limit footage per day. Quality is now redesigned to the "economic limit of performance" in the given interval. The economic limit of performance is a significantly higher standard than the common industry objective for borehole quality, which is to achieve low trouble time and run casing successfully.

The average drilling footage per day drilled by the 23 operations that have been active since the performance management process was implemented has improved by about 63%. Instantaneous drill rates have typically increased 100-300%. Advances in bit and non-bit limiters appear to have contributed equally, and the majority of the gain in non-bit limiters has come from improved borehole quality. Other gains have come from related limiters, such as an increased understanding of the manner in which cuttings transport and tripping operations are controlled by borehole quality.

The paper discusses the technical models that are used to understand the major borehole limiters, the engineering design and the real-time practices that have been developed, as well as the field results.
Statistical Analysis of Safety Incidents and the Implications of Imperfect Reporting
Authors: Jablonowski C. J.
Published: February 2011

Quantitative models of safety incidence allow managers to connect specific elements of the safety management system to outcomes. The results provide evidence that can be used to allocate resources to those incident prevention efforts that yield the highest returns in terms of avoided incidents. However, conventional methods of statistical and regression analysis of safety incidents do not account for the fact that not all incidents are reported. By relying on conventional methods, it is possible that resources are being misallocated, and that the industry is missing opportunities for improvement. This paper specifies regression models that explicitly account for imperfect reporting. The methods are applied to an operator provided data set of safety incidents. While all of the results of the case study are not generalizable, they clearly demonstrate the incremental value of a more complete model of safety incidence and reporting behavior.
The Potential Applications in Heavy Oil EOR with the Nanoparticle and Surfactant Stabilized Solvent-Based Emulsion
Authors: Qiu Fangda
Published: February 2011

This study presents the results of nano-particle and surfactant-stabilized solvent-based emulsion bench test studies under laboratory conditions that investigate the recovery mechanisms of chemical flooding in a heavy oil reservoir. In the study, bench tests, including the phase behavior test, rheology studies and interfacial tension measurement are performed and reported for the optimum selecting method for the nano-emulsion which is going to be applied in the coreflooding experiments. Specifically, nanoemulsion systems have been mixed with Alaska North Slope West Sak heavy oil with 16 API°, which was dewatered in the laboratory condition, to investigate the rheology change during this process.

The experiment results suggest that the potential application of this kind of emulsion flooding is a promising EOR process for some heavy oil reservoirs in Alaska, Canada and Venezuela after primary production. Heavy oil lacks mobility under reservoir conditions and is not suitable for the application of the thermal recovery method because of environmental issues or technical problems.

The idea of nano-particle application in an EOR area has been recently raised by researchers who are interested in its feature- reaction catalysis-which could reduce in situ oil viscosity and generate emulsion without surfactant. Also, the nano-particle stabilized emulsions can long-distance drive oil in the reservoir, since the nano-particle size is 2-4 times smaller than the pore throat.

In conclusion, the nano-emulsion can be an effective enhancement option for an oil recovery method in a heavy oil reservoir which is technically sensitive to the thermal recovery method.
New Method to Diagnose and Improve Shale Gas Completions
Authors: Palmer Ian , Moschovidis Zissis
Published: February 2011

The method assumes a quasi-uniform volume of enhanced permeability during and after multi-stage fracturing of a horizontal well, and quantifies both injection permeability (by predicting shear failure and matching a microseismic pattern), and production permeability (by using rate-transient analysis to match gas rate). This leads to two different permeability-based diagnostics (production permeability and loss of injection permeability), which can be correlated with fracture treatment parameters (such as pump rate, spacing of frac segments, fracture fluid cleanup, damage by additives, and proppant design). The injection and production permeabilities illustrative of several case studies appear to be consistent with other tight gas determinations. Production permeabilities can be hundreds of times greater than matrix permeabilities, but only a very small fraction of injection permeability. The fracture-dominated injection permeability is large (tens of md) and the corresponding injection porosity is small <0.01%. The challenge is to retain more of the injection permeability (eg, by less damage or better proppant design). Injection permeability and porosity are generally consistent with properties of vertical fracture networks. Fracture spacing results suggest the shale can be fractured on a finer scale than revealed by microseismic data. Fracture widths appear to be consistent with widths quoted by Reiss. The method provides a new avenue for characterizing stimulation volumes (via injection and production permeabilities), and for diagnosing the effectiveness of a stimulation volume. Correlations between injection permeability loss and fracture treatment parameters should lead to improvements in volume stimulations. The perm-based diagnosis is a new approach to improve well stimulations, and is applicable to all shale gas plays.
Complete Solution for Transient Heat Transport in Porous Media, Following Lauwerier's Concept
Authors: Barends F. B.
Published: February 2011

The state of knowledge of heat transport in porous media lacks practical closed form solutions valid for simulating the complete process, including storage, convection, conduction, dispersion and thermal bleeding. In this paper, these various processes are explored and validation by analytical tools is extensively elaborated, adopting the concept of Lauwerier 1955, a jump temperature rise condition at the inlet and incompressible porous media. Much emphasis is put on convection and thermal bleeding, i.e. the heat transfer in adjacent formations. Convenient solutions for plane and radial situations are derived applying Boltzmann and Laplace transformation techniques. Excellent match is found with existing partial solutions and results of numerical codes (COMSOL). Comprehensive insight is obtained for the heating-up period (Danckwerts’ condition). As is shown in this paper, the analytical solutions are easily handled by MAPLE for quick assessment of specific effects and/or sensitivity aspects and in particular for disregarding processes of lesser importance when tuning detailed numerical modelling or interpreting exploitation data for the incorporation of thermal bleeding in an efficient way.
Modeling Facility Expansion Options under Uncertainty
Authors: Jablonowski C. , Ramachandran H. , Lasdon L.
Published: February 2011

During the concept comparison and selection phase of capital projects, decision makers compare development options and select one option to carry forward to detailed engineering. This effort is often complicated by uncertainty in one or more of the critical inputs. Therefore, project teams are tasked to investigate how different assumptions about the uncertainty influence optimal decisions. In cases where initial investment decisions are difficult and/or costly to change, the analysis of facility flexibility increases in importance. In its simplest form, the goal is to find the optimal balance of initial capacity and the allocation of space and other resources for future expansion. This paper reports the results of a research project where the authors develop an integrated asset model for a hypothetical deepwater asset and use the model to investigate various aspects of facility design under uncertainty. The method produces estimates for the optimal initial capacity, the likelihood of expansion, the expected size of expansion, and the willingness to pay for the option to expand. The approach is systematic, the model solves quickly and thus enables a wide scope of uncertainty analysis. The graphical output is intuitive and facilitates communication between the facility engineer, subsurface engineers, and management.
Volumetric Fracture Modeling Approach (VFMA): Incorporating Microseismic Data in the Simulation of Shale Gas Reservoirs
Authors: Harikesavanallur Arvind , Deimbacher Franz , Crick Martin , Zhang Xu , Forster Peter
Published: February 2011

The growth of hydraulically induced fractures can be very complex; this is especially true when fractures are initiated from horizontal wells that are drilled in naturally-fractured reservoirs (such as shale gas) where the hydraulic fracturing process leads to swarms of fractures forming complex three dimensional (3D) fracture networks. Traditional modeling methods, suitable for simple (penny-shaped) fracture geometries, oversimplify the 3D extent of a fracture swarm and fail to capture the real extent of the drainage volume, inevitably leading to unreliable production forecasts.

It is possible to estimate the extent of the stimulated volume for each stage of a hydraulic fracturing job from microseismic data. The Volumetric Fracture Modeling Approach (VFMA) then models the fracture network as a 3D volume with fracture properties described by variations of dual porosity parameters. The VFMA was successfully applied to modeling a horizontal well in the Barnett Shale with multiple hydraulic fractures. An automated history-matching procedure was used to estimate the productive volume from the initially stimulated volume.

The VFMA is especially suitable for multi-well or full-field simulation where other fracture modeling methods may not work due to gridding or simulator performance constraints. Using the VFMA, it is possible to obtain the real extent i.e. the drainage volume, of complex fracture networks in shale gas reservoirs. Understanding the drainage volume allows for well spacing optimization, which in turn determines the total well count, and ultimately the cost of field development.
How 24/7 Real-Time Surveillance Increases ESP Run Life and Uptime
Authors: Camilleri L. , MacDonald J.
Published: February 2011

This paper explains the development and implementation in the Schlumberger artificial lift real-time surveillance center of a workflow to track ESP alarms from their initial identification through their classification to the analysis of their root-cause. The workflow uses a QHSE database with Web access to enable collaboration between the surveillance center and field locations throughout Europe and Africa. Of more than 700 alarms which were substantiated over an 18 month period, over one third were classified as "critical", i.e. if no actions were taken, an Electric Submersible Pump (ESP) failure could potentially ensue. As such, real-time surveillance was seen to contribute to an increase in ESP run life, firstly, by preventing the ESP from being misoperated and experiencing excessive stress, and secondly, by using the alarm classification as the basis for service quality reviews to promptly identify remedial action items.
Improved Oil Recovery Methods: Applicability Screening and Potential Evaluation
Authors: Surguchev Leonid M. , Reich Eva-Maria , Berenblyum Roman A. , Schipanov Anton A.
Published: February 2011

Screening and analytical methods are often used for fast preliminary evaluations of various EOR scenarios. Screening is typically performed using real field experience and knowledge data bases, which summarize application of EOR methods to similar fields. Analytical methods are limited by simplified representation of the reservoir and EOR processes; however solutions are exact and not affected by the numerical dispersion. Often an analytical solution is used to verify numerical results. The advantages of analytical methods are in their speed and relatively small amount of data necessary to estimate the recovery of a certain EOR technique. The approach is viable and practical when a large number of reservoirs are to be screened for EOR applicability or when a decision over a new asset with limited field data is to be made.

A three-level approach to selection of EOR strategies is suggested. First the screening model allows for a fast first-order screening of key EOR applicability methods at given reservoir conditions. The applicability assessment is based on ranges for critical reservoir parameters, using a multi-criterion model and distribution functions. Than the model for oil recovery factor estimation based on the statistical data from projects carried out world wide is applied. Finally, analytical methods could be used for quantitative analysis and production profile calculations for main oil recovery methods: Depletion, Waterflooding, Cyclic Waterflooding, Polymer, Surfactant and Polymer/Surfactant flooding, Immiscible and Miscible Gas (CO2, N2, HC) flooding, Steamflooding and Immiscible WAG injection.

A wide range of reservoir parameters and computed results enable the user to perform rapid and comprehensive reservoir analyses as well as sensitivity studies. A unique feature of the developed program is its capability to handle a series of scenarios in only one single run. This tool can be compared with a “compass” helping reservoir and petroleum engineers to identify and successfully implement EOR/IOR methods at their fields.