bluuebunny/crossref_metadata_2025_split huggingface dataset:
Rotating Jet Technology Improves Stimulation Fluid Placement to Effectively Treat Horizontal and Gravel Packed Wells – Lab Model Tests and Global Results Are Reviewed
Authors: Stanley F. O. , Serrano Fabrizio , Knopp Steve 
Published: December 2007

AbstractEffective placement of stimulation fluids on horizontal, long interval and/or gravel-packed wells is critical for cost-efficient production enhancement. Successful case history work in 19991, using precision rotary jetting technology (R-Jet) on the end of coiled tubing (CT), demonstrated to the oil and gas industry that fluid placement is a key factor in removing near-wellbore damage and optimizing well stimulation treatments.This paper will review continued efforts relating to precision rotary jet technology including extensive laboratory tests using a full-scale gravel pack (GP) model. Tests were videotaped for further visual study. Established guidelines applying lab results, computer modeling, and field validation provide a well-engineered, non-damaging (low nozzle pressure) treatment for optimum stimulation performance. Proper damage identification coupled with skillful stimulation fluid design are important steps to a successful job and will be highlighted in the global R-Jet case histories.The data clearly shows that a highly effective method of placing stimulation fluids into a completion, such as sand control screens or slotted liners, is to use CT-conveyed, rotary speed-controlled, forward-angled radial jets. This technique yields 360° coverage of the treatment area, is more efficient than traditional bullheading and CT methods and allows reduced treatment volumes to be considered. It applies to a wide selection of completions including horizontal wells which can now be successfully stimulated at reasonable costs.
Underbalanced Drilling of Fractured Carbonates in Northern Thailand Overcomes Conventional Drilling Problems Leading to a Major Gas Discovery
Authors: Pinkstone Henry , Timms Andy , McMillan Scott , Doll Rick , de Vries Hans 
Published: December 2007

Abstract
In the Phu Horm Field in Udon Thani Province, Northern Thailand, conventional overbalanced drilling of fractured carbonates had presented severe difficulties. The first 2 wells drilled in the field, Phu Horm 1 and 2, were sub-economic. Therefore, the Phu Horm 3 location was chosen to maximize the likelihood of encountering an extensive fracture network that would increase productivity and deliver economic flow rates.
Amerada Hess commenced drilling the Phu Horm 3 well conventionally using a water-based mud. The well was drilled into the top of the Pha Nok Khao Limestone reservoir, wherein severe fluid losses were encountered. The loss of hydrostatic head resulted in a gas kick with 1200 psi at surface. After pumping large quantities of loss circulation material in an attempt to block the fractures, the bottomhole assembly (BHA) became stuck. The drillstring was explosively severed, 71m of BHA were cemented in the hole, and operations were suspended.
This paper will discuss how a sidetrack was drilled on Phu Horm 3 using underbalanced drilling techniques in order to overcome the problems of lost circulation and safely maintain pressure control. The well was flow drilled underbalanced by injecting fresh water as the underbalanced fluid and producing gas, water, solids and condensate back to a four-phase separation package. The well was successfully completed barefoot and underbalanced. The paper will discuss the planning and execution of the underbalanced drilling operation, including some of the challenges, and learnings gained for future operations.
On Phu Horm 3 the primary objective of using underbalanced drilling technology was to enable the well to be drilled safely while maintaining pressure control and minimizing the potential of severe fluid loss. These problems had been experienced while drilling the over-pressured reservoir section of the original well. Other objectives were to reduce formation damage and evaluate productivity and reservoir characteristics during the drilling operation.
The Phu Horm 3 underbalanced project is categorized as a Level 5B5 well in the IADC UB classification system due to circulating wellhead pressures in excess of 3000 psi and gas flow rates of 50 MMscfd being seen during the course of operations. The well was drilled without any safety or environmental incidents, or loss or damage to equipment.
This underbalanced drilling project verified the applicability of underbalanced drilling in the Phu Horm field, as well as discovering major gas reserves.
Maximizing Reservoir Potential Using Enhanced Analytical Techniques with Underbalanced Drilling
Authors: Ansah J. , Shayegi S. , Ibrahim E. 
Published: December 2007

Abstract
Improved oil and gas recovery begins at the point of first contact with the reservoir. If drilling of the wellbore used to access reserves is accomplished with minimal formation damage, then oil and gas recovery will be maximized at all stages of reservoir development: from primary exploitation through to tertiary recovery. Underbalanced drilling (UBD) is a technique that has shown excellent results in this area for vertical and horizontal wells.
This paper describes the use of UBD technology to improve the overall hydrocarbon recovery. It focuses on how this technology can be used to maximize reservoir performance, illustrating these gains with the results of a field case where this technology has been applied.
At its inception, UBD technology was focused primarily on drilling issues such as increasing the rate of penetration, avoiding drilling problems including differential sticking, lost circulation incidents, and facilitating drilling through difficult zones. More recently, however, UBD has seen increased application in cases where the primary objective is to avoid or minimize damage to the reservoir. This change of focus to the reservoir means that from the outset, recovery from the reservoir can be maximized with data and information gathered much earlier than in the typical field development life cycle. To take advantage of the availability of the "well testing type" data during underbalanced drilling, analytical and numerical models were developed. Results from these models, which permit analysis of each of the productive zones as they are traversed, are reviewed. Finally the current developments in further characterization of the reservoir being embarked upon are described. The results from the modeling in conjunction with a new system being developed for on-site analysis of produced fluids while drilling, allows characterization of the produced effluent which can be used to determine waterflood status, interconnectedness of a system, sweep efficiencies of the current water or gas floods, bypassed oil, and to aid in optimizing completion methods and multi-well infill drilling campaigns.
Horizontal Gravel Packs Successfully Deployed in Trinidad's First Multilateral Well — Planning, Implementation, and Remedial Strategies
Authors: Lougheide Delano , Lutchman Krishna , Anthony Elred , Waterman Bert , Cavender Travis , Flores Denar , Ramsook Vishnu 
Published: December 2007

AbstractThis paper discusses the first multilateral well drilled in Trinidad and the unique integration of techniques that allowed sand control procedures to be implemented as well. The well was recently drilled and completed in the 759 area of the northern Soldado Field, offshore Trinidad in approximately 60 feet of water. A multilateral completion was selected over conventional well construction to horizontally access heavy-oil reserves in the Forest 4B and 4C sands, located at true vertical depths of 3850- and 4000-ft respectively. Since the formation parameters included poorly sorted, non-uniform formation characteristics, the completion would have to employ some method of sand control.This well represents several "firsts" for this area as it not only represents the first multilateral well in Trinidad but also is the first in the area that integrates sand control into a multilateral.After reviewing many possibilities, horizontal openhole gravel-pack technology had been selected to provide sand-exclusion. A TAML 4 multilateral well junction was selected originally because it offered a cemented junction with full casing-drift access across the mainbore/lateral interface. When sand was encountered above the junction area, a completion workover was required to convert the existing TAML 4 multilateral junction into a TAML 5 to gain pressure integrity across the junction area.The paper will present the initial planning, special considerations, methods for implementation of horizontal gravel pack into multilateral technology, and finally, the rework operation later required for junction conversion.
Poromechanics Modeling of Wellbore Stability in Naturally Fractured Formations
Authors: Nguyen V. , Abousleiman Y. , Mody F. K. 
Published: December 2007

Abstract
With recent advances in drilling technology, directional drilling in deep and highly fractured formation has received considerable attention concerning the stability of the wellbore. The majority of the existing wellbore stability predictions are based on the solutions obtained using single-porosity elastic or poromechanics theory which considers rock formations to be homogenous with one degree of porosity distribution. However, the solutions may fall short when the rock formation is also fractured. The dominant characteristics of fractured rock formations, i.e., the coupling between various induced hydro-mechanical processes and interporosity flow can be well represented under the realm of dual-porosity poromechanics. Due to the complexity of the physical phenomena and mathematical formulations associated with a dual-porosity system, to date the solution for industry field applications e.g. mudweight estimation, pore pressure and stress distribution in wellbore drilling in fractured formations does not exist. This paper aims at using a consistent dual-porosity poromechanics and/or poroelastic analytical model to analyze wellbore stability in naturally fractured rock formations.
Application of Vacuum Insulated Tubing to Mitigate Annular Pressure Buildup
Authors: Azzola J. H. , Tselepidakis D. P. , Pattillo P. D. , Richey J. F. , Tinker S. J. , Miller R. A. , Segreto S. J. 
Published: December 2007

Abstract
Vacuum insulated tubing (VIT) has been used successfully to mitigate the potentially harmful effects of annular pressure buildup (APB). In a recent deepwater installation, the subject well had lost alternate APB mitigation capability through a series of events. VIT was then chosen as the only viable technology.
A common design companion of VIT is gelled brine, chosen to decrease annular natural convection driven by heat loss around the VIT connections. There are, however, several drawbacks to the indiscriminate use of gelled brine: Tight clearances around the tubing hanger running tool, creating the potential for debris plugging and/or tool recovery issues from the subsea wellhead,Limitations imposed by VIT collapse and hydrostatic packer setting pressures,Unknown temperature/viscosity response and associated quality control requirements for displacement through a subsea wellhead, andA need to reduce operational time and cost.
These issues led to the consideration of alternative means of controlling natural convection, and an effort was made to understand, improve, and deploy external coupling insulators.
An in-ground vertical experiment with two connected joints of VIT was conducted with and without coupling insulators. Temperatures were monitored at multiple locations. Test results confirm the effectiveness of external coupling insulators. Several theoretical models using different numerical techniques (finite difference, lumped mass/resistance, finite element, and computational fluid dynamics) were found to be consistent with experimental results. These were compared with critical APB temperatures calculated with a commercial wellbore simulator. The net result of these studies was to adopt the external insulators.
This paper reviews the experimental data and presents several models of a vertically aligned VIT in a deepwater completion. A comparison of thermally effective APB solutions, together with a critical assessment of modeling accuracy, is presented.
Perforating and Hydraulic Proppant Fracturing in Western Siberia, Russia
Authors: van Gijtenbeek Klaas A. W. , Pongratz Reinhard 
Published: December 2007

AbstractHydraulic proppant fracturing is developing rapidly in the oil fields in western Siberia and is seen as the most important means to improve oil production from both existing and newly drilled wells. The oil fields vary in size and reservoir quality, with a majority of the developed fields showing permeabilities of 1 to 30 mD. Reservoirs are layered, and fracturing vertical wells in general seems to give higher productivity compared to horizontal wells that are not being hydraulically fractured. This result is most likely because the vertical permeability is much lower than the horizontal permeability.To maximize production from these wells, coarse-sized proppant must be placed using the least-damaging and lowest-viscosity fluid systems. For production optimization, the trend is currently "larger (proppant sizes) and bigger (jobs)," using the lowest acceptable polymer loading in the frac fluids, which minimizes gel damage.This paper describes the conflicts that can arise between the requirement to place large amounts of coarse propping material using low viscosity fluids and the perforation size and condition that is needed to do so. These conflicts can lead to job scenarios in which screenouts take place.During fracturing operations in wells in west Siberia, some screenouts did take place. An investigation of the screenouts revealed that the major cause of the screenouts is reduced width development at the perforations associated with the "stress cage." Guidelines were developed to reduce the influence of the near-wellbore stress cage and prevent screenouts. In addition to these guidelines, future solutions are proposed that may avoid the stress cage and place coarse proppant more efficiently.
Is Bitumen a Petroleum Reserve?
Authors: Etherington John R. , McDonald Ian R. 
Published: December 2007

Abstract
Like most reserves issues, the answer depends on the specifics of the project relative to an interpretation of the applicable regulatory guidelines.
The US Security and Exchange Commission (SEC) regulation S-X, 4-10 a) states that: "Oil and gas producing activities do not include the extraction of hydrocarbons from shale, tar sands, or coal". Thus, it has been generally accepted that oil derived from processing of mined bitumen cannot be included in petroleum reserves of companies listed on the US stock exchanges. However, the quantities of synthetic oil derived from the upgrading the same bitumen produced out of wellbores using thermal processes are routinely included in reserves disclosures. The logic is that the activities largely duplicate those involved in producing and processing heavy oil.
The new Canadian Security Administrators' regulations (NI 51-101), take a different approach: "The intended product of both conventional and non-conventional oil projects is essentially the same – a liquid hydrocarbon. We believe that investors are likely to consider a reporting issuer focused on oil sands to be more comparable to a conventional oil producer than to a hard rock mining issuer. Accordingly, NI 51-101 applies to activities directed at the extraction or production of hydrocarbons from either conventional or non-conventional sources (such as surface mines and in-situ projects)".
Which approach provides more clarity for investors? Should the sales product quantities derived from mined and thermally recovered bitumen be treated differently? What would be the international impact of including all bitumen in petroleum reserve estimates and production statistics?
This paper presents background and reviews industry practices for the estimation and disclosure of bitumen resources. The issue is of most interest to the Canadian industry; it is forecast that by 2012 over 50% of that nation's crude production may be derived from bitumen.
A Comparative Study of Sea-Going Natural Gas Transport
Authors: Subero Gloria , Sun Kai , Deshpande Asim , McLaughlin John , Economides Michael J. 
Published: December 2007

AbstractRapidly increasing worldwide natural gas demand and tight domestic supplies in many consuming countries suggest that trans-national transportation of gas will rapidly become important. From a technical perspective, the most economically attractive gas transport option depends on a specific project's reserve base, production capacity, and required shipping distance.This paper examines and quantifies how distance, reserves, and gas production rate affect the technology selection and project economics. Sea-going natural gas transport technologies are: liquefied natural gas (LNG), compressed natural gas (CNG), sub sea pipelines (PNG), gas-to-liquids (GTL), gas-to-wire (GTW), or gas-to-solids (GTS). Available data on capital, operating, and shipping costs for proposed, conceptual, and actual gas-transport projects are analyzed. These cost functions are then integrated into an economic model, which is used to determine the economic constraints of a number of theoretical developments that cover a range of gas rates and shipping distances.Given pricing, financing, and escalation assumptions, net present values (NPV) of the four options are generated over a range of daily gas rates and shipping distances. By examining which option delivers the highest NPV some conclusions are reached: Pipeline and CNG projects are best suited to maximize returns for shorter distances (e.g., 1,000-2,000 km); LNG is better suited for long distance projects.We find that meaningful comparisons between CNG and LNG are for relatively small volumes of gas, i.e., less than 500-600 MMscf/d. For large quantities and for any reasonable distances LNG is still by far the best option. For distances &gt;3,000 km, it is necessary to have at least a &gt;500-600 MMscf/d gas stream available for 20-30 years; this translates to a requirement of a reserve base on the order of 5-10 TCF to supply these long haul projects. For CNG much smaller reserve bases are attractive.
Flow Assurance and Subsea Productivity: Closing the Loop with Connectivity and Measurements
Authors: Ratulowski J. , Amin A. , Hammami A. , Muhammad M. , Riding M. 
Published: December 2007

Abstract
Flow assurance is a key priority for the subsea community as it is being challenged to provide answers to the following question: Can we manage the risk of hydrocarbons flow interruptions while optimizing the system performance using current flow assurance practice?
Traditionally, flow assurance has focused on evaluating potential production problems associated with produced fluid issue such as waxes, asphaltenes, hydrates and scale. A combination of fluid sampling, laboratory techniques, and predictive modeling are then used for system selection and design of prevention and remediation strategies. These are often based on conservative modeling practices using incomplete or inconsistent data sets. No allowance for continuous monitoring that will provide data needed to recalibrate the system or to change the course of the process over the subsequent years is made. The result is often an overly conservative system design and operating strategy.
The paper discusses a more dynamic approach to answering the above question as it explores the integration of the design and surveillance processes. Advances in sampling, analysis and modeling that reduce conservatism in design are reviewed. The role of real-time measurements during production from the reservoir, the wellbore, and the subsea infrastructure, in monitoring and optimization of a system is then discussed. Specific case examples are presented throughout to illustrate these points.
A Multiscale Methodology for Simulating Miscible Gas Injection Projects Applied to a North African Oil Field
Authors: Bronchalo Jesus , Venkataraman Ramachandran , Blunt Martin J. 
Published: December 2007

Abstract
We present a methodology for the simulation of miscible gas injection applied to a water alternate gas (WAG) project being considered for oil field in North Africa. First we run one-dimensional (1D) simulations using an eight-component Peng-Robinson equation-of-state and tune the fluid characterization to match the results of slim tube experiments at different pressures. We use the simulations to determine the minimum miscibility pressure (MMP) by finding the pressure at which a piston-like advance of the injected gas is observed. We find that while acceptable recoveries that match the experiments may be obtained using 100 grid blocks, even when using 10,000 blocks a converged saturation profile is not obtained, especially close to the MMP.
We then run 2D compositional simulations above the estimated MMP to model viscous fingering. We compare the results with those of a black-oil model that assumes a first-contact miscible displacement (FCM). The compositional simulation predicts much less fingering than the FCM black-oil model. This is because the resolution of the 2D compositional simulation, even with a very fine grid, is insufficient to resolve the sharp transition in viscosity from injected gas to reservoir oil and thus severely underestimates the apparent viscosity contrast. We recommend using a simpler FCM simulation if the system is above the MMP. The degree of fingering in the FCM model is accurately predicted using the Koval model.
At the field scale we use FCM simulation with a Todd & Longstaff mixing parameter ω that accounts for small-scale fingering. For WAG floods the value of ω is adjusted to account for the reduced mobility ratio between injected gas and water and displaced oil. Overall we show how to account systematically for the development of miscibility and sub-grid-block fingering in field-scale simulation of a miscible gas injection project.
Secondary Porosity and Permeability of Coal Vs. Gas Composition and Pressure
Authors: Mavor Matthew J. , Gunter William D. 
Published: December 2007

AbstractWe have been investigating sequestration of atmospheric pollutants by injection into coal seams while at the same time enhancing hydrocarbon productivity by displacement of methane by the pollutants. During the course of our field measurements, we have been using single well injection, soak, and production tests to collect data required to understand and predict enhanced coalbed methane (ECBM) recovery potential and sequestration capacity. We found that changing the composition of the gas sorbed into the coal changes the porosity and permeability of the coal natural fracture system due to gas content changes, which cause matrix swelling or shrinkage due to relative adsorption of different gases.We collected sufficient information to develop a method for predicting the permeability and porosity of a coal bed as a function of the secondary porosity system (SPS) pressure and the gas content and composition of the primary porosity system (PPS). The method uses data from injection/falloff tests using water and/or a weaker adsorbing gas (WAG) than CH4 and a stronger adsorbing gas (SAG) than CH4. Estimates of effective permeability to gas and water obtained from these tests are used with an iterative computation procedure subject to constraints to solve for equivalent SPS porosity and absolute permeability at atmospheric pressure.Once calibrated, the model can be used to predict a coal bed's permeability and porosity as a function of injection pressure and injected fluid composition that in turn are used to predict injection performance. The model is applicable to production forecasts to account for SPS permeability and porosity changes as reservoir pressure declines with changes in gas composition.This paper describes the new model and discusses well test procedures to obtain the data required for model calibration. Also included are coal property estimates resulting from Alberta Medicine River (Manville) coal core and test data and an example model calibration.