bluuebunny/crossref_metadata_2025 huggingface dataset:
Stimulated Shale Volume Characterization: Multiwell Case Study from the Horn River Shale: I. Geomechanics and Microseismicity
Authors: Hurd O. , Zoback M. D.
Published: October 2012

We carried out an integrated geomechanical and microseismic analysis of a gas shale production pad in the Horn River Basin containing 16 horizontal wells, over 270 individual hydraulic fracture stages, and more than 15,000 located microseismic events to better characterize the reservoir response to hydraulic fracture stimulations. Geomechanical constraints indicate that the pad is generally characterized by a strike-slip stress regime (SHmax > SV > Shmin) with the maximum horizontal stress (SHmax) oriented NE-SW. A pre-existing NNE-SSW-trending fault passes through the pad and appears to be well-oriented for slip in the current stress field. Measurements of Shmin, the minimum principal stress, are moderately elevated in some stages in the vicinity of this fault, and also appear to gradually increase from toe to heel in most wells. Microseismic b-values, which quantify magnitude scaling relationships for a population of events, vary from stage to stage but typically range between 1.0 and 2.5, indicating a relative abundance of small magnitude to large magnitude events compared to naturally-occurring earthquake populations (b ≈ 1.0). This observation has also been reported in other shale gas stimulation projects. We also utilize the double-difference relocation technique in an attempt to improve the accuracy of microseismic event hypocenters recorded during individual hydraulic fracture stages. The technique produces a clear hypocenter lineation, which unfortunately appears to be an artifact arising from the limited monitoring array configuration and not an actual structure within the reservoir. Finally, we analyze a population of microseismic events recorded during a single hydraulic fracture stage and find that the events can be broken into small sub-groups of events based on high waveform similarity, which suggests repeated slip on small-scale reservoir structures. We conclude that reservoir response to hydraulic fracturing is generally characterized by seismic deformation occurring on small fractures created or reactivated by the hydraulic fracturing stimulations, although there is also some evidence for seismic deformation occurring on larger-scale localized structures within the reservoir.
A Fresh Look at Completion Reliability Supports Sand Control Selection
Authors: Capderou Christian , DiLorenzo Neil
Published: October 2012

Although several publications provide reliability estimates based on a constant rate of failure (CFR), the results remain controversial. The use of published results in completion selection and Reliability Availability Maintainability analyses (RAM) is often challenged by industry peers.

This study sets out to generate reliability estimates for three sandface completion techniques applicable to horizontal oil producer wells in unconsolidated sands: Open Hole Gravel Pack (OHGP), Expandable Sand Screens (ESS) and Cased Hole Oriented Perforating (CHOP). The data set included subsea and platform wells (including deepwater fields) from several regions of the world using a consistent definition of failure.

The team first conducted a survey across operated and non operated assets worldwide including subsea deepwater and platform wells and then defined a failure criterion to be used across all sandface completions. The data gathered was then analyzed to select the appropriate Probability Distribution to represent variable failure rates.

This fresh look at sandface completion life data found that OHGPs are a much more reliable sandface completion option compared to ESS. OHGP completions are estimated to have a mean time to failure (MTTF) of 29.0 years (5.3 years to 52.7 years with 95% confidence). ESS completions in this dataset have a MTTF of 6.2 years (3.8 to 8.6 years with 95% confidence). The results obtained for CHOP could not be directly compared to OHGP and ESS due to limited data available.

The results from these analyses were used along with other value drivers to support the sandface completion selection for a Major Capital Project (MCP). The life distributions found in this study were also used to build a RAM model for major capital projects – providing life of field OPEX and well availability (percent uptime) estimates.
Effect of Multicomponent Adsorption/Desorption Behavior on Gas-In-Place (GIP) Calculations and Estimation of Free and Adsorbed CH4 and CO2 in Shale Gas Systems
Authors: Das Mita , Jonk Rene , Schelble Rachel
Published: October 2012

Unconventional shale gas resources have become a major component of the energy mix in North America, with future growth projected globally. The nature of storage and transport of hydrocarbon gas are not yet fully understood in these plays. Adsorption in gas shales is expressed by the Langmuir isotherm, which is the capacity of the rock to adsorb gas at any given temperature. The Langmuir isotherm is generally measured in the laboratory with crushed rock samples. In the presence of CO2 with CH4 in the free gas state, the desorption behavior and measurement becomes more complex.

There are significant differences in sorption experimental procedures and results reported by different vendors. This study addresses the challenges in data variability in sorption measurement, the differences in EUR and GIP calculations, including existing limitations on adsorption measurement and reporting techniques. The results and implications of round- robin experiments with four different samples across four vendor laboratories are shown with multi-component adsorption isotherm analysis. The limitations and variations based on vendor data measurement techniques for accurately calculating GIP and EUR in the case of multi-component adsorption are discussed.
The Evolving Unconventional Gas in China
Authors: Wang Xiuli
Published: October 2012

Natural gas is emerging as the premier fuel of the world economy and will play a pivotal role in China. China, the pre-eminent industrialized nation of the era, needs new and very large energy supplies and currently does not even come close to supply adequate indigenous resources in both quantity and variety. Coal still overwhelmingly dominates the energy mix, causing both major economic and environmental complications. Energy will be "China's choke point" on its path of becoming a world power.

Today, natural gas accounts for only a small fraction of the Chinese energy mix. With a share of 4 percent, natural gas will have to grow to 10 percent through a government edict by 2020. The volume of gas needed will be staggering.

This paper describes the current state of natural gas in China and its evolutionary history during the past two decades with an attempt to forecast the future over the next decade. Emphasis is placed on technical problems and challenges in natural gas development, particularly in the exploration and production of shale gas. A basin analysis is done to compare the characteristics of potentially producing basins in China with those in the United States. Technological demands are identified and production capability is forecasted.

It is the author's belief that to maintain China's current economic growth of 10 percent, China needs to greatly expand its natural gas use and produce much of it locally. This can be done only by emulating North America, not just by adapting existing technologies but also by developing economies of scale and cost-cutting efficiencies to fit in China's own situation. This is the only way that China can speed up its domestic natural gas production, especially in shale gas developments.
Gas Breakthrough Detection and Production Monitoring From ICD Screen Completion on Lukoil's Korchagina Field Using Permanently Installed Distributed Temperature Sensors
Authors: Chertenkov M. , Deliya S. V. , Semikin D. A. , Brown G. A. , Bayanova A. , Kanevsky E. , Nukhaev M. , Shapovalov A. , Pormeyster Y.
Published: October 2012

Lukoil-Nizhnevolzhskneft is developing its Korchagina oil field in the Russian sector of the Caspian Sea using inflow control device (ICD) sand screen completions producing from horizontal wells. The ICD completion is used to delay gas and water breakthrough and extend the well's production life. Offshore operations, restricted wellhead access and a relatively low TVD limit conventional production logging possibilities, so Lukoil has chosen to install permanent fiber-optic distributed- temperature monitoring systems with its sand screens and to use these systems to monitor and optimize production.

The optical fiber has been deployed on the outer part of the sand screen shroud in this horizontal, low-drawdown well. Installing the fiber outside the ICD sand screens gives a unique direct measurement of the inflow temperature from individual well zones (the effect of Joule-Thomson warming/cooling of the flowing fluids caused by the pressure drawdown), excluding the effects of thermal mixing of the reservoir fluid flowing inside the wire-wrapped screens. This inflow temperature responds directly to zone drawdown and fluid Joule-Thomson properties, allowing these properties to be monitored over time.

Descriptions are provided of the completion technology used to install the fibers along the ICD sand screens and of the data and results obtained. Thermal models of the near-well environment are also described and are used to analyze the data for early detection of the gas breakthrough and to allow real-time production optimization. The installed optical fiber proved its value for production optimization in this ICD completion in the Korchagina oil field.
Dual-Continuum Modeling of Shale and Tight Gas Reservoirs
Authors: Azom Prince N. , Javadpour Farzam
Published: October 2012

Shale and tight gas reservoirs are characterized by very low permeabilities at the nano-scale which gives rise to non-Darcy effects such as Knudsen diffusion that makes the use of conventional (Darcy) models inadequate. Slip-flow and Knudsen diffusion have been shown to be accounted for in an apparent permeability that is not just pressure dependent but can be strongly non-linear. Available apparent permeability models are either an empirical function of the matrix permeability or capillary tube models based on the ideal gas law. We use the latter in this work but correct for real gas and porous media effects. Incorporating slip-flow and Knudsen diffusion in developing a dual-continuum reservoir simulator capable of modeling natural fracture flows in shale and tight gas reservoirs is tricky because the matrix-fracture interporosity term can no longer be treated as the historic constant for single phase flows but as a complex function of pressure. In this work, we show that we can circumvent this complexity only if we use a modified pseudo-pressure approach and treat the resulting variable diffusivity as an explicit term in the derivation of an adequate matrix-fracture interporosity shape factor. We also develop a 2D implicit compositional single phase dual-continuum reservoir simulator suitable for modeling naturally fractured (or fissure rich hydraulically fractured) shale and tight gas reservoirs. Our results show that natural fractures (and/or fissures) can play a very crucial role in shale and tight gas recovery, which is significantly enhanced by slip-flow and Knudsen diffusion and hence, should not be ignored. Our model can also be used to model flows through the hydraulic fractures for situations where hydraulic fracturing is dense and hence present a computational challenge to model explicitly.
Advancements in Openhole Completion Technology Increase Efficiencies and Production in the Williston Basin
Authors: Paneitz John , Johnson C. Christopher , White Matthew , Gentry George
Published: October 2012

Unconventional reservoirs require innovative completion techniques and technology to become more economical. Formations vary drastically in lithology, lateral lengths, completion methods, and financial drivers. The two most popular stimulation techniques are ‘plug-n-perf’ and multistage openhole packer/sleeve completions.

The Williston Basin consists of two primary oil- and gas-producing formations: Bakken and Three Forks. As frac sleeve designs have improved, the capabilities to offer operators an ever-increasing number of stages in a one-trip system have vastly increased the effective flow area created by staged hydraulic fracturing, thus resulting in better production.

Over the years, hybrid systems have been installed in horizontal wellbores to increase the number of compartmental sections for hydraulic fracturing because of the limitations of ball-actuated frac sleeves. These hybrid systems place ball-actuated frac sleeves along sections of the wellbore starting at the toe. Once the maximum number of frac sleeves has been spaced out using openhole packers for isolation, the additional sections of the wellbore are separated without sleeves using only openhole packers. During the frac, balls are used to shift open frac sleeves and provide isolation from the previously treated sections. Once all the sleeves have been opened and the fracs placed, composite frac plugs are pumped down and set to isolate and treat additional stages using the ‘plug-n-perf’ method. Experimenting with hybrid systems provides operators with the ability to optimize spacing of frac stages along the horizontal section when sleeve technology alone did not allow for the desired number of stages. The costs are higher for operators to perform a hybrid-type completion, and this has driven enhanced sleeve technology to allow for all sleeve completions.

Working relationships between operators and service companies have enabled the advancement of current technology to provide solutions that increase efficiencies and production. This paper outlines information from specific case histories on current well construction/design, historic overviews showing the progression of openhole completions used within the Williston Basin, how spacing is determined between stages based on reservoir characteristics, and how technological advancements and working relationships have enabled a record number of sleeves to be installed in a single wellbore where tighter frac spacing is required.
Modeling and Dynamical Analysis of the Wave Equation of Sucker-Rod Pumping System
Authors: Yang Yu , Watson Jeff , Dubljevic Stevan
Published: October 2012

The use of sucker-rod pumping systems is the most common method of artificial lift in the oil-well industry. In this work, the viscous-damped-wave equation model has been developed to describe the rod-string dynamical behavior at various well depths utilizing the inputs of load and position originating from the surface-card measurement. In contrast to the existing solutions of viscous-damped-wave equation dynamics, which is based on Fourier series truncation and finite difference method, in this paper a novel technique is presented and utilized in the real time estimation framework. In particular, an infinite-differential state space representation of the viscous-damped-wave equation dynamics is developed based on appropriate boundary transformation. The spectral decomposition and truncation of an infinite number of modes is realized, so that the partial differential equation model is cast to the system of coupled ordinary differential equations, which can be solved in real time and utilized for period and non-periodic motion stroke. Finally, the new method is validated by the real case study associated with the existing well.
Mini-DST to Characterize Formation Deliverability in the Bakken
Authors: Kurtoglu B. , Kazemi H. , Boratko E. C. , Tucker J. , Daniels R.
Published: October 2012

Characterization of reservoir deliverability is fundamental for the economic development of any field. In the Bakken, there is a need for reliable pressure transient tests to provide the effective formation permeability of the fracture-matrix in this formation for deliverability calculations. This effective permeability can then be compared to laboratory measured core permeability of the matrix rock samples. This comparison is the basis for planning early production options and subsequent enhanced oil recovery (EOR) decisions. This comparison is particularly important because of the influence of massive hydraulic fracture stimulation on reservoir performance.

Determining well deliverability potential by conventional drill stem tests (DST) or traditional wireline formation tests (WFT) in the past has resulted in mixed success in the Bakken. On the other hand, the mini-DST has definitely increased reliability and the success rate of pressure transient tests. The operation of mini-DST tool requires much less time than the classic DST, and multiple zone tests can be conducted to assess individual zone deliverability. The Mini-DST tool uses the conventional Wireline Formation Tester (WFT) configured with a dual-packer module and downhole pump. Tests are conducted by inflating the dual-packer module to isolate a 3-foot interval of the wellbore. The formation fluid is pumped out from the packer-isolated wellbore interval to conduct pressure drawdown and buildup tests in the interval. An overlay of all the pressure drawdown and buildup results from various intervals is compared on a single plot to identify the most productive interval. Finally, conventional pressure transient analyses are performed to interpret all pressure drawdown and buildup tests. In this paper we present several field tests which were analyzed both by the above procedure as well as by numerical simulation.

The analyses of several mini-DST results have provided insight into a better understanding of the flow mechanism in the Bakken both during primary production and in forecasting various improved and enhanced oil recovery proposals. The experience can also serve as a basis for test design in similar low-permeability reservoirs elsewhere.
Mapping of Hydraulic Fractures under Triaxial Stress Conditions in Laboratory Experiments using Acoustic Emissions
Authors: Damani Akash , Sharma Abhishek , Sondergeld Carl , Rai Chandra
Published: October 2012

Hydraulic fractures are traditionally modeled as planar features developed by the tensile failure of the rock. Laboratory nanoseismic and field mine-back studies show that most of the fractures are non-planar complex features. Fracture properties are strongly affected by the magnitudes and directions of the stresses in the formation. Low stresses are associated with a complex fracture development while high stresses create simpler, straighter and more planar fractures.

We report the results of controlled laboratory triaxial hydraulic fracturing experiments instrumented with piezoelectric sensors. We performed tests on Lyons sandstone which was determined to have an initially isotropic velocity structure. The fracturing experiments have been performed under triaxial stress state to replicate the insitu stress reservoir conditions. The uncertainty in hypocenter locations, frequency analysis, source mechanisms and the effects of stress on fracture propagation will be discussed. Microscopic observations of the fractures are correlated with the mapped microseismic events. Fractures are observed to be non-planar visually and at the SEM scale. Shear failure recorded by focal mechanisms appears to dominate the failure mode. The deviation from planarity will surely affect proppant transport and dispersement.
Multidisciplinary and Integrated Methodology for Deep Water Thinly Bedded Reservoirs Characterization
Authors: Nurhono Achmad A. , Kantaatmadja Budi P. , Masoudi Rahim , Thu Goh Sing , Rahman M Nasir , Othman Mohamad B , Hernandez Nina M. , Rahman M. Ramziemran
Published: October 2012

The sedimentation in deepwater environments commonly includes deposition of thinly-bedded pay zones that are difficult to be characterized using standard seismic and logging techniques. Furthermore, these zones are often left unexploited and even overlooked during drilling, as they are finer in resolution than it can be detectable in conventional open-hole logs.

The paper presents an integrated multi-disciplinary study on thinly-bedded reservoir characterization in deep water areas in Malaysia. The adapted workflow consist of: (1) Seismic Data Conditioning, (2) Petrophysical SHARP Analysis, (3) Simultaneous and Rock Model Building, (4) Lithology Prediction, Hydrocarbon Volume, and Net pay, (5) Stochastic Seismic Inversion and Geo-statistical Modeling, and (6) Reservoir Simulation and Validation, (7) Uncertainty Analysis, (8) Sedimentological Analysis using Core-Image, and (9) Geomechanical Rock Property Analysis.

Petrophysical diagnostics using high quality resistivity images of OBMIs, as log input for thinly-bedded modeling, was the primary driver to establish effective elastic properties through AI vs. VP/VS cross plot (for lithology prediction) and AI vs. total porosity cross plot (for porosity prediction) within the model. These cross-plot transforms are then upscaled and applied to build a cascading of deterministic inversion (simultaneous AVO inversion) and stochastic inversion of 1-ms sampling, which are calibrated to core and neural network litho-facies interpretation for lithology and porosity modeling.

The geo-statistical modeling workflow was initially built-in with 7 exploration wells that have OBMIs (Oil Base Micro Imager) as the typical model. Numbers of reservoir properties realizations were generated by generating geo-cellular grid over the zone of interest. These realizations could provide an improved lithology, porosity and fluid determinations and could lead to estimate a more robust volumetric, particularly within such thinly-bedded reservoir. The developed unique integrated workflow was applied on the field under study showing about 30% increase in in-place volume and was successfully validated against available production/well data as well as new drilled wells.
Technology Enhanced Online Learning for Drilling Equipment Improves Knowledge Transfer
Authors: Keable Kevin BP , Redlinger Thomas
Published: October 2012

As companies grow and spread their activities globally, so the adequate training of the resultant expanding workforce becomes an issue of major importance to ensure quality of performance is maintained. Our current global workforce is working under significant pressure to deliver tools, equipment and services to a high standard which has significantly increased the challenge of ensuring that all personnel are trained to the same standards and have access to the best information. Online learning programs or computer based training (CBTs) although providing consistency lack the utilization of video, animation, technical graphics and voice-over, which are essential to ensure good knowledge transfer and retention. So, with the current online training being considered insufficient a new approach needed to be initiated.

As a result a new series of innovative hybrid CBT courses has been developed which is focused on commodity drilling tools, pressure control equipment and safety, using interactive methods dramatically to improve the learning experience and knowledge transfer. The resultant courses were placed on the in-house learning management system and made available across the globe in multiple languages. A total of 12 modules have been created in the initial year of CBT course development, following which some 13,000 training modules have been taken representing an impressive employee acceptance of the process

In this paper the authors will review the development of this program and the process used to create its content and track performance. The objective of this paper is to transfer knowledge on the processes needed for the development of successful online training and to demonstrate its level of effectiveness.
Increased oil production at Troll by autonomous inflow control with RCP valves
Authors: Halvorsen Martin , Elseth Geir , Nævdal Olav Magne
Published: October 2012

Troll is a large subsea development offshore Norway. Oil is produced to Troll B and Troll C platforms from 120 long horizontal subsea wells completed in a thin oil column. Oil production is optimized within the gas handling capacity at the platforms and the challenge is to drill and complete the wells in a way that gas does not have an easy access into the well. Troll has focused on developing and implementing inflow control devices that limits gas coning. An autonomous inflow control device, the RCP valve, has been developed by Statoil and implemented at the Troll field. The purpose of the RCP valve is to restrict gas compared to oil. The valve adjusts the choking of the fluids depending on which phase (oil or gas) being produced. Currently three wells have been completed with RCP valves. Reservoir simulations as well as production experience show a significant increase in oil production. It is observed that a well completed with RCP valves has a significantly lower gas oil ratio development compared to other Troll wells.
Oil-Water Delineation with a New Formation Tester Module
Authors: Al-Otaibi S. H. , Bradford C. M. , Zeybek M. , Corre P.-Y. , Slapal M. , Ayan C. , Kristensen M.
Published: October 2012

Delineation of oil and water in heterogeneous carbonate formations can be challenging, especially in the presence of low resistivity formations and low mobility zones. Advanced wireline formation testers (WFTs) have traditionally been used in openhole logging for pressure profiles, coupled with downhole fluid analysis (DFA) and sampling for an integrated approach. It is often difficult to obtain well defined oil and water gradients with pressure measurements in tight formations, especially with probe-type tools. Straddle-packer modules are often used to enable flow from low mobility formations. However, the straddle-packer module has operational and differential pressure limitations, as well as a relatively large storage volume in the isolated interval.

A field example of oil-water delineation is presented for a low resistivity, heterogeneous carbonate formation. Low formation fluid mobilities required the utilization of a new wireline tester module over the standard probe type tool. A newly designed fluid inlet module with multiple openings was utilized across the low mobility zones for the first time in the industry. This new module avoids issues associated with the interval volume of a dual-element straddle-packer-type tool and provides significantly faster clean up from the formation. In addition, minimized storage results in better Interval Pressure Transient Test data. Faster set/retract operation of this tool and a much higher pressure differential limit are additional advantages over existing dual packer tools. Several station measurements with mobilities of less than 0.1 md/cp were conducted. This allowed oil to be identified across a low resistivity zone, leading to an increased oil column height in the field.

Results showed that more accurate oil-water delineation was provided using the new module along with high resolution optical fluid analyzers, identifying mobile oil from low resistivity carbonate zones. In addition, more accurate permeabilities for the tested zones were obtained through pressure transient data analysis.
Improving Production in the Marcellus Shale Using an Engineered Completion Design: A Case Study
Authors: Walker K. , Wutherich K. , Terry J. , Shreves J. , Caplan J.
Published: October 2012

To complete the Marcellus shale's horizontal wells simply and cost-effectively, operators typically use geometric perforation designs in order to prepare for hydraulic fracturing. With this technique, perforation clusters are placed at equidistant points along the lateral. However, microseismic monitoring shows that this type of stage selection often distributes hydraulic fracturing treatments unevenly. The fracture treatments propagate to the lowest-stress intervals, leaving a large number of perforations under stimulated or simply unstimulated. In an attempt to improve on this technique, a study was performed in which wells using an engineered perforation design were compared against offset wells that had a geometric perforation design.

For the wells employing an engineered design, an acoustic scanning tool was deployed on wireline and mechanical rock properties were obtained along the length of the productive lateral. The critical well information, including in situ stress, lithology, Young's modulus, and Poissons Ratio enabled engineers to create custom staging and perforating designs. These designs were optimized to provide more consistent stimulation along the entire lateral, and lower breakdown and treating pressures. The final result of using the engineered perforation design was a significant increase in production when compared to conventionally completed wells.

During the stimulation treatment of the engineered perforation design, there was a significant drop in the average treating pressures during fracturing when compared to geometric offsets. This was due to several factors including the fact that perforations targeted lower stress intervals. In addition to lower pressures, an elimination of premature job terminations or "screen-outs" was seen. This occurs when pressures increase to such a degree that the stimulation treatment cannot continue within acceptable pressure ranges. Previous treatments in offset wells yielded a 35% screen out rate which resulted in significant lost time and additional costs.

The process and production results of wells completed with geometric perforations to wells with engineered perforations.
Subsurface To Surface Microseismic Monitoring for Hydraulic Fracturing
Authors: Peyret Olivier , Drew Julian , Mack Mark , Brook Keith , Maxwell Shawn , Cipolla Craig
Published: October 2012

The options for acquiring microseismic data to evaluate hydraulic fracture treatments have expanded in recent years to include surface and near-surface monitoring. However, there has been an absence of detailed and comprehensive validation and comparison of the various monitoring techniques, leading to misconceptions and uncertainties concerning the different alternatives. Traditional downhole monitoring is constrained by the requirement for adequately located deep monitor wells, which limits application in exploration and appraisal and other areas without suitable monitor wells. Surface monitoring provides a means to gathering important microseismic data without the need for observation wells, although the validity of the results is sometimes questioned.

This paper presents detailed "side-by-side" comparisons of surface and near-surface monitoring techniques and provides guidelines for the application of the various monitoring options. This multi-year journey was undertaken by comparing several surface/near-surface data sets with their downhole counterparts in a series of concurrent surveys in US shale plays. These comparisons answer the following questions concerning sensitivity, attenuation, and location uncertainty of surface monitoring options:

How do the microseismic events detected and located at the surface or near-surface compare with those detected and located downhole? What is the best surface or near-surface design and what parameters are key to optimizing it? How does the processing and analysis of surface data compare with that of downhole data?

The paper includes a rare dataset from a field laboratory in the Fayetteville shale that was instrumented with a 4000 geophone surface microseismic array, a 5 Shallow Hole Grid, and traditional downhole microseismic arrays located in both vertical and horizontal observation wells. In addition, a 71-level geophone array was deployed from TD to surface in a vertical observation well. This multifaceted monitoring provided an unparalleled dataset to compare the various microseismic monitoring options.

The paper documents how and when the surface or near-surface technique provides a meaningful alternative to downhole monitoring both technically and economically, presents candidate selection criteria and provides a comprehensive comparison of the relative technical and economic merits of each monitoring option.
Improving the Accuracy of Directional Wellbore Surveying in the Norwegian Sea
Authors: Edvardsen I. , Hansen T. L. , Gjertsen M. , Wilson H.
Published: October 2012

Time-dependent current fluctuations in the Earth's ionosphere cause inaccuracies in wellbore directional surveying. These inaccuracies increase at higher latitudes and although monitoring and correction is possible, it becomes less valid as the distance between the monitoring site and the rigsite increases, a particular problem for offshore drill sites. The characteristics of the ionosphere currents indicate that the most favourable location for monitoring stations is on the same geomagnetic latitude as the drill site. Such an arrangement has been used to monitor and correct directional survey at the Haltenbanken area of the Norwegian Sea over a period of approximately two years. Haltenbanken is located about 200km west of the Norwegian coast at latitude 65° north, where magnetic storm activity can have a significant effect on directional surveying. A monitoring station was set up on the coast at the same geomagnetic latitude as Haltenbanken. To test the idea that magnetic disturbances are similar along constant magnetic latitude, an additional monitoring station was established 200km east of the main station. The data broadly confirmed the hypothesis, although isolated events were observed when this is not the case. The challenges of surveying at offshore sites north of 62° N latitude are probably greater than the oil and gas industry is accustomed to; challenges that will become more significant if the Arctic Ocean is opened to drilling operations. The technique described in this paper may contribute to safer and more productive offshore operations at high latitudes.
Investigation of Thermal Well Test Analysis for Horizontal Wells in SAGD Process
Authors: Ghahfarokhi Ashkan Jahanbani , Jelmert Tom Aage , Kleppe Jon
Published: October 2012

Steam assisted gravity drainage (SAGD) is the most promising technique in heavy oil recovery. Determination of the steam chamber volume is very important for monitoring the progress of this process. Thermal well testing offers an early method to estimate the steam chamber mobility and volume using pressure falloff tests. However, well test analysis of horizontal wells is more complex than that of vertical wells.

Pseudo steady state method is used to estimate the chamber volume from falloff testing assuming a composite reservoir. Due to the large contrast in the fluid mobility of the swept and un-swept zone, the flood front behaves as an impermeable boundary. Therefore, the steam chamber acts as a closed reservoir and the pressure response is characterized by pseudo steady state behavior.

The purpose of this work is to evaluate the feasibility and accuracy of thermal well test analysis for horizontal wells in SAGD process. Pressure falloff test is simulated using a numerical thermal simulator. The generated pressure falloff data are then analyzed to calculate swept volume and reservoir parameters. Effects of several parameters like permeability anisotropy, steam quality, injection rate and time on well test results are also studied.

Results of this study show that steam chamber volume and mobility and skin factor can be reasonably estimated from pressure falloff tests, and are in good agreement with simulated results. Longer injection times prior to shut-in, prove to have an adverse effect on the estimated swept volume because of a more irregular shape of swept region and the possibility of early breakthrough. Irregular swept region shape, however, does not significantly affect the early time well test data. Calculated swept volume is highly sensitive to the ratio of vertical to horizontal reservoir permeability. Finally, higher steam quality results in more accurate estimations.
Case Histories Exploring the Economic Value of Solid Expandable Systems over the Life of the Well
Authors: Farley Douglas
Published: October 2012

From the early beginnings, the idea of expanding solid tubulars as a means to reduce nonproductive drilling time by covering unstable formations and pressure events while minimizing the telescoping effect of standard casing programs was thought to be the panacea over conventional well-construction techniques. However, the development and commercialization of this technology has been driven by increased production opportunities realized by improved well architecture and completion size optimization. Solid expandable systems are now commonly used in development, planning, drilling, and completion, and during production decline.
Global Chemical Evaluation Process Review to Qualify Regulatory and Environmental Characteristics for Oilfield Chemical Products
Authors: Daulton Dan , Post Matt , McMahon JoAnn , Kuc Bill , Ake Charles , Hill Denise
Published: October 2012

Environmental qualification of chemical products is a critical component of the oil and gas industry. However, regulatory and chemicals evaluation criteria, if available, are typically designed for local ecosystems and vary within specific regions and regulatory entities. Although some qualification schemes have been adopted across multiple geomarkets, there is a lack of uniform, globally coordinated, strategic objectives to address this issue for the industry. This has created disjointed, ineffective responses by vendors, chemical manufacturers, and suppliers involved in creating and delivering complex chemical solutions to meet oil and gas industry challenges.

Recent movements of international organizations sponsored by the United Nations (2009) have addressed communication of chemical hazards via the Global Harmonized System of Classification and Labeling (GHS/CLP). Adoption of GHS by numerous regulatory bodies has brought international consensus to hazard criteria and definitions. Implementation of GHS is proving to be long, slow, and arduous. Furthermore, the intended scope of GHS focuses on standardization of hazard communication. As such, the core elements of GHS are applicable to evaluating chemical hazards. However, several hazard endpoints are either inappropriate or need modification to address the unique needs of the oilfield chemical market. Therefore, it is incumbent upon global chemical suppliers to identify an effective chemical evaluation process. This process must facilitate the offering of product solutions which meet the performance demands of petroleum exploration and production, while protecting human health and the environment and complying with existing and future regulatory statutes, as well as specific local concerns. This paper describes our continued efforts to globalize the chemical evaluation for all oilfield products. Comparative scoring of chemicals is accomplished through a practical, transparent, and quantitative process, based upon their potential safety, health, and environmental impact. Since initially introduced, the evaluation process has been updated to include review of key global regulatory requirements (chemical prescreening, transportation, handling, and application). Benefits include:

Reducing redundant development efforts, Improving research and development focus using specific guidelines for regulatory and chemical hazard assessments, Enhancing marketing value by providing a comprehensive view of inherent benefits or potential concerns associated with chemical products; Clarifying expectations in the supply chain and Effectively managing issues of confidential business information (CBI) when multiple parties are involved in research and development chemistry.
A Novel Method to Optimize Horizontal Bakken Completions in a Factory Mode Development Program
Authors: Shelley Robert , Guliyev Nijat , Nejad Amir
Published: October 2012

This paper will describe a new method to facilitate optimization of hydraulically fractured horizontal Bakken completions. A key component of this method is a predictive data-driven model developed from a detailed evaluation of over 50 horizontal Bakken completions. Using this model, production predictions and economic optimization can be quickly performed using only data obtained during lateral drilling operations. This type of modeling and optimization of new horizontal completions fits well with a factory mode (rapid pace of well completion and hydraulic fracturing) of resource development.

The need to create large amounts of fracture area and the associated costs create an opportunity for economy of scale. Unfortunately, the time and expense required performing logging runs to gather data, and estimate reservoir and rock properties to facilitate completion design and optimization reduces operational efficiency and increases well cost. A data-driven approach to optimizing hydraulically fractured horizontal completions does not reduce operational efficiencies since it can be developed from common data and information obtained during drilling operations.

The data-driven model shows that reservoir quality, as one would expect, has the dominate effect on Bakken production. In addition hydraulic fracture design/methodology, fracture spacing, proppant selection, frac staging methods, frac compartment isolation, drillout/cleanup procedures, wellbore length and orientation have a significant effect on well production and economics. Several case histories will be included in which data-driven modeling was used to evaluate various completion/frac scenarios, predict production and facilitate completion/frac optimization.

The challenge of optimizing horizontal Bakken completion and frac design (30 or more hydraulic fracturing treatments per well) in a fast paced factory mode of resource development is problematic. The methodology described in this paper has been helpful to identify production drivers and facilitate well planning while also supporting a factory mode of resource development.
A New Family of Anionic Surfactants for EOR Applications
Authors: Gao Bo , Sharma Mukul M.
Published: October 2012

A new family of anionic surfactants that has great potential for EOR applications was synthesized and characterized in our lab. The unique and versatile structure of these surfactants has endowed them with properties that are attractive for enhanced oil recovery. A detailed experimental study was carried out and is presented here on the oil-water and solid-water interfacial properties of seven novel molecules.

The interfacial properties of this series of seven anionic surfactants with different length of hydrophobic tail and linking spacer group show systematic trends in interfacial tension and static adsorption density with changes in solution conditions. These molecules showed excellent aqueous stability even in high salinity and hard brines. Ultra-low IFT values were measured at low surfactant concentrations. The synthesized Gemini surfactants also showed lower maximum adsorption densities than the conventional single chain surfactants. The results from this study showed the potential of utilizing these surfactants at low concentrations and in harsh reservoir conditions.
Alternative Interpretations of Shale Gas/Oil Rate Behavior Using a Triple Porosity Model
Authors: Tivayanonda Vartit , Apiwathanasorn Sippakorn , Ehlig-Economides Christine , Wattenbarger Robert A.
Published: October 2012

In this work, the fully transient triple porosity model proposed by Al-Ahmadi and Wattenbarger (2011) is selected to model the existence of natural fractures in shale reservoirs. This triple porosity describes three linear flow systems: from the matrix into natural fractures, from natural fractures into hydraulic fractures, and from hydraulic fractures into the wellbore. To completely identify this mathematical model, properties and dimensions of three mediums (matrix, natural fractures, and hydraulic fractures) must be known. This may be too complicated to be a practical interpretation tool.

To use the triple porosity model in a practical way, the original model is simplified. Assuming an infinite conductivity of hydraulic fractures, the triple porosity model is reduced to a dual porosity model. This Simplified Model considers only the natural fracture and matrix systems and treats the hydraulic fractures as a constant pressure boundary. The analysis equations and guidelines for this Simplified Model are presented for interpreting production data.

Interpretation guidelines are proposed corresponding to five production scenarios which are combinations of bilinear flow, linear flow, and boundary dominated flow (BDF) periods. With the interpretation guidelines, various analysis equations for different flow periods or different physical conditions are used to interpret production data. Field examples are presented with the calculation procedures of interpretation guidelines. The possible errors in general interpretation are also presented. Furthermore, this work also compares the results from the Simplified Model with those from a model with no natural fracture.
Produced Water Treating Systems -Comparison between North Sea and Deepwater Gulf of Mexico
Authors: Walsh J. M. , Georgie W. J.
Published: October 2012

It has often been noted that water treating systems in the North Sea differ from those in the deepwater Gulf of Mexico (GoM). The objective of this paper is to provide an understanding of the reasons for these differences.

In terms of platform technologies, and extraction strategies, there are fundamental differences between the two regions. FPSOs (Floating Production Storage Offloading) and fixed leg platforms are commonly used in the North Sea, whereas in the deepwater Gulf of Mexico there are currently no FPSOs, and only one fixed leg platform (Bullwinkle). Floating Spars and Tension Leg Platforms are typically used in the deepwater Gulf of Mexico. Thus, there is much greater deck space and weight availability for North Sea platforms than in the deepwater Gulf of Mexico. In addition, almost all North Sea fields are developed using pressure maintenance which relies on water and/or gas injection. Hence the water production in many of these fields has reached high water cut. In the Gulf of Mexico, there is only a handful of fields with water injection and most production is relatively dry.

The approach in this paper is to compare the systems to Best Practices in water treating system design and to consider the reasons for deviation from the Best Practices. Factors which account for this deviation include capital and operating costs, extraction techniques, reservoir characteristics, the properties of the fluids being treated, the target specifications, and the obvious differences in platform type (fixed structure in shallow water versus floating structure in deep water). In addition, modeling tools are used to answer "what if’ questions. This provides a detailed understanding of the relative importance of various factors which differentiate the systems in the two regions (such as inlet fluid shear and temperature, separator flux rate, residence time, application of hydrocyclones, etc).

While the overall conclusions of the analyses can be readily anticipated (i.e. deepwater systems are designed to minimize weight and space), the detailed understanding provided here gives insight into the design of water treating systems in general. It emphasizes the importance of carrying out effective water treating early in the process (i.e. in primary separation as done in the North Sea), and the necessity of using large end-of-pipe equipment when this is not possible (as in the deepwater, due to high cost of weight and space).