bluuebunny/crossref_metadata_2025_split huggingface dataset:
Pompano Paraffin Calibration Field Trials
Authors: Kleinhans J. W. , Niesen V. G. , Brown T. S. 
Published: December 2007

Abstract
Models exist for predicting paraffin deposition in wellbore tubulars and flowlines. However, with increasing water depths and subsea offset distances approaching 15 - 30 miles and more, the need to properly design black oil, multiphase subsea systems for wax management is critical to successful project delivery. To increase the confidence level for using one of these theoretical models to predict paraffin deposition in a multiphase seabed line, the Pompano 4-1/2 mile subsea tie-back system was used to validate the theoretical model predictions. This paper describes the model and predictions, the field trials that were done to obtain comparison information, and the results. Field conditions required sequential modeling of six subsea wells that were each produced through a single line to the host Pompano Platform test separator. Multiphase fluids included a wide range of individual well oil, water and gas rates. The wax deposition modeling was done without knowledge of the related field paraffin cutting observations. Thus, the close agreement that was obtained between the predicted and observed paraffin deposition increased confidence level in the model results.
Compositional Simulation of Water-Alternating-Gas Processes
Authors: Christensen J. R. , Larse M. , Nicolaisen H. 
Published: December 2007

Abstract
In recent years several authors have demonstrated that relative permeability hysteresis effects may be significant in the physically correct modelling of general gas injection processes and WAG processes in particular. Today simple hysteresis models are available in most simulators, but more recent and advanced models are still not standard tools. Especially when compositional simulation is needed the choice of hysteresis models is generally limited to very simple models.
In this work we have combined a compositional simulator with a calculation method for relative permeabilities developed for Water Alternating Gas (WAG) injection (Ref. 1). The model can roughly be categorised as an extension of the well known Killough hysteresis model from two to three phases. Hysteresis behaviour is implemented for the water and gas phases (wetting and non-wetting phases). The residual oil saturation (intermediate phase) is dependent on the trapped gas saturation if the Stone1 method is used for calculation of relative permeabilities for the oil phase.
The paper describes a few simplifications made to the model and its implementation in a compositional simulator. Special attention is given to compositional effects such as solution of gas components in the oil phase. We then present simulation results showing the impact of the hysteresis model on oil production, first for a synthetic model (5th SPE comparative solution project), then for a real North Sea oil reservoir with WAG as primary recovery mechanism. The model is found to give a more physically correct description of three phase flow than exisiting hysteresis models and will be an enhanced tool for history matching and simulation of production forecasts.
Analysis of Measured Bottomhole Treating Pressures During Fracturing: Do Not Believe Those Calculated Bottomhole Pressures
Authors: Keck Richard G. , Reiter Doris F. , Lynch Keith W. , Upchurch Eric R. 
Published: December 2007

Abstract
This paper presents the analysis of measured bottom hole pressure data for 45 hydraulic fracture treatments pumped in Alaska and California in the past three years. On 30 of these wells, bottom hole data was obtained from memory gauges deployed on the tubing or in side-pocket mandrels, while the other 15 wells had reflected pressure up an open annulus. The fluid systems were either delayed borate guars, or linear gel HECs.
The paper starts with a comparison of these measurements with the Keck et al4 correlation. The results show that there are large systematic errors both in the magnitude and trends of the correlation. We illustrate the effects these errors have on net pressure analysis and on the success of executing these tip screen out treatments. The data also shows an unexpected transient effect in almost all the wells, whereby changes in surface pressure of 100’s to 1000’s of psi are found to change the bottom hole pressure by 10’s or 100’s of psi, respectively. We speculate on possible causes for this phenomenon, but conclude that additional work is needed for accurate predictions of bottom hole pressures during fracturing treatments.
Selecting Drilling Fluid Properties and Flow Rates for Effective Hole Cleaning in High-Angle and Horizontal Wells
Authors: Adari Rishi B. , Miska Stefan , Kuru Ergun , Bern Peter , Saasen Arild 
Published: December 2007

Abstract
This paper presents a method to determine optimum drilling fluid properties and flow rates to minimize cuttings bed height and circulation time in high angle and horizontal wells. The method uses empirical models relating the cuttings bed height and the bed erosion time to drilling fluid properties and flow rates.
Bed erosion tests have been conducted using a cuttings transport facility available at the University of Tulsa. Cuttings bed height as a function of time has been investigated by using variable flow rates (200 – 400 gpm) and four different drilling fluid compositions. Experimental results were used together with a non-linear regression analysis program to establish a functional relationship among drilling fluid properties, flow rate, cuttings bed height and the time required to circulate the borehole clean.
A numerical example is provided to explain the field application of the method. The sequential calculations involved in determining optimum combination of the Power Law viscosity parameters n and K, and the flow rate to minimize the cuttings bed height and circulation time are also given.
Field implementation of the proposed empirical correlations and the new method can aid optimization of circulation practices before tripping, and so reduce the associated risk of nonproductive time.
Overcoming Completion Challenges With Interventionless Devices - Case Study - The "Disappearing Plug"
Authors: Larimore David R. , Huggins Jeff , Lyngaas Kjell Harry , Robb Ewan , Bach Terje 
Published: December 2007

Abstract
The ongoing need for greater operational cost efficiency has encouraged oil companies to seek new methods that can simplify completion processes and reduce the number of required well interventions. This focus has resulted in new challenges for engineering/manufacturing and service companies to develop multi-functional equipment. To meet the challenges, a new generation of completion equipment with capabilities that would have been considered impossible ten years ago has been introduced to the oilfield. This equipment has been designed to not only reduce the number of interventions normally required in traditional completion scenarios but also to meet challenges of safety and reliability that can surpass the cost of contingency measures should the product fail.
The development of one such device, the "disappearing plug," which serves as a plugging device for setting a hydraulic-type packer, will be the focus of this paper. When run in with the completion, the tubing will fill automatically through an auto-fill device, and then, will close during one of the pressure cycles. The fluid-expendable plug material disintegrates on the last pressure cycle, which allows full-tubing-drift production and eliminates the need for a slickline or coiled-tubing run to retrieve a plugging device as would be the case with conventional methods.
While the industry average for successful installation of interventionless devices has still not reached the sought-after 100% reliability, when these concepts have been successful, the expected economic job goals have been surpassed. When successful in offshore, horizontal, and/or high angle wells where slickline or coiled tubing intervention after completion is significantly more costly, these interventionless technologies have proven to be even more beneficial.
The paper will discuss development of the plug, some of the failures that occurred, how these difficulties were addressed, and finally, will discuss several recently run installations. These clearly show the extent of the economic benefit that can be realized.
Disappearing plug technology currently improves economics by eliminating the need for slickline and coiled-tubing interventions in plugging operations. When setting hydraulic packers, this not only reduces operating costs but also the risks associated with interventions and plug failures. One of its most significant contributions, however, becomes apparent when considering the future trends of the industry — interventionless and intelligent well technologies. The disappearing plug will undoubtedly play an important role in the actualization of these future well trends.
Quality Control of NMR Logs
Authors: Stambaugh Brian , Svor Rick , Globe Mike 
Published: December 2007

Abstract
Nuclear Magnetic Resonance (NMR) Logging has gained widespread acceptance over the past decade. Those using NMR data need assurance regarding the quality of the data and the interpreted product. This is particularly true as NMR replaces other logging devices and is of paramount importance when NMR is run as a standalone service. NMR applications require proper job planning and acquisition for successful data processing, interpretation and integration with conventional logs. Quality control procedures are particularly important during data acquisition and during the creation of integrated computed products. This paper seeks to provide a reference for quality control of NMR data at acquisition and during subsequent interpretation. Examples are shown that demonstrate the importance of quality control related to data acquisition and processing. Quality assessment is divided into three areas; 1) Adherence to service company standards for calibration, tuning, and raw data quality. 2) Repeatability of NMR results. 3) Coherence of data with other available data. Respective of these three areas, some simple guidelines for quality assurance of NMR data and products are presented.
Gravel-Pack Isolation Squeeze for Plug-Down Recompletion
Authors: Fleming J. J. , Boyd S. R. , Wolverton D. M. 
Published: December 2007

Abstract
This paper presents a case history of a plug-down operation using a coiled tubing unit to perform a contaminated cement squeeze to seal a gravel-packed interval. This procedure maintained unrestricted tubing access, without milling, for wireline tools to perforate a lower bypassed zone of interest. A three-component or trimodal microcement-based slurry isolated the gravel pack and completion assembly. Standard cements, polymer gel systems, and conventional microcement slurries have not been shown to adequately address gravel-pack squeeze operations of this type. Incomplete placement and differential pressure during production are primary causes of failure. Furthermore, care must be taken during the coiled tubing contaminated squeeze procedure to minimize the risk of overdisplacing or contaminating the slurry once in place. This paper provides information to aid in the design and execution of gravel-pack squeeze operations, including water control treatments, zone abandonment, and through-tubing recompletions.
Permeability Estimation Using Hydraulic Flow Units in a Central Arabia Reservoir
Authors: Al-Ajmi Fahad A. , Aramco Saudi , Holditch Stephen A. 
Published: December 2007

Abstract
Knowledge of permeability is critical to developing an effective reservoir description. Permeability data can be obtained from well tests, cores or logs. Normally, using well log data to derive estimates of permeability is the lowest cost method. To estimate permeability, we can use values of porosity, pore size distribution, and water saturation from logging data and established correlations. One benefit of using wireline log data to estimate permeability is that it can provide a continuous permeability profile throughout a particular interval.
This paper will focus on the evaluation of formation permeability for a sandstone reservoir in Central Arabia from well log data using the concept of Hydraulic Flow Units (HFU). Cluster analysis is used to identify the hydraulic flow units. We have developed a new clustering technique that is unbiased and easy to apply. Moreover, a procedure for determining the optimal number of clusters that should be used in the HFU technique will be introduced. In this procedure, the sum of errors squared method was used as criterion for determining the required number of HFU’s to describe the reservoir.
In our work, the statistically derived hydraulic flow units were compared with the core description made at the well site by a geologist. The grain size classes from core description match very well with the statistically derived clusters from the HFU method. Our results indicate that hydraulic flow units correspond to different rock types in this Central Arabian Reservoir.
Of course, direct measurement of rock properties using cores is the ideal method to determine HFU’s. However, because the costs to cut and analyze cores are so high, few core measurements are routinely available. Hence, it is crucial to extend the flow unit determination to the un-cored intervals and wells. The relationship between core flow units and well log data was established by non-parametric regression in cored wells, and then was used as a tool to extend the flow units prediction to un-cored intervals and wells.
Permeability estimation using the HFU method was extended to un-cored wells by implementing the Alternating Conditional Expectation (ACE) algorithm. ACE provides a data-driven approach for identifying the functional forms for the well log variables involved in the correlation. The reservoir porosity vs. permeability relationship was represented with single equation by using the different HFU’s as indictor variables. Permeability profiles generated by HFU’s using well log data agree with core data.
A computer program was developed to perform hydraulic flow unit analysis. In the computer program, three main processing options were integrated, which are: sensitivity runs are made to determine the optimal number of HFU’s;the analysis is then based on the optimal number of HFU’s (or any user-defined number of HFU’s); andregression analysis is performed using the different HFU’s as dummy variables to predict values permeability.
Study of Refracturing Results in the Clinton Sand Formation
Authors: Greene Jack 
Published: December 2007

Abstract
Decline curves (production vs time) were drawn and evaluated in an effort to determine the results of restimulation work performed in the Silurian Clinton Sand Formation, east central Ohio area.
A total of seventy-one oil wells were hydraulically fractured between 1972 and 1975. Of these wells, seven had to be plugged and abandoned due to problems resulting from the restimulation work.
The average increase production due to restimulation was 4,000 bbls per well.

Introduction
This paper concerns itself with an evaluation of seventy-one oil wells restimulated by hydrofracing. The type of wells restimulated consisted of uncemented, shot wells, uncemented, fractured wells and cemented, fractured wells. The Oxford oil Company did this work between the years 1972 and 1975.
In this paper four case studies are used to evaluate the results by the different types of frac jobs. In selecting a particular well for case study examination, several factors must be considered. They are (1) volume of water injected; (2) type of completion; (3) type of initial stimulation; (4) past production history; and (5) geographic location. The wells in the case studies are classified according to the volume of water used in the restimulation.Less than 1,000 bbls1,000 bbls—2,500 bbls2,500 bbls—5,000 bbls5,000 bbls—10,000 bbls
Decline curves (production vs time) were drawn and analyzed to determine the ultimate recovery and economic limit of each reworked well.
For a successful rework, several factors must be completed.Clean out wellboreProtect casing against high pressure (if necessary)Increase fracture size and lengthWellbore must be clean before tubing run
Minas Surfactant Field Trial Tests Two Newly Designed Surfactants with High EOR Potential
Authors: Bou-Mikael Sami , Asmadi Faisal , Marwoto Danny , Cease Cedric 
Published: December 2007

Abstract
Caltex Pacific Indonesia (CPI) recognizes the enormous potential that a large scale tertiary enhanced oil recovery (EOR) project like Light Oil Steam Flood or Surfactant Flood can have on extending the operations in Minas oil field well into the 21st century. With 4.5 billion barrels of remaining target oil, a successful tertiary EOR process will have a significant economic impact on future operations. Tertiary projects are capital intensive and carry a high degree of risk, however, decision analysis (DA) studies for Minas indicate they have tremendous upside potential. In depth EOR screening identified two major processes for potential application in this high temperature, shallow reservoirs: Surfactant Flooding and Light Oil Steam Flooding. A successful Surfactant Field Trial in Minas will pave the way to potentially implement the process in several CPI fields in the Central Sumatra Basin.
The Minas Surfactant Field Trial is a unique project where two new low-cost surfactant systems, Lignin II and Synthetic Petroleum Sulfonate, have been specifically designed for Minas reservoir conditions. Lab tests indicated significant and comparable recovery from both systems in Berea and field cores. They are ready to be tested in the field for the first time.
Four different polymers, designed to provide a favorable mobility ratio in displacing the surfactant, will also be tested to select the most cost-effective system for Minas' high temperature environment. The purpose of the Field Trial is to validate the lab results, reduce the range of technical and economic uncertainties associated with recovery efficiency and field operations, and select the most cost-effective surfactant for field scale application.
The Surfactant Field Trial area is a 4.3 acre, 5-spot pattern utilizing 4 injectors and one central producer. Five sampling wells and four observation wells will be drilled to monitor the flood performance in both the A1 and A2 sands. The evaluation of flood results have been based on actual log and core data collected before, during and after surfactant injection. A reservoir simulation model will be used to history match production performance and to scale up the process for field wide performance predictions. The selected finite difference simulation package is equipped with surfactant and polymer options.
This paper will discuss both reservoir and facility aspects of the Surfactant Field Trial design and implementation. In the future, actual recovery efficiency of both surfactant systems will be reported and compared to performance predicted from laboratory test results & reservoir modeling.
Historically surfactant floods have not been viewed favorably due to their high cost & moderate recovery1. However, the low cost of production of Lignin II and Synthetic Petroleum Sulfonate may change the way we view surfactant flooding if their high recovery is proven in the field trial.
W.F. James No. 1 (Hunton-Arbuckle) Mills Ranch Field, Wheeler County, Texas
Authors: Leonard J.W. 
Published: December 2007

Abstract
The Mills Ranch (Hunton) Field was discovered in 1972, and a total of seven Hunton producers were drilled prior to spudding the producers were drilled prior to spudding the James No. 1 on 2-14-75. The James was drilled to 21,670' as a Hunton development well and deepened on 24,482' as an Arbuckle exploratory hole. The well reached total depth in December, 1975; 318 days after spudding. Drilling operations were reasonably trouble free except for a voluntary sidetrack that occurred at 22,308' while on a trip for a new bit at 24,092'. The well was completed as a dual gas producer with the Hunton potentialing for producer with the Hunton potentialing for 72,000 MCFD from perforations 20,747'-21,330' and the Arbuckle potentialing for 31,000 MCFD from perforations 22,918'-23,937'. Although at least one other well has produced from a greater depth, the James is believed to be the world's deepest commercial gas well. Drilling problems encountered in drilling later Arbuckle problems encountered in drilling later Arbuckle wells in the field are also discussed.

Introduction
The Mills Ranch Field is located in southeastern Wheeler County, Texas, in the Texas Panhandle and approximately five miles west of Panhandle and approximately five miles west of the Oklahoma state line (Fig. 1 and 2). Chevron U.S.A. Inc. is operator for the field and owns approximately 38% of the Hunton production and 43% of the Arbuckle production.
The field lies to the north and adjacent to the buried Amarillo Mountains but separated by large normal down-to-the basin (Anadarko) faults, which preserved the Pre Pennsylvanian sediments. Pennsylvanian sediments covered the down-faulted blocks with conglomerates, sands and granite washes as a result of erosion of the Amarillo Mountains. Wolfcamp sediments overlie the Pennsylvanian formations (Fig. 3). Overthrusting of the Pre Penn sediments in early Pennsylvanian time formed fault blocks which Pennsylvanian time formed fault blocks which were later buried by sediments. Accumulation of hydrocarbons migrating from the Anadarko Basin were trapped in the updip fault blocks. The Mills Ranch Field is an asymetrical northwest-southeast aligned structure, with the primary pay zones being the carbonate Hunton and Arbuckle formations.
The Mills Ranch (Hunton) Field was discovered in 1972, and a total of seven Hunton producers were drilled prior to the James No. 1 producers were drilled prior to the James No. 1 well. The Hunton producers are completed with a total depth of approximately 21,500'.