bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluating High-Angle Wells With Advanced Production-Logging Technology, North Slope Alaska
Authors: Schnorr DeWayne R. , Hupp Doug 
Published: December 2007

Abstract
High-angle wells with longer and longer departures are being drilled at an ever-increasing pace on the North Slope of Alaska. This type well is used to penetrate new oil reservoirs and increase oil recovery in older fields. These older oil fields are under waterflood and gas injection to maintain reservoir pressure, and the wells are producing oil with high water cuts and high gas-to-oil ratios. This is a very complex environment to evaluate with production logs.
To assist in these complex interpretations, data from a new production logging tool string are being used to determine the production profile when a high-angle well is producing oil with high water cut and high gas-to-oil ratios. This compact tool string directly measures water holdup distribution around the wellbore, phase velocity data and provides X-Y caliper information. All measurements can be acquired as close as 16 in. (40 cm) to the bottom of the tool. Sensors to acquire data on pressure, temperature, inclination, gamma ray and casing collar locator are included in the tool string. The measurements can be made in either telemetry or memory modes. The memory mode eliminates the need for electric line when logging horizontal wells, or wells that have high surface flowing pressures.
Sensors for sigma/porosity and carbon oxygen measurements can be combined with this logging string (when run on wireline), so that the production profile and the reservoir behind the casing can be evaluated on a single trip. The combined data from the production profile and the formation are then used to determine how to produce the well and manage the reservoir for maximum oil production and recovery.
Production profiles from three wells are used to demonstrate the value of these direct measurements and how they were used in remedial work to increase oil production and reduce or eliminate unwanted gas and water production.
Scale Management Through Laboratory Analysis and Wellbore Monitoring Surveys
Authors: Carbone C. Leandro , Fleming Niall , Spark Iain , Patey Ian 
Published: December 2007

Abstract
This paper highlights the role which laboratory analyses together with in-situ monitoring surveys have helped in the scale management programme for the Dunbar Field, a very water sensitive reservoir situated in the South-Central part of the Shetland Basin, block 3/14. The major formation damage mechanism in Dunbar is that on production, the mixing of separate formation and injection brines drops out a sulphate scale within the near wellbore and wellbore itself. In order to solve this problem, TOTAL in conjunction with COREX (UK) Ltd., Aberdeen designed a laboratory programme to best mimic field scale treatments under reservoir conditions. Two separate water based scale inhibitors were assessed to evaluate their compatibility within the reservoir and identify any damaging mechanisms, which could result from their squeeze application. The interpretation of the permeability data obtained from the coreflood tests was aided by X.R.D. (x-ray diffraction), dry and cryogenic S.E.M. (scanning electron microscopy) and thin section analyses to determine the nature of the formation damage mechanism(s).
The coreflood test results suggest that the major control on permeability impairment was the retention of a compound believed to be derived from the scale inhibitor which occurred as a thin film, hemispherical globules with a moderate wetting preference and/or irregular shaped globules with a high wetting preference. Retention of this substance reduced pore volume and narrowed pore throats, hence reducing permeability.
In conjunction with the laboratory testing wellbore monitoring surveys were undertaken. Production and caliper logging tools were run to gather wellbore data and to give an indication of any decrease in wellbore diameter with time through sulphate scale drop out. Wellhead pressure and topside sampling of the connate/injection water mixture was monitored to determine if any scale precipitation was occurring and of what type.
The evaluation of the laboratory data plus the information obtained from wellbore monitoring surveys were complemented by the more global recommendations issued by a task-force which includes, in particular, TOTAL's partner Elf Exploration UK PLC. It is on this basis that Total based its decision on the most suitable downhole scale management programme for the Dunbar Field.
Alternative Method for Stimulating Open Hole Horizontal Wellbores
Authors: Purvis D. L. , Smith D. D. , Walton D. L. 
Published: December 2007

Abstract
Drilling and completing horizontal wells has become an accepted method to connect natural fracture systems and increase the effective drainage radius. In the Madison formation of the Williston Basin, common practice is to complete the horizontal laterals as open hole. Production is through natural fracture swarms combined with tight matrix permeability. Without stimulation, production has often been disappointing from these wells. During the drilling of the horizontal interval, cuttings are ground into a fine powder. These fines combined with polishing and other horizontal drilling damage mechanisms plug the near wellbore porosity. The fines flow into and effectively plug the natural fracture systems. In order to maximize production rates, some treatment is necessary to remove or stimulate past this damage. This can best be achieved by creating multiple radial fractures or alternately connecting with and widening the natural fracture systems. Several methods have been utilized in the past to achieve this with varying degrees of success.
This paper examines a different approach to this problem. With this process, it is possible to create multiple radial fractures or connect to natural fracture systems in the most promising sections of the open hole. This is done with jointed tubing placement and the use of an oil soluble diverting medium to block acid from reaching previously treated intervals as well as other sections of the open hole. The use of divertor to channel acid combined with conventional tubing diameters allows achievement of significantly higher bottom hole stimulation pressures. The application of this process is presented along with case histories identifying the challenges and the results achieved to date.
Assessment of Foamed – Cement Slurries Using Conventional Cement Evaluation Logs and Improved Interpretation Methods
Authors: Frisch Gary J. , Graham William L. , Griffith James 
Published: December 2007

Abstract
Methods to evaluate conventional cements with logging data may not yield valid results in foamed cements. Logging tools commonly used in cement evaluation are the traditional cement bond log (CBL) tools and the modern ultrasonic scanning tools. CBL tools provide waveform images and acoustic amplitudes that together help describe cement-to-pipe and cement-to-formation bonding. Ultrasonic scanning tools contribute circumferential images and detailed information regarding the cement-to-pipe bond. The major problem in evaluating foamed cements is that their impedance values can be below that of annular fluids, such as mud or water. Thus, a standard interpretation of ultrasonic images and data in foamed cements may provide an incorrect diagnosis of the cement bond and could lead to unnecessary remedial cementing activities.
A new interpretation method expands and improves on previously published methods to effectively evaluate foamed cements with the common cement-evaluation tools. This method uses ultrasonic scanning data to provide detailed information regarding the cement-to-pipe bond and allows foamed cement to be distinguished from mud or spacer fluid behind casing. Cement-slurry weight and composition do not affect this technique. The technique does not require additional logging tools or passes and thus does not introduce additional logging or rig expenses.
Examples are presented showing that the new method is valid and is effective in both time and cost. These examples will illustrate several new ultrasonic cement-bond curves that were developed as a result of the new method and that, when used in conjunction with CBL amplitude data, improve foamed-cement evaluation. In the examples, the interpretation is focused to answer the basic question, "Should remedial cementing be performed, or should the well be perforated for production?"
Acoustic Method for Determining the Static Gel Strength of Slurries
Authors: Moon Jeff , Wang Steven 
Published: December 2007

Abstract
Complex chemical reactions are occurring within a cement matrix as it becomes a solid. During the initial phase of the cement hydration, the cement exhibits polymer characteristics that exhibit a shear yield point that has been described as "static gel strength" (SGS). Due to this behavior, the cement slurry develops SGS after it has been pumped downhole. The start of gel strength development signals the point at which the cement slurry begins to change from a true hydraulic fluid that transmits full hydrostatic pressure to a solid material that has measurable compressive strength. The cement gel strength is important for two reasons:
The static gel strength development determines the shut down safety factor on the job. If the cement slurry is stopped prior to placement, then the static gel strength allows the calculation of the pressure required to restart circulation. The static gel strength affects the hydrostatic pressure distribution and the flow of gas or water into the cement filled annulus, known as fluid or gas migration.
This paper describes the discovery that as some slurries develop static gel strength, the attenuation of a high frequency acoustic signal transmitted through the slurry decreases. This change in amplitude correlates with the actual static gel strength of the slurry.
An acoustic method and system for determining the static gel strength of a cement slurry sample has been developed that provides nearly continuous, accurate, non-mechanical measurements of the static gel strength of cement slurry samples. The measurements are made at wellbore temperatures and pressures up to 400°F, 20000 psig.
Vacuum Jacketed Tubing: Past, Present, and Future
Authors: Bunton Mark A. 
Published: December 2007

Abstract
Vacuum jacketed tubing has been used for many years in steam flood EOR applications and protection of permafrost. The product more recently has been applied to production tubing for hydrate and paraffin prevention. The paper will discuss case histories and economics of the various past uses of vacuum jacketed pipe along with potential new applications such as vacuum jacketed pipelines. We believe that the superior insulating ability of vacuum jacketed tubing could be an integral part of the rejuvenation of Alaska's oil production in both steam flood and production tubing applications.
Use of Pressure Activated Sealants to Cure Sources of Casing Pressure
Authors: Rusch David W. , Ellis Barry C. 
Published: December 2007

Abstract
Pressure leaks in a wellhead or in downhole tubulars or equipment can lead to inoperable subsurface safety valves, casing pressure, environmental pollution, loss of production and, in extreme cases, blowouts. As such, it is essential to the safe and environmentally sound operation of a well that the sources of the pressure leaks be identified and cured. Use of a new and unique pressure activated sealant technology allows utilization of a method of repairing wellhead and downhole leaks in-situ without employing any mechanical downhole operations. Only at the point of differential pressure, through the leak site, will the sealant reaction occur and create a bond across the leak. Use of the pressure activated sealant technology obviates the need to employ expensive and risky rig or wireline operations to cure downhole leaks.
Outstanding Economic Advantages Based on New Straight-Hole Drilling Device Proven in Various Oilfield Locations
Authors: Calderoni A. , Savini A. , Treviranus J. , Oppelt J. 
Published: December 2007

Abstract
Tremendous savings in drilling investment have been made possible through application of a new drilling concept and directional system. The Straighthole Drilling Device (SDD) has migrated from an experimental system into a mature tool, which is now used to a major economic advantage in different places of the world. At first sight this device's advantage seems to be mainly the ability to drill a borehole into the ground with a vertical trajectory. However soon after the earliest applications in a commercial environment it became obvious, that this new kind of directional tool allows in fact to revolutionize the way of drilling.
Much beyond the mere benefits of a straight and geometrically exact borehole shape, SDD technology actually offers the opportunity to completely re-configure the well trajectory. The final result of this are considerable savings in time and investment to arrive to well production. According to the current knowledge base, the SDD is also be extremely helpful in locations, were the formation has a natural tendency to build up hole inclination.
SDD has been used in several different hole sizes, there providing a higher penetration rate, and a very smooth and precise hole trajectory. This in turn allows to drill wells in a cluster approach, and to apply the lean casing concept. Also curved sections in the lower part of the hole do considerably gain with respect to lower friction in the drill string to borehole wall contact. Finally, a considerable positive environmental impact is associated with this technique, in terms of reduction of waste disposals at about 30% in volume, compared to a standard well profile.
Basically the SDD comprises a positive displacement motor section, a control sub having electronic and hydraulic means, and a bearing assembly equipped with selectively expandable stabilizer pads. The system does autonomously drill a straight, vertical hole, where no surface human interaction is required. Whenever the directional sensors detect any small deviation from the vertical, one or more of the ribs will be activated in a closed loop circuit. Standard mud pulse transmission allows to monitor the down hole operation.
SDD was originally developed for the German Scientific Ultra-Deep Well (KTB), but later on turned out to be of considerable advantage for major oil and gas fields in Italy. SDD has so far seen it's most utilization in South of Italy, which is the center of Italy's onshore oil and gas exploration. Meanwhile additional application has occurred in other places around the Mediterranean Sea. A considerable interest has recently developed within several drilling areas in South America.
Wet Crude Transport through a Complex Hilly Terrain Pipeline Network
Authors: Alvarez Carlos J. , Al-Awwami Mofeed H. 
Published: December 2007

Abstract
This paper discusses the results of steady-state and transient flow simulators utilized in the design, operation, and troubleshooting of a complex multiphase pipeline network in a Saudi Arabian oilfield. The oilfield pipelines pass across a hilly terrain with sand dunes rising up to 200 meters, transporting wet crude from wells located on sabkhas (flat terrain) to three Gas Oil Separation Plants (GOSP). State-of-the-art transient multiphase flow model performance was also evaluated using pipeline slug flow tests measurements.
The results of various steady-state algorithms used for pressure drop and free-flow calculations in the Field's pipelines were found inaccurate and inconsistent. A comparison of these calculations and Field data demonstrates that they should not be used for predicting pressure drop, sizing multiphase pipelines, or designing production facilities over hilly terrain. Transient multiphase models can more accurately predict pipeline pressure drop, and optimize pipeline size. A transient multiphase model was used for simulating trunkline valves for slug flow control. Based on simulation results, plug valves were installed near trunkline outlets. The valves were found to be useful in mitigating effects of slugs into the receiving separators, thus eliminating the need for installing costly slug-catchers. Different free-flow alternatives, and crude pumping for transferring wet crude from satellite GOSP's to the Central Processing Facility (CPF) were examined. Crude pumping was found the most suitable and economical option due to large pipeline pressure drop resulting from slugs.
Transient multiphase flow continues to be highly complex. Its effects are hard to predict accurately. Pipeline pressure drop results from simulations using the latest commercially available flow models were about 20-30 % lower than Field measured values.
Two-Phase Well Test Analysis of Gas Condensate Reservoirs
Authors: Xu Shaosong , Lee W. John 
Published: December 2007

Abstract
This paper proposes a new method to interpret transient pressure data from gas condensate reservoirs. Our method models two-phase gas-condensate flow in the reservoir using traditonal solutions to flow equations for single-phase, slightly compressible liquid flow by employing a pseudopressure function and fluid properties derived from conventional laboratory experiments.
The method is especially useful for well test analysis when reservoir pressure is near or below the dewpoint, where existing methods fail. Their assumption of steady-state flow yields a relation between reservoir condensate saturation and pressure that is not valid at these low pressures.
In this paper, we show that an accurate relation between reservoir condensate saturation and pressure can be computed from the assumption of a three-zone radial model, in which steady-state fluid flow is assumed in the first zone, the condensate is immobile in the second zone, and only the gas phase exists in the third zone. (Whether the third zone exists or not is determined by reservoir average pressure.) The second zone becomes increasingly important at lower pressures.
The essential problem in multiphase well test analysis is to establish the correct relationship between saturation and pressure needed to calculate pseudopressure. We verified our calculated relationship between reservoir condensate oil saturation and pressure by comparing our analytical results to results generated by compositional simulation. The comparison also showed that our proposed relationship between reservoir condensate saturation and pressure leads to accurate test interpretations and is much more satisfactory than previous methods.
Once the correct relation between reservoir condensate oil saturation and pressure is obtained, our method can compute and correlate pseudopressure with either producing or shut-in time. Sensitivity studies for various reservoir and fluid conditions support our conclusions under a wide variety of conditions.
Our test interpretation method provides good estimates of reservoir permeability and initial reservoir pressure. Mechanical skin is usually overestimated, but only modestly (typically about one unit of skin).
Our method requires lab constant volume depletion (CVD) data, gas and condensate oil relative permeability, and producing GOR in addition to transient pressure data. The effects of non-Darcy flow, wellbore storage, and capillary number-dependent relative permeability are not considered. The production wells are fully penetrated.
Analysis and Interpretation of Well Test Performance at Arun Field, Indonesia
Authors: Marhaendrajana T. , Kaczorowski N. J. , Blasingame T. A. 
Published: December 2007

Abstract
This paper presents a comprehensive field case history of the analysis and interpretation of all of the available well test data from the giant Arun Gas Field (Sumatra, Indonesia). Arun Field has estimated recoverable reserves on the order of 18-20 TCF and has 110 wells—78 producers, 11 injectors, 4 observation wells, and 17 abandoned. Approximately 100 well tests have been performed, and the analysis and interpretation of these data suggests strong existence of condensate accumulation near the wellbore as well as a "regional pressure decline" effect caused by competing production wells.
We demonstrate and discuss the analysis/interpretation techniques for wells that exhibit condensate banking and non-Darcy flow. We found that the 2-zone radial composite reservoir model is effective for diagnosing the effects of condensate banking at Arun Field.
We also demonstrate the development and application of a new solution for the analysis and interpretation for wells that exhibit "well interference" effects. Our new solution treats the "interference effect" as a regional pressure decline and this proposed solution accurately represents the well interference effects observed in many of the well tests obtained at Arun Field. Furthermore, this solution is shown to provide a much better interpretation of well test data from a multiwell reservoir system than the existing approaches–i.e., assumption of no-flow or constant pressure boundaries, data truncation, etc.
Delineation of Hydrodynamic/Geodynamic Trapped Oil in Low Permeability Chalk
Authors: Jacobsen Nils L. , Engstrøm Finn , Uldall A. , Petersen Niels W. 
Published: December 2007

Abstract
The present paper describes the basis for delineating a significant volume of non-structurally trapped oil within low permeable chalk at the flank of the mature Dan field offshore Denmark. Drilling of extensive long horizontal wells at the flank of the main field, including one that set a world record horizontal section, has resulted in the discovery of a thin high porous (&gt;30%) Maastrichtian chalk unit. The best reservoir zone is developed with consistent high oil saturation in the order of 80-90%, and trapped between lower porosity predominantly water bearing Danian and Maastrichtian Chalk units.
Full vertical and lateral pressure continuity is observed between the hydrocarbon and water bearing units on the main field. It was therefore surprising to find the oil in the better of the units extending down flank, and outside the structural closure far beyond what could be predicted from modeling of the saturation profiles observed in the crestal wells. Drilling of three wells with up to 19,600 ft long horizontal sections in the flank area, consistently found the free water level dipping and deepening significantly to the north-west of the field allowing hydrocarbon filling of the units of highest reservoir quality in this area.
Drilling of long reach horizontal wells thus provided the data needed for regional mapping of the free water level required as input to fluid modeling. Information on layer thickness and matrix porosity, necessary for volumetric calculations, was provided from well logs and through stochastic forward modeling of seismic acoustic impedance data extracted from a regional 3D survey.
Improved understanding of the hydro- and geodynamic induced fluid pattern, combined with seismic mapping and modeling, thus resulted in the identification of significant and yet un-drained volumes at the flanks of a mature oil field.