bluuebunny/crossref_metadata_2025_split huggingface dataset:
Enhanced Hydrate Inhibition in Alberta Gas Field
Authors: Budd Dana , Hurd Danica , Pakulski Marek , Schaffer Thane D. 
Published: December 2007

Abstract
Gas wells located in Southern Alberta, Canada pose challenges for well operators. High bottomhole pressure in new wells, low bottomhole temperatures and Joule-Thompson expansion cooling effect often lowering gas stream temperatures to below brine freezing create favorable conditions for formation of gas hydrates in the wells and transportation pipelines. The problems are aggravated during cold winter months when wells and pipelines have strong tendencies to plugging with hydrates and ice. Operators experience significant monetary losses due to disrupted production and have to spend considerable amount on chemicals and time to clean up hydrates from plugged wells and pipelines.
With subcooling temperatures often exceeding 14°C, kinetic hydrate inhibitors are incapable of preventing hydrates formation. A typical solution to such severe hydrate problems is pumping massive amounts of methanol or glycols to the well and production lines. Adding large amounts of thermodynamic inhibitors creates problems by itself like oxygen corrosion or solvent induced scaling. Earlier work in the field indicated a possibility of synergism between thermodynamic hydrate inhibitors and Low Dosage Hydrate Inhibitors (LDHI). Systematic laboratory work was undertaken to explore possible synergistic effects between methanol and LDHI. A strong synergistic effect was discovered at a certain ratio of methanol and low molecular weight oligomer type hydrate inhibitor. These observations allowed a formulation of a superior hydrate inhibitor. Field results show the reduction up to 80% of the original and often insufficient methanol dosages. Due to this novel approach to hydrate problems, the operator experienced more trouble-free field operation and increased gas production, improved economics with less down time, lower total cost of chemicals and delivery.
Level 6 Multi-Lateral Experiences in the Niger Delta – A Review
Authors: Erivwo Ochuko , Ugboaja Remmy , Ikoh Editi , Banks Andy 
Published: December 2007

Abstract
Multi-Lateral technology was selected in SPDC as one of its strategic cost leadership initiative to drive down the development costs of its hydrocarbon assets. Its main objective was to reduce well construction costs by 30 – 40% in terms of unit footage costs and unit development costs and to increase string months available per rig. The technology implementation was set within legislative requirements peculiar to the area and its reservoir geology, which constrained the available options.
To date five level 6 multi-lateral wells have been successfully drilled and completed while a sixth one was aborted due to a junction installation failure. Two of the wells were Deep Set Splitter (DSS) installations in the same field while the others were Formation Junction (FJ) applications in two different fields. Field execution for the Formation Junction wells encountered significant challenges, which resulted in several innovative approaches including design and procedural modifications to achieve success. Commercial improvement was also observed as the implementation progressed.
This paper presents the application of level 6 multi-lateral technology and it’s impact in SPDC. It reviews the concept selection, engineering planning, risk analysis and mitigation for the wells. It dwells on the technical experiences from the execution phase with a special focus on the failed attempt. It also presents learnings and best practices from the technology implementation with recommendations for future applications in the industry.
Optimisation of Well Placement and Improved Well Planning within a Collaborative 3D Environment Employing Real-Time Data: A Case Study from the Visund Field, Norway
Authors: Girling S. B. , Lambert A. D. , Andersen K. , Båtevik A. 
Published: December 2007

Abstract
The overall success of an oil and gas company is largely judged by their ability to prolong revenue from producing fields. Reducing operating cost has the single most significant impact on this objective but has become more challenging to minimize, as the deviated wells required to economically exploit reserves, necessitate highly accurate placement and increasingly advanced engineering. Rapid evaluation cycle times and operational lost time prevention are critical to cost reduction.
This paper will detail how the well design process and WITSML enabled real-time drilling information is conducted and visualized in one 3D view. It will demonstrate how this increased efficiency, contributed to better well placement and reduced operational cost, by complementing technical expertise and increasing collaboration, through a multidiscipline workflow approach.
This change in working practice culminated in the success of achieving the worlds fastest drilled well of more than 8000m measured depth, from a sub sea template.
The Evaluation of a New Environmentally Friendly Combined Product for Application in the North Sea for Effective Scale and Corrosion Control
Authors: McNaughtan D. , Winning I. G. , Sim M. 
Published: December 2007

Abstract
The introduction of more stringent environmental regulation within the North Sea has resulted in increased focus on developing environmentally acceptable inhibitors for application to oil and gas applications. One approach in fulfilling these criteria has been the emergence of multifunctional combined products. This paper demonstrates how this approach can be used effectively to control both scale and corrosion problems. A new environmentally friendly product was developed within the laboratory that gave improved scale control performance against conventional products while also affording excellent corrosion control. A series of tests were conducted to establish the performance of the product as well as compatibility with produced fluids from a North Sea platform. The results of the laboratory investigation are discussed in detail including the advantages and disadvantages offered by this approach as well as the potential environmental benefits.
Application of Mini-Falloff Test to Determine Reservoir Parameters and Optimize Fracture Designs in a Tight Gas Field
Authors: Harting T. A. , Cox D. L. , Murillo R. , Young T. L. , Adegbola K. A. , Schupp D. 
Published: December 2007

Abstract
This paper provides examples of using small injection tests on tight gas wells in Jonah field to determine reservoir pressure and transmissibility.
Prior to Mini-Falloff (MFO) test application in Jonah field, reservoir pressure and permeability of each sand body were obtained from log-derived correlations; these correlations in the presence of depletion have been determined to be invalid. The incorrect reservoir pressure and permeability will generally result in wrong fracture geometry and pre-frac rate prediction. The MFO's were designed as small injection tests prior to fracture stimulation to correct these anomalies.
The After Closure Period following the MFO injection and shut-in contain the reservoir pseudo-linear and pseudo-radial flow periods. Analysis of the pseudo-radial flow period provides reservoir transmissibility (kh/μ) and initial reservoir pressure (Pr) in a manner similar to a Horner analysis. These two-reservoir parameters play a crucial role in the optimization of fracture design and rate prediction. For a tight gas sand, the amount of time required to reach pseudo-radial flow was thought to be quite large. However over sixty percent of all the valid tests performed so far reached pseudo-radial flow within a shut-in time of 24hrs.
A total of eighteen MFO tests were performed in the Jonah field Lance formation from April to October 2003. Two of the tests were invalid due to extremely high depletion and surface pressure gauge malfunction. The remaining sixteen valid data sets show various ranges of depletion in twelve sands tested (0.36 - 0.52psi/ft) while the two remaining sands were over-pressured (&gt; 0.7psi/ft). Permeability results in general ranges from 0.004 to 0.08md. The Jonah field log-derived correlations were validated and improved with the MFO results.
Unified Model of Heat Transfer in Gas-Liquid Pipe Flow
Authors: Zhang H. -Q. , Wang Q. , Sarica C. , Brill J. P. 
Published: December 2007

Abstract
A unified model of multiphase heat transfer is developed for different flow patterns of gas-liquid pipe flow at all inclinations from -90° to +90° from horizontal. The required local flow parameters are predicted by use of the unified hydrodynamic model for gas-liquid pipe flow recently developed by Zhang et al.1,2 The model prediction of the pipe inside convective heat transfer coefficients are compared with experimental measurements for a crude oil/natural gas system in horizontal and upward vertical flows, and good agreement is observed.
Integrating Completion and Drilling Knowledge Reduces Trouble Time and Costs on the Pinedale Anticline
Authors: Garcia Joe , Huckabee Paul , Hailey Byron , Foreman Jay 
Published: December 2007

AbstractThe Pinedale Anticline of southwest Wyoming has proven technically challenging to drill and cement. This tight gas reservoir has over 5,000 ft of vertical pay interval in stacked lenticular sands. With pore pressures ranging from normal to over 16.5 lbm/gal, unplanned circulation losses were negatively impacting drilling and cementing operations. In early 2002, desired top of cement was being achieved on only 31% of the production casings. As a result, one of three things would occur: Stimulation treatments would not go to the intended zones, resulting in no production for completion dollars spent. As a result, petrophysical evaluations of entire intervals were being questioned.Costly remediation treatments had to be conducted during completion operations to isolate zones before they could be completed.Production reserves were at risk or deferred because of inadequate annular isolation.Completion engineers use fracturing applications to enhance well performance while drilling-induced fracturing is a problem to manage. In both disciplines, knowing fracturing and pore pressures is critically important. A process was developed to determine and calibrate pore pressures and minimum horizontal stresses for the design of hydraulic fracturing treatments and production prediction. Fracture extension pressure variation with depth was measured on each well completion. Mechanical rock properties were measured in the laboratory to validate calculations from openhole logs that were used in the fracturing simulator. The data was validated further by post-matching the simulator with fracturing treatment data. The question was asked, "Why not use this frac data to prevent drilling-induced fracturing?"Because of losses and wellbore stability issues, completion data from offset wells was incorporated into casing and mud programs. Underbalanced drilling techniques were also introduced which in turn created obvious problems for the cement design. Best practices were incorporated, including foam cement on a selected basis. As a result, cement tops are now reaching the desired heights 100% of the time. Even in cases where there has been no circulation when the cement job is started, desired cement tops have been achieved. As a result, costly remediation efforts have been eliminated saving an estimated U.S.$1.3 million/year. All the desired pay intervals are being isolated so that the decision to complete reservoir intervals is based on reservoir quality rather than mechanical issues with the wellbore. Production can now be attributed to given pay intervals with confidence aiding in proper evaluation of entire sections of the reservoir.
Curve Alignment for Well-to-Well Log Correlation
Authors: Zoraster Steven , Paruchuri Ramoj , Darby Steve 
Published: December 2007

AbstractThis paper presents a novel curve alignment program based on dynamic programming applied to well-to-well log correlation. The dynamic time warping (DTW) algorithm for data mining and signal processing is adapted to work on depth sampled well log data. Analytical tools to assist evaluation of curve alignment are provided. Our implementation can be described as automated, interactive, and constrained.Mathematical optimization - dynamic programming - provides the algorithmic, "automated" part of our solution to the well log correlation problem. "Interactive" means that the process is fast enough to be used interactively, and that it should be used iteratively, supplying visual and quantitative feedback to user identification of markers common to both wells. "Constrained" means that decisions by an educated user such as a geologist or a geophysicist, about depth ranges to which the algorithmic is applied is important, as are decisions about acceptance or rejection of particular results.The key to success has been display of pick selection mapped from posted depths in a "reference well" at depths on the "target" well, and the provision of interactive features so that the program be guided in the search for good problem solutions.
Application of a Lightweight Cement Slurry for the Naturally Fractured Mesa Verde Formations
Authors: Posey D. B. , Purvis D. L. 
Published: December 2007

Abstract
The Mesa Verde formation is highly naturally fractured and varies in depth from 5500 ft to 6200 ft. Low recoverable reserves make wells in this area marginally economical.
The lower hole is air drilled and cemented back to the intermediate at 3700 feet. Historically, the production casing has been cemented with a 50/50 Poz/H blend mixed at 13.2 ppg. Bond logs were often marginal and fall back was a problem.
This paper reviews the development of a lightweight cement system with the ability to develop high compressive strength to enhance the mechanical seal. This slurry needed to have plating lost circulation material (LCM) to prevent fall back and minimize node buildup due to high fluid loss. Compressive strength, fluid loss and rheological properties for various formulations are presented. The results of over forty jobs are summarized with operation and bond log results reviewed in detail from four typical wells.
A Numerical Model for Simulating Solid Waste Injection in Soft Rock Reservoirs
Authors: Chin L. Y. , Montgomery C. T. 
Published: December 2007

Abstract
This paper describes the development, validation, and application of a numerical model that simulates solids injection operations for soft rock reservoirs. There exist many classical fracturing models that are good tools for evaluating solids injection operations in formations with competent rocks. However, when evaluating solids injection operations in soft rock formations such as unconsolidated sand, these classical fracturing models generally fail to provide reliable evaluations. In this paper, a solids injection model was specifically formulated and developed for solids injection in soft rock formations. The development of the proposed model for soft rock formations is based on the Biot&#39;s self-consistent theory, plasticity theory, and fracturing and liquefaction criteria for rock. The predictive capability of the developed model was verified against field data from waste injection wells in soft rock formations. The validated model was used to evaluate solid waste disposal for cases of various injection operation conditions in a soft rock reservoir. Results show that the solids injection model provides an effective tool to assess the maximum injection volume allowed per well, the area of influence of injection, the bottom-hole injection pressure, and the vertical containment of the injected fluids and solids. Simulation results for representative cases are presented. The model can also be useful for quantitatively assist in identifying feasible solids injection mechanisms in soft rock reservoirs.
Determining Formation Resistivity Anisotropy in the Presence of Invasion
Authors: Barber Tom , Anderson Barbara , Abubakar Aria , Broussard Tracy , Chen Kuo-Chaing , Davydycheva Sophia , Druskin Vladimir , Habashy Tarek , Homan Dean , Minerbo Gerald , Rosthal Richard , Schlein Robert , Wang Hanming 
Published: December 2007

Abstract
Resistivity anisotropy in both laminated shale-sand and clean sand formations is well documented. Tools that are sensitive to formation anisotropy are also well documented, and the leading contender for this type of measurement is the transverse induction array. Such an array, whose transmitter generates formation currents in the plane of the borehole axis, has a good sensitivity to the vertical resistivity of the formation, Rv.
Invasion of mud filtrate into permeable formations has long complicated wireline log analysis. Interpretation of anisotropic formations will be no different. In most drilling environments, these formations will be invaded as readily as isotropic formations. Although we expect that invading mud filtrate from water-based mud will reduce the anisotropy, we also expect that invading oil-based mud (OBM) filtrate will increase it. Thus the anisotropic properties of each zone must be determined separately.
A single-spacing induction array (of any orientation) cannot, by itself, separate uninvaded zone properties from those of the invaded zone. Multiple-spacing tools have been used for many years to make this separation. A multiarray triaxial induction tool is in field test, and invasion interpretation algorithms are under development. A fast analytic algorithm corrects shoulder effect on all nine triaxial couplings of each array, allowing Rv and the horizontal resistivity Rh to be determined at several radial depths in the formation. Rigorous 2D and 3D inversions are also used to evaluate beds on the order of 1 m thick in both vertical and deviated wells. Examples in both modeled formations and in actual formations demonstrate the methods.
A New Approach to Improve Cuttings Transport in Horizontal and Inclined Wells
Authors: Yu Mengjiao , Melcher Daniel , Takach Nicholas , Miska Stefan Z. , Ahmed Ramadan 
Published: December 2007

Abstract
With increasing measured depths and horizontal displacements in extended reach (ERD) wells, good hole cleaning remains one of the major concerns in the oil and gas industry. While the methods currently used to increase cuttings transport capacity seek to increase the drag force applied to drilled cuttings, they are unable to significantly increase the cuttings transport capacity in horizontal and inclined wellbores because the gravitational force causes the cuttings to settle to the bottom side of the borehole.
The proposed technology works to counteract the gravitational force while simultaneously increasing the drag force by attaching gas bubbles to drilled cutting particles with chemical surfactants. The gas bubbles will pull the cuttings upward because of their buoyancy in the drilling mud thereby counteracting the gravity force. Furthermore, the gas bubble/cutting aggregation will have a larger surface area than the cutting alone, resulting in an increase in the drag force.
In addition to the theory behind this technology, this paper also focuses on laboratory development. Laboratory experiments were conducted to determine the effects of chemical surfactants, pH, and cutting particle size on the attachment of air bubbles to cutting particles. Two types of chemical surfactants, one to attach air bubbles to cutting particles and another to strengthen the air bubble, were necessary for attachment to occur. The corresponding chemical solution, with a pH range of 9 to 11, resulted in the optimal attachment of air bubbles to drilled cuttings up to 1.4mm in diameter that can be floated to the top of the fluid. Thereafter, experiments were conducted on a laboratory-scale flow loop with a horizontal test section. While conducting the flow loop experiments in the base solution without chemical surfactants, no cuttings were moved along the horizontal section. However, with the use of straight chain chemical surfactants up to 30% of the cuttings were carried completely across the horizontal tube by air bubbles and many other cuttings were carried partially across the horizontal tube. Further experiments showed that the use of certain branched chemical surfactants can greatly increase (about 58% of the cuttings were transported) the strength of attachment between air bubble and drilling cuttings compared to straight chain surfactants. These results show that this technology has the potential to make a "step-wise" improvement of cuttings transport capacity in horizontal and inclined wells.
Integration of Time-Lapse Seismic Data into a Flow Model Study of CO2 Injection into the Weyburn Field
Authors: Yamamoto Hirofumi , Fanchi John R. , Davis Tom L. 
Published: December 2007

Abstract
The Reservoir Characterization Project at the Colorado School of Mines has conducted a time-lapse seismic survey in a section of the Weyburn Field, Saskatchewan, Canada. The section is being subjected to a CO2 injection process that began in October 2000. The seismic monitoring process is of interest for both enhanced oil recovery and geologic carbon sequestration. This paper describes a study that integrated both static and dynamic data in a history matched (calibrated) model of CO2 injection performance. An objective function was used to quantify study results.
A Numerical Assessment of Modern Borehole NMR Interpretation Techniques
Authors: Toumelin Emmanuel , Torres-Verdin Carlos , Sun Boqin , Dunn Keh-Jim 
Published: December 2007

Abstract
Recent developments of two-dimensional (2D) NMR techniques have been advertised as efficient and accurate methods to interpret a variety of petrophysical parameters, including mixed fluid saturation, in-situ oil viscosity, wettability, and pore structure. No quantitative study, however, has been presented to precisely define the domains of application and practical limitations of such methods. We address this issue by introducing a general pore-scale framework to accurately simulate suites of NMR data in complex rock models. This general pore-scale framework is based on the novel combination of three models: (1) NMR random-walk model for multiphase fluid diffusion, T1 and T2 relaxations, (2) thermodynamically-based wettability model, and (3) saturation model based on imbibition history. Two-dimensional NMR inversion was used to interpret synthetic data sets for diverse petrophysical configurations including two-phase saturations with different oil grades, mixed wettability, carbonate pore heterogeneities, or clay-induced internal fields.
It is shown that T2/diffusion (D) maps are more reliable than T1/T2 maps for a variety of applications, including fluid typing without the need of independently determined cut-offs. It is also found that T2/D maps are more reliable than T1/T2 maps for heavy-oil and gas applications, even in the presence of substantial internal fields. A major failure of accurate fluid typing and pore structure estimation with NMR methods could be attributed to mixed-wettability states, which had never before been accurately considered in NMR interpretation studies. For the assessment of wettability, only that of light oil could be reliably interpreted from 2D NMR. No currently available 2D NMR method can be used to correctly diagnose substantial diffusion coupling in carbonate rocks.