bluuebunny/crossref_metadata_2025 huggingface dataset:
Why Monitoring With a Single Downhole Microseismic Array May Not Be Enough: A Case For Multiwell Monitoring of Cyclic Steam in Diatomite
Authors: Murer Anthony S. , McNeish Greg R. , Urbancic Ted , Prince Marc , Baig Adam M. , Bleakly Doug
Published: February 2011

Nine wells were drilled to test cyclic steam stimulation as a recovery mechanism in the diatomite reservoir in the Belridge field. Microseismic monitoring was proposed to evaluate steam chest and fracture growth. A series of models were constructed to determine both microseismic event detectability and locatability. The modeling indicated that poor signal-to-noise ratios would constrain the ability to locate events using a single array. As a result, three monitoring wells were installed. The purpose of this paper is to evaluate the microseismic event location results obtained from the 3-well solution and compare them with the solutions obtained when turning off one or two of the arrays. This first phase of investigation was performed on the sand-propped hydraulic fracture stimulation prior to the cyclic steam operations. This study may be applied to other areas including imaging hydraulic fracture stimulations in shale plays, reservoir steam monitoring, or in any area where location precision in microseismic monitoring is necessary.

It has been demonstrated in the field that the monitoring range of a microseismic system can be increased and the potential for locating microseismic events improved by installing multiple arrays having overlapping radii of observation. Innovative system design, deployment techniques and operational procedures, plus advanced multi-well processing strategies have all contributed to creating a growing data set with over 4,000 events recorded during the first 13 months of operation. Results of turning off arrays showed increased location error with two well solutions and a significant increase in error with one-well solutions notwithstanding the reduction in event location count due to lack of multi-phase signals on a single array. Azimuth errors in single microseismic observation well solutions result in disperse interpreted fracture geometry and in misinterpretation.

Overall, our observations show that, for both multi- and single-phase events, the observed detection limits and size distribution of the seisms has far exceeded those originally predicted by the earlier modeling.
Multidimensional Reservoir Description and Data Integration Using Time- Space Wavelet Analysis
Authors: Awotunde Abeeb A. , Horne Roland N.
Published: February 2011

Developing computationally efficient nonlinear regression algorithms is central to reservoir parameter estimation. The problem of inverse analysis is further complicated when the constraining data exist at different scales of resolution. In this case, integrating the data to reduce the scale effect becomes necessary. A commonly adopted approach is to use different scaling factors to bring the different datasets to the same resolution. However, there is no unique way to select scaling factors and this introduces some bias into the inverse modeling giving more importance to some datasets.

In this paper, we propose the integration of multiwell production data using the wavelet transform. The method involves the use of the two-dimensional wavelet transformation of the data space to reduce the linear adjoint system for a multiphase flow sensitivity computation. The approach proved very effective at reducing the cost of computing sensitivity coefficients. Multiple datasets from different wells, representing different production responses (pressure, water cut, etc.), were treated as a single matrix of data rather than separate vectors that assume no correlation amongst datasets. This enabled us to transform the multiwell production data into a two-dimensional wavelet domain and subsequently select the most important wavelets for history match. By minimizing the square of the Frobenius norm of the residual matrix we were able to match the calculated response to the observed response. We derived the relationship that allows us to replace a conventional minimization of the square of the l2 norms of multiobjective functions with the minimization of the square of the Frobenius norm of the integrated data. The usefulness of the approach is demonstrated using several examples.
Hydraulic Fracture Monitoring to Reservoir Simulation: Maximizing Value
Authors: Cipolla C. L. , Williams M. J. , Weng X. , Mack M. , Maxwell S.
Published: February 2011

Hydraulic fracture monitoring with microseismic mapping is now routinely used to measure hydraulic fracture geometry, location, and complexity, providing an abundance of information that can be essential to optimizing stimulation treatments and well completions. Although microseismic mapping has added significant value in many different environments, we have yet to fully utilize microseismic data. Significant details can be extracted from microseismic measurements that, when integrated with other information, can improve the characterization of both the reservoir and the hydraulic fracture. In addition, microseismic data has yet to be quantitatively and routinely utilized in reservoir simulation, which is the key to optimization.

Geological and geophysical data and wellbore logs can be combined with newly-developed complex fracture propagation models and reservoir simulation models. These models are calibrated using microseismic measurements and production data— closing the loop from microseismic mapping to simulation. The combination of microseismic measurements and complex fracture modeling with sophisticated geological descriptions of pre-existing natural fractures can be used to evaluate existing and predict future well performance in complex shale-gas reservoirs. The application of calibrated complex hydraulic fracture and reservoir simulation models provides more reliable forecasts of well performance resulting from various hydraulic fracture designs and completion scenarios, allowing the selection of the most economic strategy.

The optimization process includes a detailed workflow to efficiently integrate the large amount of information and modeling results into a coherent work product. This includes the integration of advanced processing and geomechanical interpretations of microseismic data with newly developed complex hydraulic fracture models that significantly improve the application of microseismic measurements. An example illustrates how HFM can be taken from event locations to production forecasts, showing how the capability to integrate geophysics, geomechanics, hydraulic fracture mechanics, and reservoir simulation can result in significant economic benefits.
Leveraging Knowledge Retention and Sharing Across the Value Chain
Authors: Senivongse Chulatep , McClelland Corey
Published: February 2011

Knowledge walks in and out of your offices in the form of your employees experiences, built up career comprehension and organizational adroitness as your employees come to work and then leave to go home everyday. Then at some point they leave and don't come back, they retire, take a job with another company, rotate to a new position or end their consulting agreement and are reassigned to another company. Capturing that tacit knowledge before it walks out the door the last time can bring enormous benefits to your company. Through the corporate quest for knowledge during their career or tenure with the company the company has invested in these staff to acquire the right knowledge. What happens to all their knowledge? The oil and gas industry has a major portion of its work force retiring over the next five years. The process being executed at PTTEP is attacking the capture and reuse of knowledge from those staff who are retiring, rotating or being reassigned head on. They are leveraging the departing person's knowledge to the benefit of the company and those who need to know. That shared knowledge is being reused by those still working on solutions to critical hydrocarbon problems. Knowledge retention and sharing is a process utilizing knowledge management techniques focused on the reuse of the departing staff tacit knowledge across an organization or company. The process as utilized can save oil and gas companies from reinventing by using the knowledge that already exists. The focus of this paper will be how knowledge is being captured and retained from a transitioning workforce at PTTEP and how leveraging this knowledge is creating value for the individuals who are reusing the retained knowledge to the benefit of the company.
Optimal Water Flood Management Under Geological Uncertainty Using Accelerated Production Strategy
Authors: Taware Satyajit , Sharma Mohan , Alhuthali Ahmed H. , Datta-Gupta Akhil
Published: February 2011

Waterflood optimization via rate control is receiving increased attention because of rapid developments in the smart well completions and i-field technology. The use of inflow control valves (ICV) allows us to optimize the production/injection rates of various segments along the wellbore, thereby maximizing sweep efficiency and delaying water breakthrough. We propose a practical and efficient approach for computing optimal injection and production rates given multiple geologic models with application to smart wells. Specifically, we examine the trade-off between maximizing oil recovery vs. maximizing NPV using a penalized misfit function for optimization. The waterflood sweep efficiency is maximized by equalizing the arrival times of the waterfront at the producing wells and the production acceleration is accomplished using a ‘norm’ constraint on the arrival times to accelerate injection/production rates. The ‘optimal’ strategy is decided based on a compromise between the two. Our previous work primarily focused on sweep efficiency optimization and did not account for production acceleration. There are four important elements in our current approach that makes it particularly well-suited for large-scale field applications. First, we use streamlines to efficiently and analytically compute the sensitivity of the arrival times with respect to well rates. For finite-difference models, the streamlines are easily derived from the velocity field. Second, we account for geological uncertainty via a stochastic optimization framework that relies on a combination of the expect value and variance of a performance measure from multiple realizations for risk assessments. Third, analytical forms for gradients and Hessian of the objective functions are derived which make our optimization computationally efficient for large field cases. Finally, optimization is performed under operational and facility constraints using a sequential quadratic programming approach. Multiple examples are presented to support the robustness and efficiency of the proposed optimization scheme. These include 2D synthetic examples for validation and a 3D benchmark field application.
Quality-Assured Evaluation of Freshwater-Bearing Hydrocarbon Reservoirs
Authors: Worthington Paul F.
Published: February 2011

The petrophysical evaluation of freshwater-bearing reservoirs cannot be approached using the standard Archie equations because these reservoirs show departures from the assumptions that underpin the application of those basic equations. The problem is placed on a sounder technical footing by defining the preconditions for the application of non-Archie saturation models and showing where and how these are satisfied. This exercise assumes that porosity has been pre-evaluated. It reveals that there is no fixed salinity level below which reservoirs show freshwater character in an electrical sense: the level is reservoir-specific. Where the non-Archie models do break down, a conditioned pseudo-Archie approach is proposed. This approach demonstrably enhances the estimation of hydrocarbon saturation, typically by up to 20 saturation units, as evidenced through groundtruthing core measurements and comparisons with other log deliverables. These comparisons can, of course, impart additional quality assurance. The approach is illustrated using field examples. On this basis, a protocol is outlined for the optimum acquisition of petrophysical data in freshwater hydrocarbon reservoirs. Central to this protocol are charts for identifying the most appropriate values of the porosity and saturation exponents. The adoption of this protocol leads to a significant reduction of uncertainty in the volumetric evaluation of these challenging hydrocarbon accumulations.
Integrated Workflow for Modeling Basin-Scale Petroleum Systems: Applications to the Kupe Area, Taranaki, New Zealand
Authors: Roncaglia L. , Arnot M. , Baur J. , Fohrmann M. , King P. , Kroeger K. F. , Ilg B. , Strogen D. , Zhu H. , Milner M.
Published: February 2011

This paper describes a multidisciplinary integrated workflow for mapping Late Cretaceous to Recent subsurface structure and stratigraphy, and modeling petroleum systems of the Taranaki Basin (74,209 km2), New Zealand. The basin-scale assessment of geology and fluid flow is aimed to improve previous, mostly local, studies. The size of the study area and integration over a nine-year timeframe of large datasets, multiple software and disciplines present technical challenges.

The workflow consists of the following six main tasks: data compilation, quality assessment and integration; structural and stratigraphic interpretation of seismic reflection data over a regional framework and local grids including assessment of timing and volumetrics of erosion; validation of the geometric and geological integrity of the structural framework through structural restoration; seismic attribute analysis and facies mapping to constrain the sedimentary facies distribution and the paleogeographic evolution of the basin; construction of 3D static models of stratigraphy, lithology distribution and faulting, as determined from the seismic and well interpretations; development of 4D dynamic models of basin deformation and petroleum generation and migration through time, to improve prediction of where as-yet undiscovered petroleum accumulations may be preserved.

Representative examples of data applications and results are presented for the hydrocarbon-producing Kupe area (4,155 km2). In Kupe, more than 200 fault planes and 20 laterally-continuous stratigraphic horizons are mapped, constrained by well data, and included in structurally-validated 3D framework models, which are populated with seismic attribute properties. The 4D models are created by integrating the results of all the steps of the workflow with source rock geochemical properties, heat-flow data from crustal-scale modeling, and rock properties for reservoir fairways.

This integrated workflow and associated data management and interpretation protocols have proved effective for developing a holistic 4D depiction of Taranaki Basin tectono-stratigraphy and petroleum systems. It provides a co-ordinated approach to interrogating large amounts of independent data, and the derivative models are the base for detailed petroleum exploration. Lessons learned may serve as guidelines for projects of similar scale.
A Model of the Impacts of Operational Risk and Analysis of Hedging Strategy with Derivatives for Oil Producing Companies
Authors: Carvalho M. H. , Lima G. A. , Ravagnani A. T. , Schiozer D. J.
Published: February 2011

Economist and finance professionals are always concerned with risk in variables like NPV, IRR, payback, ROA, ROE and other indicators used by analysts and management team. But, in the day-by-day, discussions about risk in operational availability, loss of production, concern of failure of equipment on production, environmental impacts, damage due to hurricane and storms, among others. Currently, operational risk is not so discussed in the oil industry as financial risk, but it may cost billion to insurers and oil companies in events like Katrina, Ike and others.

In this paper, the operational risk of an oil project, its impacts and ways of protection to reduce exposure are studied. The approach is composed of the following:

Macro-modeling of the reliability and operational risk of the oil production system (platform, pipes etc.); Simulation of reliability, availability, downing events etc. over a period of interest (usually, 20 years); Estimation of loss of production and its associated cost with failure of equipments; Use of financial derivatives to hedge loss due to operational risk.

This model is applied to an oil production project similar to those ones of the Brazilian offshore basins. We find that derivatives could be a direct way to hedge oil companies against loss, using financial instrument already traded in the market at a very competitive price, when compared to a traditional insurance policy.
Integrating Reservoir Characterization: 3D Dynamic, Petrophysical and Geological Description of Reservoir Facies
Authors: Knackstedt Mark , Jaime Patricio , Butcher Alan R , Botha Pieter WSK , Middleton Jill , Sok Rob
Published: February 2011

Integrating conventional geologic, petrophysical and reservoir engineering rock typing methods requires studies which incorporate 3D imaging of rock material, 2D petrographic studies, fluid:fluid and fluid:solid interactions (e.g., wettability), and geological facies descriptions. This paper illustrates a new integrated methodology for the multidisciplinary study of reservoir core material. Petrophysical units define zones of a reservoir with similar flow and storage capacity. Geological facies are based on depositional and diagenetic criteria, which are tied to poro-perm data. Empirical relationships are often used to tie the petrophysical to the geological models, to estimate initial hydrocarbons in place. Reservoir engineers also wish to define rock types based on their recovery characteristics (e.g., relative permeability). In this case fluid properties (e.g., fluid components and wettability) can be a major factor controlling the flow and distribution of fluids in porous rocks, which in turn greatly impacts ultimate recovery of hydrocarbons. QEMSCAN®, automated Scanning Electron Microscopy with fully integrated x-ray microanalysis and image analysis, enables one to obtain spatial and numeric 2D mineralogical information from geologic samples. This analysis allows high quality 2D mapping of key parameters used in characterizing rocks: mineralogy, modal mineral proportions, mineral relationships and associations. Micro-CT (μ-CT) imaging enables one to enumerate the porosity, pore geometrical and topological complexities in reservoir rock and visualize fluids within the pore structure of core material in 3D; this enhances the estimation of both fluid flow and recovery properties of core. Results show how the integration of these techniques allows one to more accurately map the mineralogy and wettability characteristics of reservoir rocks in three dimensions, and therefore better couple relevant information from petrologists, petrophysicists and reservoir engineers. A number of case studies illustrate the application of this integrated approach to enhance prediction of petrophysical and multiphase flow characteristics in complex core.
Predicting Effective Permeability to Oil in Sandstone and Carbonate Reservoirs from Well Logging Data
Authors: Anand V. , Freedman R. , Crary S. , Minh Chanh Cao , Terry R. L.
Published: February 2011

This paper discusses a new method for predicting continuous logs of effective permeability to oil in sandstone and carbonate formations from well logging data. This important problem in formation evaluation has remained previously unsolved because the conventional approach used to predict reservoir properties from well log data relies on simple empirical equations and idealized models of reservoir rocks. The use of such equations and models to predict a complex reservoir property such as effective permeability can result in an inaccurate representation of the formation.

This paper shows that accurate values of effective permeability to oil can be predicted using model-independent mapping functions, constructed from Gaussian radial basis functions, which can be derived from a laboratory database of measurements on partially saturated core samples. The mapping functions replace the empirical equations used in the conventional approach and are model-independent representations of the database measurements. Once the mapping functions are constructed from the database there are no adjustable parameters.

In this study, mapping functions for sandstones and carbonates were derived from a worldwide database of laboratory measurements made on 79 sandstone and 25 carbonate core samples. The laboratory measurements available on each sample included irreducible water saturation, effective permeability to oil, porosity, and NMR T2-distributions. The mapping functions can be used to predict effective permeability to oil of reservoirs at irreducible water saturation from input measurements of porosity,T2-distribution, irreducible water saturation, and knowledge of rock lithology, e.g., sandstone or carbonate.

The methodology for deriving the mapping functions is explained in detail. The mapping functions are applied to the database itself to show the accuracy of the effective permeability predictions on core samples. The method is also applied to log data from both sandstone and carbonate formations in three wells from different parts of the world. The predicted effective permeabilities to oil are shown to be consistent with oil mobilities measured in the formations by fluid sampling tools.
Controlling Coal-Fines Production in Massively Cavitated Openhole Coalbed-Methane Wells
Authors: Magill Douglas , Ramurthy Muthukumarappan , Jordan R. , Nguyen Philip
Published: February 2011

In the San Juan basin Fairway, cavitated Fruitland coalbed-methane (CBM) wells have been successfully producing for the past 30 years. However, over the years, coal-fines migration into these cavitated wellbores has resulted in pump issues and coal-fines production, leading to a significant decline in production. To clean out the coal fines and replace the pumps on a continuous basis is a costly workover issue. Hence, a foamed remedial treatment was designed to displace the conductivity-plugging coal fines away from the wellbore and immobilize them with the foam also serving as a diverting agent. This has allowed the production and dewatering process to continue without any interruption. The remedial treatment was chosen because the aqueous tackifier in it can control the fines and help prevent them from plugging the flow path. Also, it dissolves any calcium-carbonate scale in the wellbore and near-wellbore region.

In this study, 15 cavitated wells with coal-fine issues were selected for the foamed remedial treatment. In all of these 15 wells, the coal-fines issues were resolved. This allowed production to be uninterrupted and reduced the cost of workover rigs and pumps. As a secondary benefit, production stabilized in 10 wells and increased in 5 of these wells. This study shows the production results from these two groups of wells that were treated. It also discusses the design options for the treatments and lessons learned from the process. This technology can be applied to openhole as well as cased multilayered CBM wells.
Building on PRMS to Quantify Risk and Uncertainty in Resource Reconciliations
Authors: Etherington John R. , Stabell Charles B.
Published: February 2011

The Petroleum Resources Management System (PRMS) provides a project-based approach to assessing the full range of recoverable quantities in accumulations from early exploration through mature development phases. As new technical information becomes available and/or commercial conditions change, the estimates of recoverable volumes and their associated risk and uncertainty must be updated. The recording of these changes and the contributing factors is termed resource tracking or resource reconciliation.

For publicly traded companies, regulatory agencies define specific change codes. The US Securities and Exchange Commission (SEC) has historically focused on Proved Reserves and registrants reported annual additions (asset purchases, new discoveries and extensions, improved recovery), deletions (production, asset sales) and revisions (technical and commercial-based) to prior year estimates.

Internal systems must apply resource tracking to the company's full portfolio of projects and are more focused on changes to the expected value (mean) of the estimates. The portfolio may include Reserves, Contingent Resources (discovered not commercial), and Prospective Resources (undiscovered). PRMS further defines sub-classes based on project maturity with the option to quantify associated risk (chance of discovery). Moreover, each resource category has an implied associated confidence factor that discounts volumes for uncertainty. For example, only a portion of Possible volumes may ultimately transfer to Proved. These confidence factors (or "uncertainty discount factors") may be estimated through parallel probabilistic analyses or based on analog assessments. Changes in confidence-factor must be considered as an additional revision type regarding transfers between categories.

This paper discusses a quantitative approach wherein companies compute an expected value for each project as the sum of the confidence-weighted category volumes and also apply an associated sub-class risk factor. A realistic example illustrates combining risk/confidence-weighting and qualitative descriptions of the key source of changes in estimates to support both internal and external resource tracking requirements.
Application of Composite Jet-Rod Pumping System in a Deep Heavy-Oil Field in Tarim China
Authors: Shen Jianxin
Published: February 2011

Great challenges had been faced in the design and selection of artificial lift methods at Lungu reservoir of Tarim field in the North West China due to the extremely deep reservoir and extra-viscous crude. The average depth of the reservoir is about 5500m. The initial reservoir temperature is about 127°C, and pressure ranges from 57 to 64 MPa. With very high content of resins and asphaltenes, the oil from this reservoir has a viscosity of about 10×104mPa.s at 50°C and density varying from 0.95 to 1.08 g/cm3. Thanks to the high reservoir temperature along with high pressure, the oil has fairly enough mobility to flow into the well bore under reservoir conditions. However, as it flows towards the surface, the decrease in temperature along the well bore causes dramatic increase of viscosity. Both calculations and field experience suggested that it is not possible to meet the required production rate with only one particular available mechanical lift method, such as rod pump, jet pump, or other individual lifting method.

To overcome the lifting difficulty and achieve the production volume, a composite pumping system which combines both jet and rod pumps was proposed and practiced in this field. The proposed composite jet-rod pumping system was proven to be a great success, which significantly increased and maintained production volume in the wells tested. This paper discusses the working mechanisms involved in the composite jet-rod pumping system, the lifting parameter optimization methodology and workflow, and the field application experience. This composite jet-rod pumping system was demonstrated to be the most promising mechanical lift system for Lungu reservoir and it can be potentially used in the other deep heavy oil fields world wide.
Flow Profiling and Completion Leak Detection with Memory Production and Corrosion Logging Tools in High Profile Gas Condensate Wells: Case History from Southeastern Bolivia
Authors: Foianini Ivo
Published: February 2011

Production logging is a necessity in today’s deep and complex reservoirs, where high-production and extreme downhole conditions (including high pressure high temperature (HPHT), carbon dioxide, and hydrogen sulfide) require constant monitoring of well performance. This service can be combined with other cased hole logs, such as tubing evaluation and pulsed neutron, to establish a customized relationship between the fluid, wellbore, and completion properties. This process enables the construction of an instantaneous relationship between these three elements and determines the efficient production of each well.

This service integration was successfully applied in a deep gas condensate well in southeastern Bolivia. With more than 5200 m of total depth and a wellhead pressure of 5,500 psi, the operating conditions proved to be difficult. However, they proved ideal for the use of memory logging tools that, when deployed downhole with slickline wire, facilitated surface pressure control without risking log quality assurance/quality control (QA/QC).

Producing at a high flow rate (> 100 MMscf/d) from three reservoirs, the well required constant flow profiling and production follow-up. In addition, the presence of carbon dioxide in the gaseous stream provided opportunities for weakening the mechanical integrity of the completion through the onset of corrosional events. After running a production log, the client discovered an unexpected fluid entry point in the completion string, which was confirmed as an orifice with a subsequent tubing evaluation logging run. After reviewing the original production log, the client determined that the high flow rate from a particular formation had eroded a blast joint and created the orifice.

Running these services with memory tools reduced preparation time and operating costs. These benefits enabled the client to quickly acquire detailed information about the downhole condition of the well, improve the understanding of the relationship between reservoir and completion, and reduce production downtime and service costs.
Benefits of Freshman Engineering Projects for Petroleum Engineering Students
Authors: Bryant J. A. , Salama G. H. , Fahes M. M.
Published: February 2011

The engineering program at Texas A&M University includes a freshman "Introduction to Engineering" sequence for the first two semesters of the freshman year. The Qatar campus of Texas A&M University has four majors offered and all majors take this two semester sequence. The overview course covers many subjects for the students and these typically are very broad in scope. Both courses include at least one or several projects.

Each year, freshmen student evaluations are critical of the perceived lack of applicability of the design project to petroleum engineering students. One possible reason for this perception could have been that during the first four years of program startup, there were no petroleum engineering professors involved in teaching this course. Nevertheless we noticed that the projects introduced important skills that petroleum engineers need. A review of the junior and senior curriculum and ABET outcomes confirm this.

In this paper, we discuss some of the projects offered in these freshman courses, and the skills it promotes. We also present the results of a survey that included almost all of the students at Qatar campus from all four engineering majors and compare the responses of the students in terms of the perceived benefits of these courses and the skills it promotes.

Proper design of projects for inclusion of necessary skills and tools for petroleum engineers is recommended to ensure students are equipped with appropriate competencies needed for upper division classes. Our results show that the skills promoted by projects currently being implemented are in line with the skills that petroleum engineering students need for their upper devision classes as well as their careers.
Water Recycling Helps with Sustainability
Authors: Pierce Dale A. , Bertrand Kelly , Vasiliu Cornelia Cretiu
Published: February 2011

The oil business uses a large quantity of water during the drilling and completion of an unconventional gas well. In many of the shale plays each well needs in excess of 4 million gallons of water (100,000 bbl) during the drilling and completions operations. Water is a precious resource and many areas are faced with water shortages.

Water shortages extend to almost all the traditional oil and gas producing areas in the United States including Colorado, California, Wyoming, Texas and Oklahoma. Also, the arid areas of Australia, The Middle East, and Africa see even more severe shortages of fresh water than in the United States. Moreover, in areas where water is not in short supply such as Indonesia, Malaysia, and the Eastern United States, discharge of high salt content water is problematic. In order to assure itself of adequate water for drilling and completion operations, the oil business needs to change the ways it has traditionally transacted its business.

As stated above many drilling areas are faced with water shortages, whereas many other producing areas are faced with high disposal costs for frac flow back water and produced water. In many traditional production areas disposal of water is simple and usually inexpensive since there are numerous injection wells in these traditional production areas. However, in some of the new Shale plays the access to injection wells for disposal of produced water and frac flow back water is very limited.

Part of the solution is to recycle the frac flow back water and the produced water for use as drilling fluid or for Frac Fluid. How clean does this water need to be for use as a drilling fluid or a frac fluid? What techniques are used to clean this water? How costly are the various techniques? These questions and others will be addressed in this paper.
Increasing Lazy Gas Well Production: A Field Wide Case History in Northern Alberta
Authors: Wylde J. J.
Published: February 2011

This paper summarizes methods, chemistries, and application results for a range of liquid foaming agents on a collection of wells applied at a single property in Northern Alberta. The paper goes on to summarize the philosophy, design criteria for selection of remediation chemistries, and methodologies used to counter the production decline occurring as a result of water production.

Gas flow rates from these low pressure gas wells were being dramatically affected by production of free or condensed water. If allowed to collect to sufficient levels, the produced fluid killed production altogether. The shallow (500 to 750 meters) wells on this lease are particularly sensitive to fluid production as reservoir pressure was very low, approximately 700 kPa (102 psi), and production of only 0.5 m3 (3.15 bbl) of water per day could kill a well.

Additional challenges were caused by high solids production and scale deposition. Additionally, further loading up the wells and lowering production as well as asphaltene precipitation, formed a very adherent and dense solid precipitate with sand produced by the well.

Initially wells were cleaned with a combination batch asphaltene solvent. Subsequently, a very pervasive foam forming chemical was used to unload solids. Continuous injection of 2 liters per day of a liquid based foaming chemical into one particular well increased gas production by 3 e3m3 (0.1 mmcf) per day (a 50% increase). Other wells were successfully treated to remove water and solids that were blocking the perforated interval. Significant value was added by increasing production field wide by 33% with an insignificant associated chemical cost.

The results and conclusions of this work are applicable to the shale gas and CBM fields being produced throughout North America and enable best practice chemical well enhancement to be applied.
Improving Stimulation Effectiveness – Field Results in the Haynesville Shale
Authors: Pope C. D. , Palisch T. T. , Lolon E. P. , Dzubin B. A. , Chapman M. A.
Published: February 2011

Effective hydraulic fracturing has become a critical component in the successful development of most unconventional gas reservoirs, including the massive Haynesville Shale. The rig count in the Haynesville currently exceeds 130 active units and is expected to continue to climb. Many hundred horizontal wells have been drilled and completed, and several thousand stages have been hydraulically fractured. With this large and sometimes diverse cross section of wells, best practices have begun to emerge for various aspects of the stimulation design.

This paper focuses on several areas of the completion and hydraulic fracture design in the Haynesville Shale that are identified as critical to the success of this play, including:

The impact of lateral length, number of fracture stages and perf clusters The impact of effective fracture length The impact of fracture conductivity

This paper will review production data from 56 wells completed in close proximity by a single operator to evaluate the impact of fracture design on initial production rates and sustained productivity after six and twelve months. These findings will be compared to reservoir simulator predictions, pressure transient testing, and production data analysis interpretations to evaluate the mechanisms constraining well production.

Readers of this paper who are currently working in the Haynesville will be able to compare their current completion techniques to those presented in the paper. The authors hope this paper will promote a continued dialog on best completion practices among operators in this massive shale play. The findings in this paper may also be used by engineers as a guide for moving up the learning curve in other unconventional plays.
Combining Seismic Models with Realtime LWD Measurements to Reduce Geologic Uncertainty: A Case Study of the Mars A-8 Extended Reach Well
Authors: Weiland Jeff , Cuttitta Matt , Soto Gerard , Wandstrat Matt , Donadieu Brian , Jebutu Segun
Published: February 2011

In January of 2008, Shell began drilling an extended reach exploration well from the Mars tension leg platform (TLP). This was an ambitious undertaking with targets nearly 20,000 ft (6,096 m) away in an unexplored fault block. Because of the high inclination of the borehole and the shallow depth of the objective sands, any geological uncertainty in the targets jeopardized the success of the project.

While surface seismic is used to evaluate potential targets, it lacks the resolution needed to reliably place those targets. Different seismic processing techniques are available, but the validation of each model requires additional information. True vertical depth (TVD) and true vertical thickness (TVT) synthetic ties created from realtime logging data can improve that resolution. By employing a method that uses TVT, the synthetic ties better match the seismic model allowing for updates to the well path and precise placement inside the target. Multiple velocity models are also incorporated to obtain better time-to-depth relationships and to better predict pore pressure anomalies.

In extended reach wells, small issues in the beginning can escalate into more serious problems at total depth. The well path, dogleg severity, and casing shoe placements must be optimized, leaving room for the possibility of changes due to unexpected events. Bottom hole assembly (BHA) design is also a key success factor. Acquiring the needed information in realtime to update the seismic model, while also factoring in tool reliability and planning for shoe-to-shoe performance, is critical. Further, at these high angles, it is important to drill a smooth and continuous borehole to reduce torque and allow for better casing runs.

This paper describes how the geological, mechanical, and economical uncertainties were identified and minimized through well planning and the use of realtime data. Specifically, this paper addresses those uncertainties, associated risks, and the methods to minimize them in the A-8 well.

The authors examine the pre-well work undertaken with the seismic data and how the BHA and well plan were designed to allow for possible changes. In addition, they will discuss how all the data were used to continually update the model and reduce geologic uncertainty as the targets were approached. Answers were provided in time to update the well path, increasing the chances for success, and ultimately meeting the well objectives.
Drilling of Middle-Eastern Reservoir Carbonate Rocks by High Power ND: YAG Laser
Authors: Erfan M.R. , Ahmadi M. , Ashena Rahman , Ashena Rahim , Nazari M. , Roohi A. , Moazeni A. , Moradkhani Mehrdad
Published: February 2011

High power lasers when applied to drilling is potentially capable of reducing the drilling time, improving well performance and exemption from the necessity to remove the cuttings.

In this paper, Rate of Penetration (ROP) and the specific energy (SE) required to remove the rock from Carbonate reservoir rock, Ahvaz#383-9 is measured using the Nd.YAG pulsed laser to identify the prospective laser application for drilling in South of Iran. The three samples selected from each depth and formation were the dry, water and oil saturated. The petrography studies of the rock samples were performed before and after the laser test to analyze any changes in the rock mineralogy and properties. SE was measured with different operational parameters comprising the laser beam and rock properties to detect their effect. This would help us to spot the optimum operational beam parameters with fixed rock properties to be adjusted to obtain minimum SE.

The results show SE increases with increasing laser radiation time and drilling depth non-linearly. SE corresponding to water saturated samples were higher than that of oil saturated and the SE of oil saturated were higher than that of the dry samples. ROP and SE showed to have a nonlinearly inverse relationship.

The optimum operational parameters determined, can help optimize the laser application in regards to obtaining the minimum SE. Future laser rock mechanical laser simulation softwares can be developed based on the experimental approach.
Qualifying Seismic as a Reliable Technology —An Example of Downdip Water Contact Location
Authors: Sidle R. E. , Lee W. J.
Published: February 2011

The term "reliable technology" was added to the lexicon of oil and gas reserves estimation with the updated regulations published by the US Securities and Exchange Commission (SEC) in late 2008. A previous paper by the co-authors (2010), SPE 129689, described an approach to the demonstration that a technology satisfied the criteria of a reliable technology. This paper builds on the use of the scientific method, as described in the previous paper, by examining a real-life example of seismic interpretation to define water contacts downdip of hydrocarbon column penetrations.

Complex technologies, such as seismic, require careful and detailed calibration and testing to demonstrate the consistency and repeatability needed to qualify as a reliable technology. However, this complexity need not preclude that technology from use as reliable. Proper analysis of the science behind the technology and testing to demonstrate those circumstances which allow reliable conclusions from the technology will permit even a complex technology to be qualified as acceptable.

The example used is from the Gulf of Mexico (GoM) Deepwater. It gives the results from several turbidite sand reservoirs in multiple fields to demonstrate the conditions under which certain seismic can be shown as reliable. The learnings from these applications allow the development of a "reliability qualification checklist" which defines the conditions under which the seismic data are definitive. Then it describes the final testing of the "reliable data" to determine when a seismically interpreted water contact is sufficiently conclusive to be reasonably certain.

This paper will provide a useful description of how the qualification of a technology can be planned, tested and conclusions drawn. It will provide examples of constraints that develop from the theoretical analysis and testing results and show how these constraints can be incorporated into a set of limitations on the application of the technology. While certain elements of the technology are discussed in this paper, it is not the authors’ intent to provide an exhaustive description of the seismic theory and methods used for this example. Rather, the paper will focus on the reliability demonstration process.
Experimental Studies on the Effect of Mechanical Cleaning Devices on Annular Cuttings Concentration and Applications for Optimizing ERD Systems
Authors: Ahmed Ramadan , Sagheer Munawar , Takach Nicholas , Majidi Reza , Yu Mengjiao , Miska Stefan , Rohart Christophe , Boulet Jean
Published: February 2011

In horizontal and highly deviated portions of an Extended Reach Drilling (ERD) well, cuttings beds form on the low-side of the annulus. The bed partially blocks the annulus resulting in excessive pressure loss and a higher equivalent circulating density (ECD) that is exacerbated by the increase in length of the annulus. This condition limits hole-cleaning capabilities. As a result, selecting favorable drilling parameters is not always sufficient to overcome the hole cleaning problem. Recently, the use of downhole Mechanical Cleaning Devices (MCDs) has been introduced to the industry to mitigate the problem without inducing excessive ECD. Although the use of these tools is increasing, very limited studies have been conducted to optimize their performance.

This paper presents results of an experimental study that was carried out to evaluate cuttings removal efficiency of MCDs and applications of MCDs for optimizing ERD systems. Experiments were carried out in a large-scale flow loop that has an 8-inch transparent test section. Three different drillpipe sizes were considered in the investigation. The Taguchi approach was implemented to reduce the number of experiments while covering the most relevant parameters such as flow rate, ROP, diameter ratio, tool design and drillpipe rotation speed. For each test, the amount of cuttings accumulated in the test section was determined from weight measurements. Results indicate that the tools significantly reduce the amount of cuttings in the annulus, especially around the MCDs, compared to locations where there is no tool.

Experimental results were evaluated to obtain the overall effect of operating parameters on annular cuttings concentration and develop correlations. The results show that the flow rate and inclination angle have the most significant impact. The correlations are useful to develop an analytical model for designing and optimizing drilling systems with MCDs, either in terms of operating parameters or drillstring design.