bluuebunny/crossref_metadata_2025 huggingface dataset:
A Historical Survey of Summer Internships with a Review of Options for Increasing the Number of Interns Available for Industry.
Authors: Platt Frank Martin , Heinze Lloyd
Published: October 2011

Abstract Most of the major Universities teaching Petroleum Engineering encourage students to complete an internship before graduation. Two of the major schools, Texas A&M University and the University of Oklahoma require it before graduation. This paper will report the results of a survey of graduates in Petroleum Engineering on their experiences and career outcomes as they relate to internships. With this will be a report on the current enrollment in Petroleum Engineering at a majority of the schools offering a degree in this field. In conclusion the results will be combined along with comments from the survey participants to derive more options for students to obtain and participate in internships while in school. Historical Review Petroleum engineering careers especially in the beginning were more of a field operations versus the office engineer position found in other engineering fields. Graduates very quickly were put into the field and required to produce or if fortunate put under a mentor or supervisor to guide them as they developed. From this environment and the needs of the industry summer internships were created. Oil companies and students both benefited from this environment. Students were able to work in the field at some position and the oil companies had additional labor and an opportunity to view the students before graduation. In many cases students have been able to fund their education and the oil companies find the best candidates for permanent hire after reviewing the students' internships. This has been a program or vehicle for students for over 50 years and has changed dramatically since its inception. In the first summer (usually after their freshmen year) students literally were hired as a basic field employee (roustabout) and worked in that position for the summer. The student would not have a lot of experience yet but could learn how field operations functioned in this position. Many of the Engineers who participated in this type of initial internships call it the summer of scrapping rust off of tanks. The skill level required was not high but the supervisors could see who had initiative and who did not for their decisions for a second summer of internship with that company. Generally the second year would be a promotion into field operations. The intern would be assigned to the field supervisor or unit operators to learn how the field operates. In this position the intern would not have as hard a physical job but would be more into a learning environment. In this summer they would learn how the field operates, the reports filed, the tasks needed to keep operations in order and the methods employed to obtain the required results. These tasks, never covered in the classroom, are fundamental to the operational environment of a producing field. This could be considered the summer they learn the business model of operations.
Numerical Prediction of Relative Permeability from MicroCT Images: Comparison of Steady-State versus Displacement Methods
Authors: Sheng Q. , Thompson K. E. , Fredrich J. T. , Salino P. A.
Published: October 2011

Numerical prediction of rock properties is a rapidly evolving area that has the potential to influence dramatically how core analysis is performed. In this paper, we investigate the numerical prediction of relative permeability from micro-computed tomographic images using pore network modeling. Specifically, we apply four different algorithms to a digital image of a reservoir sample that has been tested using traditional core analysis, and compare the results. The four algorithms are the following: quasi-static, unsteady-state, steady-state periodic, and steady-state non-periodic. They differ significantly in terms of the physics that they are designed to capture and their computational performance, but there is no published research quantifying how these differences affect the simulation of relative permeability. We show that the traditional quasi-static algorithm exhibits outstanding computational performance, but gives results that are the most different from the other three methods. The unsteady- and steady-state simulations give surprisingly similar results given the differences in how relative permeability is obtained. The two steady-state methods differ little under the conditions tested. This result is encouraging because the periodic simulation is significantly more computationally efficient. However, it raises questions about the ability to capture hysteretic behavior. Phase saturations are mapped from the network results onto the digital images of the pore space as a means to help interpret differences in the pore-scale behavior of the models. Finally, results are compared to relative permeabilities from laboratory corefloods.
Effective Pressure and Microstructure Control on Resistivity Formation Factor and Seismic Waves Velocities
Authors: Tinni Ali , Sondergeld Carl. H. , Rai Chandra , Simo Herve
Published: October 2011

In clay-rich tight gas sand, conventional resistivity methods yield inconsistent saturation estimates, and simple velocity models such as the Biot-Gassmann do not accurately predict the saturation induced velocity variations in these formations. This paper presents an experimental study designed to better understand the electrical and acoustic properties of clay-rich tight gas sands. A comprehensive set of measurements including porosity - permeability, mineralogy, mercury capillary pressure and SEM imaging were conducted on six tight gas sands cores saturated with 25, 000 ppm NaCl brine. To complete the experiments, resistivity, compressional and shear wave velocities were measured on the same tight gas sands as a function of hydrostatic confining pressure (500 psi to 5000 psi) and pore pressure (500 psi to 3000 psi). During these experiments, the time necessary for pore pressure equilibrium was determined to be at least three hours. The tight gas sands studied have porosities ranging from 4.5% to 8.3% and permeabilities between 18 μd and 82 μd. Their mineralogy is dominated by the presence of quartz with clay content as high as 28 wgt%. The SEM imaging shows the presence of a significant number of low aspect ratio pores and authigenic microcracks. The formation factor and seismic velocities data were used to evaluate the effective pressure law for each of these petrophysical properties. The effective pressure dependency for the formation factor and the seismic velocities observed are in opposition to each other. The analysis of the effective pressure coefficient n for the formation factor showed a general increase from a value generally close to 1, by 31% over a differential pressure range of 500 to 2500 psi. This same coefficient n generally equals about 0.92 for low differential pressure but decreased by about 30% for compressional and shear wave velocities. Using simple considerations, we established that a change in n values by 30% can induce an error in pore pressure prediction of 15%.
Evaluating the Long Term Benefits of Improved Fracture Treatments
Authors: Blackwood K. , Flowers J. , Handren P. , Pope C. , Palisch T. , Chapman M. , Godwin J.
Published: October 2011

It is understood that improved hydraulic fracture treatments increase production rates from most reservoirs. However, are these gains short lived, or do they yield incremental recovery? Is the improved productivity related to recovery of additional reserves or merely an acceleration of existing reserves?

Frequently, the impacts of design improvements are demonstrated by improved initial production (IP) rates or perhaps evaluated base on 6- to 12-month cumulative production increases. Field development decisions are often made based on these initial results, never again to be reviewed for long term corroboration. Rarely are the rate, reserves, and economic impact of these design changes evaluated and documented over longer production periods. As such, while a particular design change may pay out in two or three months, the question remains as to whether the enhancement represents merely a short term acceleration of production or in fact an increase in hydrocarbon recovery.

This paper will review the production results from several tight gas and unconventional reservoirs in which hydraulic fracture designs were upgraded to premium proppant, for which the results were documented in previous SPE papers. Areas evaluated include wells in the Cotton Valley-Taylor and Haynesville Lime of East Texas, the Haynesville Shale of North Louisiana and the West Texas Canyon Sand; all were evaluated and documented shortly after implementation. Raw production differences will be reviewed along with decline curve analyses, using updated production to evaluate both near and long term recovery impacts.

In addition to (re)evaluating for technical success, economic evaluations are provided to determine whether the design improvements truly resulted in favorable economic outcomes, as suggested in the original evaluations. When possible, these new evaluations will be compared to original recovery forecasts to ascertain whether the original conclusions still hold.

This paper should be of interest to anyone who evaluates the benefits of fracture design changes in their completions, and will provide insight on the accuracy of initial evaluations compared to actual long term production. It will also further investigate the benefits of improved fracture designs.
Parametric Investigation of Shale Gas Production Considering Nano-Scale Pore Size Distribution, Formation Factor, and Non-Darcy Flow Mechanisms
Authors: Michel G. G. , Sigal R. F. , Civan F. , Devegowda D.
Published: October 2011

The effects of the parameters involved in shale gas reservoir simulation are investigated using an improved transport equation for description of gas flow in nano-Darcy permeability media. This approach takes into account the effects of molecular collisions at the pore wall and is valid in all flow regimes: Darcy, slip, transition, and free-molecular flow. The study generalizes a transport equation valid for all flow regimes for an ideal gas in a capillary tube and extends the formulation to quantify the effect of a distribution of pore sizes for different flow regimes. We first describe the adopted methodology to model ideal gas transport and then account for real gas behavior by modifying the conventional definition of the mean free-path. The relationship of this approach to the Klinkenberg correction for slip flow and other published formulations that are described as the sum of a Darcy term plus a diffusive transport term are examined. An application of the present approach and its implications are demonstrated by means of a numerical example involving a hydraulically-fractured shale gas reservoir producing at a constant rate. The bottomhole pressure predictions from the non-Darcy formulation indicate a substantial deviation from the bottomhole pressure predicted by assuming Darcy flow and consequently, can be expected to have serious implications for production forecasting and planning for well abandonment. In particular, for infinite acting flow regimes that are commonly observed for shale gas wells, our calculations indicate that flowing bottomhole pressures tend to be higher than those calculated using a transport formulation governed by Darcy's law, thereby describing the potential for significantly enhanced productive well life.
Fiber Optic Strain Sensing at the Sand Face Enables Real-Time Flow Monitoring and Compaction Mitigation in Openhole Applications
Authors: Earles Denise M. , Stoesz Carl W. , Surveyor Nilufer , Pearce Jeremy G. , DeJongh Hans A.
Published: October 2011

Subsurface stresses can cause formation faults, slippage, and reservoir compaction, which can damage or permanently shut in a well. Traditional means of detecting these failures are limited and usually require moving a costly rig onto locations, and then interrupting production to re-enter the well. This results in late detection of issues and allows limited counteractive options.

A new system has been developed to actively monitor strain and temperature of wells. The system consists of three key enabling technologies: A fiber optic support device deployed at the sand face, a cost effective high-flow liner system that protects the instrumentation in openhole applications, and two optical wet connects for up to 12 channels.

The fiber optic support device provides a means of holding a helically wrapped optic fiber rigidly in place at the sand face. This new technology can be installed over traditional sand screens in gravel pack or frac pack applications, with no negative impact on the sand control functionality of the screens, or the quality of the pack. The installed fiber optic provides the equivalent of a strain gauge positioned every centimeter along the length of the producing zone.

For openhole applications, a high-flow liner system was developed to protect the fiber optic support device, and the control lines. This system includes a special quick connect that simplifies the on-rig assembly and allows torque transmission in an openhole deployment.

The final key to this system is the two 6-channel optical wet connects, allowing a total of 12 connected channels. This game changing technology provides an information conduit between the fiber optic at the sand face and operators at the surface. The same wet connect can also be used to connect more traditional means of measurements such as pressure-temperature gauges, or distributive temperature sensing (DTS).

The information relayed through this system allows the operator to infer flow and detect subsidence or compaction of the sand face before the well is compromised, allowing time to plan and execute mitigative actions. This paper will discuss the design, testing, and potential applications of this new system.
Interpretation of CO2 Sequestration-Induced Surface Deformation over KB-502 at Krechba, Algeria
Authors: Davis Eric
Published: October 2011

The Krechba field is part of a gas development in Central Algeria where CO2 is being injected to develop carbon-storage techniques within an active gas-producing reservoir. In 2004, three CO2 injectors (KB-501, KB-502, and KB-503) began placing CO2 in a 15-to 20-m thick target zone at a depth of roughly 1850 m. Above the target zone lies approximately 1, 000 m of very low permeability carboniferous mudstones. This caprock is expected to provide long-term sequestration of the injected CO2.

Surface-deformation monitoring measured using differential interferometric synthetic aperture radar (InSAR) has proven to be one of the more useful of a wide array of monitoring methods deployed at Krechba. The unique, horseshoe-shaped uplift pattern around KB-502 has been the subject of several technical papers to date. The analysis presented in this work, however, is unique in that it does not place any constraints on the location of strain sources that produce the measured uplift. The results of this analysis, which indicate strain sources shallower than the injection horizon, coincide well with formation properties determined from logs and 3D seismic surveys. The implications of fluid intrusion into depths shallower than the injection interval, even if that fluid is displaced formation water rather than CO2, are significant for the project operators.
Well Performance Diagnosis with Temperature Profile Measurements
Authors: Tabatabaei M. , Tan X. , Hill A. D. , Zhu D.
Published: October 2011

The measurement of the temperature profile of a well has been a primary part of production logs since the inception of these logs and continues to be a routine production logging measurement. In recent years, the increasing application of fiber-optic based distributed temperature sensors, either permanently installed in the well completion, or temporarily deployed, has provided a source for additional temperature profile data. In this paper, we present methodologies for interpreting numerous conditions in wells from temperature profiles. For each method, the underlying theory of the interpretation, and one or more field examples are presented. The most fundamental well property that can often be obtained from a temperature profile is the well's inflow profile - the locations and relative rates of inflow along the well. Simple analytical methods for interpreting the flow profiles of vertical oil producing wells are presented along with examples of this interpretation.

Another key application of temperature profile measurements, particularly for horizontal wells, is the location of water or gas entries in oil-producing wells. We will show how water or gas entries create temperature anomalies along horizontal wells caused by the differences in the Joule-Thomson coefficients of the different phases or by the water or gas source being from below or above the well depth, as in a coning situation. We illustrate how such water or gas inflows can be quantitatively identified by applying standard inversion methods to the measured temperature profiles, yielding the locations and rates of water or gas entries.

Another growing application of temperature profile measurements is the analysis of stimulation treatment (fracturing or acidizing) fluid placement. Temperature profiles measured during treatment pumping, during a flowback period, or after shut-in can be analyzed to determine the amount of stimulation fluid placed in different completed intervals along the well. A related analysis method using transient temperature profile measurements provides a means of determining layer properties of permeability, skin factor, and damage depth. This method can be applied before a stimulation treatment to aid the stimulation design, or post-job to evaluate treatment results.
New Perspectives in Technology Transfer and Training for the Real World
Authors: Fiffick William , Markham Meredith A.
Published: October 2011

As oil field engineers, scientists, and technologists are challenged to solve new and more complex problems, the ability to properly apply oil field technology is vital to our success.

But as the technology is applied, it can be just as important to document and transfer those "lessons learned." While much of the training provided to those entering the workforce is built on foundational concepts, products, and processes, much more is required. New processes, practices, and products are constantly being invented, refined, and/or improved. The ability to quickly and systematically capture these lessons can save hundreds of work hours. Applying new technology can also pay great dividends by helping field engineers propagate technology and foster continuous improvement.

So, how do we capture that knowledge and those lessons learned? What best practices can be modeled? How do we leverage learning technology to archive, and transfer these important lessons? How do we optimize the time commitments from our subject matter experts? What emerging technologies are available which may assist with the capture, transfer, and delivery efforts? How are the varied learning methodologies satisfied?

The following is a case study from a major oil field services company outlining effective and efficient technology transfer efforts. Best practices as well as lessons learned are discussed.
Evolution of High Build-Rate RSS Changes the Approach to Unconventional Oil and Gas Drilling
Authors: Hummes O. , Janwadkar S. , Powers J. , Bond P. , Anderson M. , Chesher S. , Paugh W. , Wiggers C. , Roberts G. , Schmidt S. , Hildebrand J.
Published: October 2011

This paper discusses the development, testing and optimization of a rotary steerable system (RSS) developed specifically to address the challenges around drilling wells in unconventional reservoirs in North America. As with offshore areas, rotary steerable drilling technology has rapidly gained acceptance for onshore use because of its clear advantages in directional control, wellbore placement and lateral reach, while matching or exceeding the drilling performance of conventional systems. The further growth of RSS into the drilling of unconventional reservoirs has been limited by the build-rate (BUR) capabilities of established RSS that prevent operators from successfully drilling curve and lateral sections in one run. In recent years, service companies have worked to improve the capabilities of rotary steerable drilling systems to meet the specific needs of drilling horizontal wells in unconventional oil and gas reservoirs. Due to lease spacing and limited vertical depths to achieve horizontal orientation, greater buildup rates (BUR) are required to maximize the lateral lengths in the reservoir. In addition to developing higher doglegs in the curve, the system should also enable lateral control to minimize tortuosity, facilitate easy casing running and optimize successful multistage fracturing. The authors outline how specific challenges, such as reduction in drilling time, improved wellbore placement, and more efficient completion and fracturing operations are addressed by the introduction of the new system. Included in this paper is a description of how the bottomhole assembly (BHA) and drill-bit properties are matched and optimized to deliver best directional control and drilling performance, according to formation characteristics in the Granite Wash play in the central USA. Explanations detail how the new system capabilities expand the possibilities to develop reservoirs using pad drilling, the use of more complex well profiles and real-time reservoir navigation, leading to increased hydrocarbon production.
Improved Petrophysical Core Measurements on Tight Shale Reservoirs Using Retort and Crushed Samples
Authors: Handwerger D. A. , Suarez-Rivera R. , Vaughn K. I. , Keller J. F.
Published: October 2011

Gas shales have become an important resource for the production of hydrocarbons in North America, and are being explored as a resource on other continents as well, based on their rapidly increased importance to the North American market and promise to boost domestic production elsewhere. There are numerous pricing and geopolitical reasons for this active exploration, but regardless of where in the world they are being explored, gas shales share some fundamental properties that make them virtually impossible to analyze with conventional core analysis methods or conventional petrophysical models based on log data. These properties are basically that gas shales are tight, with permeabilities in the 10s to 100s of nD, have low (effective) porosity, typically less than 10%, and have high kerogen and clay content. While there are some variations of these themes (e.g. shales with higher detrital input, making them siltier or silty-laminated), in general the tightness of the rock and abundance of clay minerals and kerogen pervades, and that causes a number of challenges to analysis.

We have developed analytical methods for evaluating these reservoirs on core by using crushed material to enable better access to the pore space, retort analysis to measure separately free, bound and structural water saturations and also distinguish water from oil, and pressure transient analyses for the determination of permeability. Conventional core analyses (e.g. Dean Stark), applied to kerogen- and clay-rich rocks fails in separating free from bound waters and water from light oils, thereby missing critical inputs into calculating effective saturations, effective porosities and clay-bound water volume. In addition, the amount of oil recovered from retort, as an independent quantity, can be a useful proxy for kerogen maturity. From a permeability standpoint, unconventional reservoirs are usually too tight to allow for steady-state permeability measurements, and microfracturing is often too pervasive to allow for reliable permeability measurements on whole plug samples. As a result, we have developed a crushed-sample pressure decay system to measure the nD permeabilities typical of shales, and a stepped confinement pulse-decay method for measuring micro-Darcy (and higher) permeabilities in more texturally complex, siltier or sandier unconventional reservoirs that typically have these higher permeabilities.
Modeling of Pressure and Solution Gas for Chemical Floods
Authors: Roshanfekr M. , Johns R. T. , Delshad M. , Pope G. A.
Published: October 2011

The goal of surfactant-polymer flooding (SP) is to reduce interfacial tension (IFT) between oil and water so that residual oil is mobilized and high recovery is achieved. The optimum salinity and solubilization ratio that correspond to ultra-low IFT have recently been shown to be a strong function of the methane mole fraction in the oil at reservoir pressure in some cases. We incorporate a recently developed methodology to determine the optimum salinity and solubilization ratios at reservoir pressure into a chemical flooding simulator (UTCHEM). The proposed method determines the optimum conditions based on density estimates using a cubic equation-of-state and measured phase behavior data at atmospheric pressure. The microemulsion phase behavior (Winsor I, II, and III) are adjusted based on these predicted optimum salinity and solubilization ratio in the simulator. Parameters for surfactant phase behavior equation are modified to account for these changes and the trend in equivalent alkane carbon number is automatically adjusted for pressure and methane content in each simulation gridblock. We use phase behavior data from several potential SP floods to demonstrate the new implementation. The implementation of the new phase behavior model into a chemical flooding simulator can greatly aid in the design of SP floods so that SP flooding failures are less likely to occur. The simulator will also make more accurate estimations of oil recovery. The new approach could also be used to handle free gas that may form in the reservoir. We show that not accounting for the phase behavior changes that occur when methane is present at reservoir pressure can greatly affect the oil recovery of SP floods. Improper design of a SP flood can lead to more oil being produced as a microemulsion phase than as an oil bank. This paper describes the procedure to implement the effect of pressure and solution gas on microemulsion phase behavior in a chemical flooding simulator, which requires the phase behavior data measured at atmospheric pressure.
Eliminating Slickwater Compromises for Improved Shale Stimulation
Authors: Brannon Harold D. , Bell Charles E.
Published: October 2011

Hydraulic fracturing stimulation is generally accepted as requisite to obtain commercial production from low permeability formations, including oil- and gas-bearing shales. Low viscosity slickwater fluids generate fractures of lesser width and therefore greater fracture length, theoretically increasing the complexity of the created fracture network for better reservoir-to-wellbore connectivity. Unfortunately, slickwater fluid is an inherently poor proppant carrier, necessitating high pump rates to achieve flow velocities sufficient to overcome the tendency of the proppants to settle. Proppant settling within surface equipment or long horizontal laterals can result in premature treatment termination and poor productivity. Crosslinked and linear gel systems have been used to mitigate the proppant settling and placement concerns, but the high viscosity that accomplishes this objective may significantly reduce the desired fracture complexity.

A ‘new’ crosslinked polymer system deploys the best attributes of slickwater and conventional crosslinked fluids systems to maximize proppant transport through the surface equipment and long laterals before breaking to create a desirably complex fracture network. The fluid is crosslinked on surface with an ultra-low loading of high-yield guar polymer loading that achieves surface viscosity sufficient to carry proppant from the pumping equipment through the horizontal lateral and perforations. Controllable viscosity degradation converts the fluid to a slickwater viscosity within the reservoir to provide the desired complex fracture network. Gel break-back timing may be used to control the onset of complex network development. For example, it may be desirable to generate a planar fracture for a distance from the wellbore before reverting to the low viscosity-induced complex fracture development. Thus, the system displays the positive attributes of both slickwater and crosslinked gel systems while simultaneously overcoming the negatives associated with each.

Fracture modeling illustrates the utility of the fluid performance management and controlling the onset of complex network development. Case histories compare applications of the system to offsets treated with conventional slickwater and crosslinked gel fluids, including well performance and an assessment of the impact upon operational reliability.
A Simplified Method to Estimate Peak Casing Pressure during MPD Well Control
Authors: Chirinos Jose E. , Smith John R. , Bourgoyne Darryl
Published: October 2011

The constant bottom hole pressure (CBHP) method of managed pressure drilling (MPD) has important advantages versus conventional drilling, especially for well control. One is the ability to stop formation flow by increasing casing pressure while continuing to circulate rather than shutting in the well. A requirement for applying this method is for the pressure rating of the rotating control device to exceed the maximum casing pressure experienced during kick circulation.

This peak casing pressure is typically estimated by applying the gas law for a single bubble calculation or by using a computer simulation. This paper describes a new, step wise method that combines gas law calculations with empirical knowledge developed by Ohara (1996) of gas distribution and velocity based on full-scale kick circulation experiments.

The new method was applied to predict the maximum casing pressure expected during kick circulation for a range of well geometries, kick sizes, fluid properties, and circulating rates. The results of applying the new method were compared to single bubble calculations, transient multiphase computer simulations, and the actual pressures recorded in test wells.

The proposed method provides a simple, potentially more accurate way to predict the maximum casing pressure during circulation of a gas kick. Consequently, it can be used to determine the surface equipment pressure ratings and formation fracture resistance required to provide the desired kick tolerance to drill safely using MPD equipment for well control.
BMPs for Minimizing Environmental Impacts: A Resource for Communities, Government and Industry
Authors: Mutz K. M. , Rice K. L. , Walker L. , Palomaki A. C. , Yost K. D.
Published: October 2011

The Intermountain West Oil and Gas BMP Project (BMP Project) is a collaborative effort of the Natural Resources Law Center and its partners, including the Environmentally Friendly Drilling Program. The BMP Project has developed a comprehensive, free-access, searchable, web-based database of oil and gas best management practices (BMPs) for the Intermountain West (http://www.oilandgasbmps.org). The database includes over 7, 000 BMPs addressing air and water quality, soils, visual aesthetics, health and safety, wildlife, and other resources. These BMPs are currently required or recommended for responsible resource management by various levels of government, communities, conservation organizations, industry groups, or individual companies. The project website includes resource pages on development issues and controversies as well as case studies of industry efforts to minimize environmental impacts. A community page illustrates community-industry efforts to negotiate, rather than litigate the best options for rational development. The BMP database focuses on source materials regarding both conventional and unconventional development from the Intermountain West states of Montana, Wyoming, Utah, Colorado and New Mexico. The website resource pages also focus on the Intermountain West, but draw on information from unconventional gas developments beyond this region.

This paper describes the Intermountain Oil and Gas BMP project resources and addresses the role of BMPs within the range of law and policy options available for facilitating development while promoting environmental and community health and safety. The paper also summarizes what is known of the efficacy and cost effectiveness of BMPs.

Communities embrace development for the economic benefit it brings to their areas, but both communities and conservation groups vigorously work to prevent oil and gas development from recklessly disrupting their lives and destroying sensitive environments. Governments consider new means to control impacts while still promoting development. Many companies work to balance cost effective production with practices that protect the environment and the communities they impact. The Intermountain BMP project helps these stakeholders identify appropriate practices for minimizing impacts to surface resources during planning, design, construction, drilling, operations, reclamation, and monitoring. BMP Project resources can also help stakeholders learn to work together to fuel the country's energy requirements and address the economic needs of communities without sacrificing the quality of their environment.
LWD for Well Placement and Formation Evaluation Towards Completion Optimization in Shale Plays
Authors: Kok Jeffrey , Shim Yen Han , Tollefsen Ed
Published: October 2011

Unconventional shale plays are characterized as low porosity and low matrix permeability reservoirs. In addition, they lack an obvious seal or trap, are of large regional extent, and understood to be heterogeneous in nature.

Due to this understanding, vertical, pilot wells are commonly drilled to evaluate rock properties and determine horizontal shale gas targets. Horizontal wells are drilled then completed by means of hydraulic fracturing to maximize reservoir contact and enhance production performance.

To position the lateral production borehole within the defined target, geosteering is commonly performed using a single averaged gamma ray measurement. In the initial development phases, this is often perceived as the most economic means for measuring and steering the production hole.

However, acquisition of sufficient LWD data demonstrates that by relying on a single measurement, structural models can be made to present several different possible correlation scenarios. Obviously, a non conclusive structural interpretation will negatively impact any efforts of evaluations for efficient field development. While, averaged resistivity measurements may be utilized as an additional correlation reference to complement gamma ray, improvements to correlation accuracy are best achieved with azimuthal images such as density, resistivity or gamma ray images. Real-time image measurements are used identify thin layers while cutting up or down dip as well as structural dip authentication along the well trajectory to provide a high level of confidence in the interpreted geosteering model.

Effectively, an accurate structural model is also an effective tool to design completion, correlate formation properties and refine target sizing while providing the foundation for formation evaluations.

This paper illustrates how correlations using only an averaged gamma ray measurement for structural modeling and steering of a production hole can result in multiple interpretations. This uncertainty is a potential cause of inconsistent reservoir interpretations and low or varied production across a given field.

In comparison, acquiring sufficient measurements while drilling for formation evaluation, and well placement can be applied to deliver consistent production results and provide a common platform for completion design practices.
Pressure Transient and Production Data Analysis of Horizontal Well in Unconsolidated Formation in Frade, Brazil
Authors: Pan Yan , Ewy Russ , Ringe Don , Kamal Medhat M. , Affinito Ralph , Sotunde Oluwole
Published: October 2011

Frade Asset is a medium-heavy-oil field located in the Northern Campos Basin, approximately 75 miles offshore from Rio de Janeiro, Brazil in 3500 ft water depth. The structure is a low relief anticline with two main fault blocks consisting of four stacked unconsolidated reservoirs. First production started in June 2009, and field development target peak production is 80, 000 barrels of crude oil per day. Currently, the field is producing from 9 horizontal oil wells with 3 vertical water injection wells to maintain reservoir pressure. Continuous well monitoring and reservoir characterization is the key to cost-efficient development in this deep-water subsea field. Therefore, most wells in Frade are equipped with permanent down-hole gauges for reservoir surveillance.

In this paper, we discuss the impact of three efforts on field performance: 1) monitoring the pressure and production data from horizontal wells since first production, 2) the real-time pressure transient analysis (PTA) of a series of buildup tests, and 3) the transient study combined with long-term production data analysis (PDA). The study results provide insight into formation quality and the change of well conditions with time. The estimations of current drainage area, average reservoir pressure, and original oil in place help to optimize the field development plan. The impacts of pressure-dependent oil properties and rock compaction were also studied, and the first quantitative evaluation of pressure-dependent permeability/porosity reduction was performed using both long-term dynamic well data and laboratory core experiment results. The applications of PTA and PDA in Frade showed that using current advanced technologies properly can yield valuable well and reservoir information from well pressure and rate data.

The positive impact of focused efforts to measure and analyze pressure transient and production data, and to use pressure-dependent permeability and porosity values in managing a large asset, demonstrated best practices that may be followed in other oil and gas fields.
A Multiple-Porosity Model for Evaluation of Giant Naturally Fractured Gas Sandstone Reservoirs in Bolivia
Authors: Sivila L. J. , Graves R. M. , Aguilera R.
Published: October 2011

A multiple-porosity petrophysical model that honours heterogeneity and the complex geologic characterization of a giant gas reservoir in Bolivia has been developed. The model handles five different porosity types: macrofracture, low conductivity fracture, microfracture, shale, and dispersed and intergranular porosity. Geological evaluation indicates that these porosities have some degree of connectivity. Due to the various porosity components, the model permits a more accurate estimation of the cementation exponent (m) and provides a better understanding of the gas storage and water saturation distribution in the reservoir. The model also has the capability to account for lithological variations throughout the field.

There is a wide variety of available models for estimating petrophysical properties, but none was found that could represent the available data for this field realistically. The Borai correlation, developed exclusively with data from Abu Dhabi carbonate reservoirs, has been used in the past to evaluate the Bolivian reservoir. As a consequence, we undertook the petrophysical analysis from a different perspective and developed the proposed model. Taking into account the various porosity types, lithology and structures depicted in the field geological characterization has been essential to develop the solid petrophysical model presented in this study. This in turn is an important aid for understanding reservoir behaviour.

The proposed multiple-porosity model allows sound characterization of the Bolivian gas reservoir considered in this study because it is strongly linked to the field geological heterogeneity. We anticipate that given the flexibility of the model, it will be applicable for characterization of sandstone reservoirs with similar characteristics in other regions around the world.
Assessment and Prediction of Erosion in Completion Systems under Hydraulic Fracturing Operations Using Computational Fluid Dynamics
Authors: Farahani Rezsa , Lastiwka Marty , Langer Doug , Demirdal Barkim , Matthews Cam , Jensen John , Reilly Adam
Published: October 2011

High rate injection or production of fluids with sand particles places wellhead components and downhole assemblies at risk of erosion damage. Depending on the severity and location of the material loss, this may pose a significant well loss or blowout hazard. For this reason, assessment and mitigation of erosion can be critical for such applications.

In this work, Computational Fluid Dynamics (CFD) was used in conjunction with erosion models to assess the erosion damage characteristics associated with the operating conditions and equipment for a high-rate, shale gas reservoir fracturing application. The work was based on the severe erosion damage experienced by EnCana as a result of high rate hydraulic fracturing operations performed in horizontal shale gas wells at their Horn River, BC field development. Material losses were observed within the wellhead equipment as well as in the LTC couplings of the production casing string near surface in several wells. CFD models were developed for the existing wellhead and wellbore geometries and used to simulate a range of hydraulic fracture operating conditions in an effort to predict the locations and degree of material loss in the components in each case. The models were calibrated with caliper log data and measurements taken from casing samples retrieved from several wells. The analyses suggested that well head system modifications, such as tubing head spool changes and use of spacer spools, could be effective in substantially reducing material losses in the tubular connections. In addition, sensitivity analyses were performed for different wellhead configurations and variations in the hydraulic fracturing parameters to determine the factors that likely had the most influence on the connection material losses. The results served to demonstrate that it is possible to use CFD with erosion models as predictive tools to identify locations of severe erosion in completion systems, and, when calibration data is available, to quantify the amount of material loss in wellhead and downhole components. This information can aid in designing optimum completions systems, and in defining operating conditions which can reduce the risk of equipment failure, potential blow-outs, and associated safety and environmental hazards.
Case Study: Successful Implementation of Driving Safety and IVMS Program
Authors: Gale B. R. , Trostel M. V. , Armitage D. L. , Mason M. A. , Bautista L. S.
Published: October 2011

Over 40% of all injuries and fatalities in the oil and gas industry are attributed to vehicular operations. Additionally, nearly one third of all fatalities were due to highway motor vehicle crashes as reported in a study of deaths in the industry between 20032008 (Retzer, et. al, NIOSH, 2011). For years the industry has tried a myriad of strategies to influence behavior, yet the risk of motor vehicle incidents (MVI's) remains a challenge for the industry and remains at the top of the list of hazards.

The proliferation of inexpensive sensors and wireless networks presented an opportunity to measure subtle patterns of human behavior that might be leading indicators of a driver's crash risk. Several years ago, Encana Oil & Gas (USA) Inc. (Encana) and a Denver based technology firm, Cartasite, teamed up to study driver behavior. The goals of this research were twofold:

profile the patterns of individuals against a large population of drivers, and attempt to influence those patterns to reduce risk, fuel consumption, and emissions.

The yearlong study program produced encouraging results and after analyzing the data, the decision was made to move forward with commercial product development. Encana has now deployed this technology on its entire fleet for over a year. A new Driving Safety Program has been put in place at Encana to effectively leverage the insights and data being collected. The impact of Encana's Driving Safety Program, presented herein, are encouraging and suggest that corporations may well be able to significantly reduce motor vehicle incidents and increase safety for field workers.
Prediction of Asphaltene Deposition in Porous Media by Systematic Upscaling from a Colloidal Pore Scale Model to a Deep Bed Filtration Model
Authors: Boek Edo , Fadili Ali , Williams Michael John , Padding Johan
Published: October 2011

We have successfully validated the Asphaltene Option in ECLIPSE, using an experimental data set from the literature. We compare our results with a previous Deep Bed Filtration simulation model of the same data. We find that the experimental data can be reproduced by using the surface deposition parameter α only. This provides an important simplification of the Asphaltene Option in ECLIPSE. Moreover, the values of α can be predicted from a pore scale colloid dynamics simulation model using the Stochastic Rotation Dynamics (SRD) technique. It turns out that the values for α obtained in the literature (Wang, 2001) and our own ECLIPSE results are consistent with the predictions from the SRD simulation model. This may give an advantage over other asphaltene deposition models available in the literature.
Benefits and Application of a Surface-Controlled Sliding Sleeve for Fracturing Operations
Authors: Shaw Joel
Published: October 2011

Recent improvements in fracturing technologies have allowed access to tight formations that previously were considered unprofitable. The most common of these technologies is a ball-drop-actuated sliding sleeve that allows operators to economically isolate and fracture ten to twenty zones in a single well. While these technologies have been well proven, there are still drawbacks such as:

Each zone requires a drop in the production string ID The zones must be stimulated beginning at the toe and ending at the heel Many applications require milling-out of ball seats after fracturing When possible to move sleeves after fracing, a workover is required.

A system has been developed to alleviate these limitations. This system includes well profile and isolation similar to the ball-drop sliding sleeve system but offers control of the sliding sleeves from the surface. This eliminates the cost and downtime of intervention. The system consists of an ICV (interval control valve) that has been optimized for fracturing applications. It is essentially an intelligent completion method that can withstand the extreme environment of a frac application. This allows the operator to frac the zones in any order, re-frac at a later date, close zones to allow pressure to build, eliminate water cut, and conduct transient pressure analysis of any zone without the necessity of a workover.

This paper discusses the use of surface-controlled sliding sleeves in frac-pack operations and the benefits that an operator can realize by installing the new sliding sleeves in tight formations.