bluuebunny/crossref_metadata_2025_split huggingface dataset:
Utilizing Flowing Pressure-Transient and Mass-Balance Analysis of SENM Morrow Producers To Calibrate 3D Hydraulic-Fracture Modeling – A Case History
Authors: Walser D. W. 
Published: December 2007

Abstract
Sizing of hydraulic fracturing treatments in the Southeastern New Mexico (SENM) Morrow has historically relied on a trial-and error process whereby a three-dimensional fracturing model was built and run with simple gamma ray and compensated neutron density logs.Stress tables have been built utilizing over-simplified correlations involving conversions from gamma ray readings and effective porosity.The resulting simulated fracture-half lengths have been utilized in NPV (Net Present Value) optimizations to arrive at a final sizing decision.
Unfortunately, this process relies on the assumption that the initial modeling generates a propped fracture geometry simulation that is realistic.Past efforts to calibrate the 3-D models in the area focused on scattered attempts to gather sonic data that could be converted to stress differentials, and the use of conventional pressure buildups before and after the treatment.While the measurement of sonic properties during open-hole logging operations assisted somewhat in calculating relative stress differentials, its application was sporadic at best, and there was no way to check the results. Pre and post-stimulation pressure buildups required shutting the well in for a period of time and subsequently risking potential deceleration of reserve recovery.
A study of a variety of existing Morrow producers was undertaken to determine whether or not flowing pressure transient analysis of existing properties could be utilized to "calibrate" three-dimensional fracturing models, so that future projects would better reflect fracture geometries that were more realistic than current practice.
Results of the study are presented, and a practical, user-friendly model is demonstrated whereby flowing transient analysis may be utilized to adjust three-dimensional fracturing simulations as appropriate for optimizing stimulation NPV.
A Review of Horizontal-Wellbore Pressure Equations
Authors: Anklam E. G. , Wiggins M. L. 
Published: December 2007

Abstract
The objective of this paper is to review the current methods of determining how the effects of wellbore hydraulics are incorporated into the evaluation of the productivity of a horizontal well.Wellbore hydraulics includes the effects of friction, acceleration, gravity, and fluid influx.Knowledge of the pressure distribution within the horizontal wellbore is important to more accurately determine the performance of the horizontal well and aides in the design of the well profile, completion, and stimulation.
Wave Equation Simulation of Fluid Pound and Gas Interference
Authors: Yavuz F. , Lea J. F. , Garg D. , Oetama T. , Cox J. , Nickens H. 
Published: December 2007

Abstract
Using adiabatic compression of gas in the pump, a model is shown that can be used to calculate the down-hole pump dynamometer card for various degrees of pump fill of liquids and gas at various degrees of pressure. The load release portion of the card is emphasized. It is shown how the lower pressure gas in the pump promotes what is commonly termed fluid pound or slap and higher pressure gas in the pump promotes what is termed gas interference.
The equations that are needed to model these effects for inclusion into wave equation pump models are presented and example calculated pump cards are shown, calculated from wave equation simulations. Since even with so-called fluid pound, gas is first compressed before the plunger encounters the mostly incompressible fluid in the pump, the traveling valve always encounters compressed gas sufficient to open the valve before the plunger "hits" the fluid. This is true as long as gas is in the barrel when incomplete fluid fill occurs. Given this fact, the time step in wave equation solution is examined as the load release in the so called "fluid pound" can happen over a very short time and longer time steps in the wave equation simulation could mask forces from short term forces.
The effects of rapid load release on forces in the rods are studied vs. what the forces might be due to the commonly supposed forces from impact with the fluid when "fluid pound" is modeled. Other parameters such as pump fillage, intake pressure and sinker bars are examined for their effects on calculated rod compression
A Coupled Model for Analyzing Transient Pressure Behavior of Horizontal Drainholes
Authors: Ogunsanya B. O. , Oetama T. P. , Lea J. F. , Heinze L. R. , Adisoemarta P. S. 
Published: December 2007

AbstractConventional horizontal well transient response models are generally based on the line source approximation of the partially penetrating vertical fracture solution1. These models have three major limitations: (i) wellbore pressure is computed at a finite radius outside the source; it is impossible to compute wellbore pressure within the source, (ii) it is difficult to conduct a realistic comparison between horizontal well and vertical fracture productivities, because wellbore pressures are not computed at the same point, and (iii) the line source approximation may not be adequate for reservoirs with thin pay zones. This work attempts to overcome these limitations by developing a more flexible analytical solution using the solid bar approximation. A technique that permits the conversion of the pressure response of any horizontal well system into a physically equivalent vertical fracture response is also presented.A new type curve solution is developed for a horizontal well producing from a solid bar source in an infinite-acting reservoir by means of Newman's product solution2. Analysis of computed wellbore pressures reveals that error ranging from 5 to 20% was introduced by the line source assumption depending on the value of dimensionless radius (rwD). Computations show that for rwD ≤ 10-4 the transient response of a horizontal well is identical to that of a partially penetrating vertical fracture system, and for rwD &gt; 0.01 the transient response of a horizontal well is indistinguishable from that of a horizontal fracture system. Type-curve plots for the ranges 0.01 ≤ dimensionless length (LD) ≤ 10, and 10-4 ≤ rwD ≤ 1.0 are presented.A dimensionless rate function (β -function) is introduced to convert the transient-response of a horizontal well into an equivalent vertical fracture response. A step-wise algorithm for the computation of β -function is developed using Duhamel's principle. This provides an easier way of representing horizontal wells in numerical reservoir simulation without the rigor of employing complex formulations for the computation of effective well block radius.
Dewatering of Hunton Reservoir: What Makes It Work?
Authors: Gupta M. , Joshi R. , Kelkar M. 
Published: December 2007

Proposal
Hunton Reservoir in Oklahoma represents one of the largest discoveries in Oklahoma in recent history.Since 1995, several fields in Hunton Reservoir have been exploited by various operators.The principle behind this exploitation remains the same.The wells produce large quantities of water, and along with it, significant quantities of gas, and sometimes, oil.Examination of various fields producing from Hunton reservoir indicates that the economic success from these fields is not uniform.Some fields produce significant quantities of oil, whereas, some fields only produce gas.In some fields, horizontal wells work the best, whereas, in some other fields, vertical wells do a good job.The water production from the fields ranges from as low as few hundred barrels per day to several thousands of barrels per day.
In this paper, we present the results from various fields to indicate the parameters needed in Hunton field to make it economically successful.We restrict our evaluation to parameters which can be easily measured or are readily available.These include log data (gamma ray, resistivity, neutron and density), initial potential data, production data (oil, gas, and water – if available) and well configuration (vertical or horizontal).By comparing the recovery of oil and gas to various reservoir parameters, we develop methodology for predicting the future success of the field.For example, a clear relationship exists between porosity of the rock and initial hydrocarbon saturation.Higher the oil saturation better is the recovery factor. Initial potential is critical in determining the possible recovery.Horizontal wells cost 1.5 to 2 times more than vertical wells, but may not provide the additional recovery to justify the costs.
Hunton formation is extensive in Oklahoma.If we want to extend the success of some of the fields to other areas, we need clear guidelines in terms what is needed to exploit those fields.This paper provides some of those guidelines based on the examination of the currently producing fields.
Air Compliance in the U.S.: A Systematic Guide for E&P Service Companies to Evaluate, Establish, and Ensure Ongoing Compliance
Authors: Carley J. , Malmquist K. , Davison W. , VanAllan P. 
Published: December 2007

Abstract
This paper discusses the complexities that E&P service companies face in the U.S. as they manage their air compliance program for their base facilities, wellsite operations, and transportation fleets while tackling the enormous amount of federal, state, county, and local air regulations. Examples of point sources (e.g., chemical blending facilities), pollution-control devices (e.g., dust collectors), and fugitive emissions (e.g., cutting sacks of dry chemicals) found within the oilfield services sector are presented, and discussions of air permit or permit exemption requirements are included for each example.
This paper is intended to share best practices for establishing and maintaining an air compliance program, including the tools (e.g., compliance matrix) and systematic techniques for managing air compliance. These practices have application across state boundaries, regardless of the site location. The compliance program includes: 1) determining if a site(s) is currently in compliance with applicable air regulations, permits or permit exemptions, including aspects related to preplanning and scope, whom to involve, audit privilege, and disclosure; 2) bringing a site into compliance once nonconformances have been identified, 3) maintaining compliance even if operational changes such as human factors, equipment, chemicals, or new construction occur, and 4) implementing operational controls to ensure compliance with continual regulatory changes.
An Innovative Way of Integrating Reliability of Intelligent Well Completion Systems with Reservoir Modeling
Authors: Ajayi A. , Mathieson D. , Konopczynski M. 
Published: December 2007

Abstract
When simulating the performance of intelligent well systems, the reliability aspect of the installed components is often ignored. In some cases, the components are assumed to be fully functional throughout the simulated life of the well or asset. However, for some assets, component reliability within the active period is a critical part of the overall intelligent well decision making process. This dictates whether or not the system delivers the promised value.
This paper describes a method of evaluating and quantifying the reliability of intelligent well systems based on historical data, installed components and number of zones. It then provides an approach for integrating the estimated reliability data with well performance in reservoir simulation. This integration enables the reservoir engineer to assess the time- dependent impact of the success/failure of the system on the estimated value of using the technology.
The authors presented an application of the proposed methodology to a 2-zone intelligent well system. The analysis was used to identify the downhole valve's active period and thereafter recommend a system with robust reliability data that will ensure that estimated potential value from the technology is realized. The analysis also provided insight into the impact of system failure on well recovery at different time periods.
Field-Trial Results for Produced-Water Polishing with New Vertical Units Utilizing Low Centrifugal Forces and Induced Gas Flotation for Compliance During Produced-Water Operations
Authors: Bridson L. , Darlington J. W. , Smith J. J. , Occhipinti J. 
Published: December 2007

Abstract
During crude oil production, a significant amount of water is co-produced. This produced water is the largest volume waste stream in oil production, with an estimated 670 million tons of produced water generated worldwide during 2002(1). Typically, a new operational field produces relatively minor amounts of water, i.e. 0-20%, of the total production. As the field ages, the water volume can increase to over 90% of the production. The offshore production facilities primarily treat oil/water mixtures by adding chemical agents to assist the mechanical separation of the fluids. The produced water is usually discharged after separation of as much of the oil and other organics as possible with current technology. At the point of discharge, typical produced waters contain oil & grease contributors at 10-40 ppm. The organic contaminants in the produced water are of increasing concern throughout the world due to their potential harmful effects on the environment.
The conventional mechanical separation devices used on the oil producing platforms can be placed in two groupings. The first grouping is high centrifugal force separators and typical examples are hydrocyclones and centrifuges. The primary advantage of this grouping is that these devices can separate large amounts of oil from water. The primary disadvantages are that these devices have difficulty with changing flowrates, changing oil in water concentration, and create small micron oil droplets by their shear forces. The second grouping is composed of polishing units and examples are horizontal dissolved gas floatation. The primary advantages of this grouping are the ability to obtain very low ppm oil in water discharge. The primary disadvantages of the horizontal dissolved gas floatation devices are the footprint requirements, changing oil concentration influent, and susceptibility to wave motion. Secondary disadvantages include the frequent requirement for routine and continuous additional chemical injection, usually water clarifiers/deoilers presenting extra operational cost and potential for increased environmental impact.
In order to overcome the disadvantages to the traditional mechanical separation devices currently utilized on oil and gas producing platforms, CETCO has developed a new vertical cyclonic separator, trademarked CrudeSep® that combines the best attributes of cyclonic separation and induced gas floatation to generate a small footprint and efficient oil and water separation. This paper will discuss the separator design and give examples of how this CrudeSep® separator can replace conventional centrifuges, hydro cyclones, horizontal dissolved gas floatation devices and degassers.
Impact of Heat Aging on Sediment Toxicity of Ester/Olefin Based Drilling Muds to Leptocheirus plumulosus
Authors: Cano M. L. , Rabke S. , Candler J. , Dorn P. B. , Louallen J. T. , Scott P. 
Published: December 2007

Abstract
Synthetic-based drilling fluids (SBF) have been used in a variety of drilling applications and are an important component of deepwater drilling operations. One of the applications of SBF is high-temperature wells. In order to address regulatory concerns about SBF in high temperature applications, an inter-industry study was conducted to examine the effects of temperature and time on the sediment toxicity (to Leptocheirus plumulosus) of synthetic-based fluids used for high-temperature wells. Four factors were examined: (1) ester content, (2) time, (3) temperature, and (4) alkalinity (absence or presence of green cement). Three base-stock fluids were tested, a 100% internal olefin (C1618 IO) and two traditional ester/olefin blends (10%/90% and 30%/70%). The base fluids were blended into drilling fluids and subjected to temperatures ranging from 275 to 350°F and time of exposures to temperature ranging from 16 to 160 hr.
Phase 1 toxicity results indicated that temperature and time parameters bracketed the region where ester/olefin drilling fluids transitioned from passing to failing the sediment toxicity limitation. Phase 2 used a statistical experimental design to identify significant factors impacting toxicity, and a statistical model was developed to predict sediment toxicity ratios (STR). 2-Ethyl hexanol, an indicator of ester hydrolysis, was positively correlated with increased STR and could be used to screen for potential sediment toxicity. The sediment toxicity tests, analytical measurements, and the statistical STR model supported the hypothesis that, for the types of muds studied, toxicity increased for ester/olefin blends under downhole conditions of increased time and temperature. The data from this study support caution in the use of drilling fluids containing the type of esters (traditional esters) used in this study when temperatures exceed a threshold of ~300°F. Above 300°F, these materials may break down and result in increased sediment toxicity for the drilling fluids.
Baselining and Reducing Air Emissions from an Offshore Drilling Contractor’s Perspective
Authors: Cadigan M. , Peyton K. 
Published: December 2007

Abstract
In recent years, global climate change and local air quality have become some of the most pressing environmental concerns. These concerns have led to collaborative international efforts to reduce the concentration of greenhouse gases and criteria pollutants. Greenhouse gases include carbon dioxide (CO2), methane (CH4) and nitrous oxide (N2O) that occur naturally and as the result of human activity. Criteria pollutants include emissions of nitrogen oxide, sulfur dioxide, carbon monoxide, and total unburned hydrocarbons. Drilling contractors can play an important role in environmental stewardship by reporting carbon emissions from drilling operations, eliminating redundant emission measurements, and leading the industry in efforts to reduce these emissions.
Noble Corporation is proactively pursuing methods to manage and reduce greenhouse gases and criteria pollutant emissions, improve diesel engine efficiency, and reduce diesel consumption as a means of lowering emissions. This paper presents Noble’s current environmental initiatives and successes to date, including:The completion of a three-year base line inventory of greenhouse gas emissions from its drilling units worldwide—a first in the drilling industryVoluntary participation in the EPA Climate Leaders program, a greenhouse gas emissions monitoring and reduction programNoble’s strategy for setting targets for reducing the amount of greenhouse gases produced by its offshore drilling operations and improving diesel engine efficiency through new diesel-injection technologyImplementation of a new rig-engine efficiency program, which has led to the reduction of nitrogen oxide (NOx) emissions by 30% and fuel consumption of 2%, a cost reduction that will amount to an average of $5,000/year for each engine.
To establish a base line of greenhouse gas emissions, Noble used ChevronTexaco’s SANGEA™ Emissions Monitoring Software and equipment specifications to calculate greenhouse gas emissions retroactively and establish methods to measure greenhouse gas emissions going forward. In addition, Noble is measuring the output of criteria pollutants using Continuous Emissions Monitoring System (CEMS) technology and is evaluating the performance and durability of the technology in harsh offshore conditions, with the ultimate goal of installing gas analyzers on all of its offshore assets.
Reducing its fuel consumption not only reduces emissions of greenhouse gases and other pollutants, it promotes a cleaner workplace and allows Noble to pass along fuel cost savings to its customers.
Recent Advances in Fault Seal Analysis as an Aid to Reservoir Characterisation and Production Simulation Modelling
Authors: Fisher Q. J. 
Published: December 2007

Abstract
It is still common practice to adjust transmissibility multipliers of faults within production simulation models to achieve a history match without establishing whether or not the values are physically reasonable. Analysis of the permeability and threshold pressure of numerous (&gt;2000) fault rocks from cores has provided a detailed understanding of the controls on fault rock properties, which now allows one to establish whether transmissibility multipliers incorporated into simulation models are physically realistic. Fault transmissibility multipliers within many simulation models that we have studied have proven to be far lower than core measurements suggest are reasonable. In effect the faults are being made ‘scapegoats’ to compensate for inadequacies in the physical description of the reservoir within the simulation model. The recognition of these discrepancies is, however, valuable and indicates that further characterization is required to understand the flow behavior of the reservoir.
The multiphase flow properties of faults are very rarely taken into account during simulation modeling. Theoretical, anecdotal, as well as the results from history matching of simulation models, suggests that considering the multiphase flow properties of faults could lead to better day-to-day and long term decision making. In other situations, it may not be necessary to consider the capillary pressure characteristics of faults. We therefore recommend that, prior to full field simulation modeling, simple models are constructed in which the capillary pressure and relative permeability characteristics of fault are included using a local grid refinement so that the importance of multiphase flow across the faults can be established.
Integrated Petrophysical Approach Fast-tracks Development and Results From a Heavy-Oil Reservoir in Trinidad
Authors: Sinanan B. 
Published: December 2007

Abstract
In planning EOR projects, teams must use all available and affordable resources to optimize results and economize on design. EOR projects are capital intensive and hence modeling the reservoir is of paramount importance before simulation and forecasting begins. Unavailability of seismic data must be substituted by core and log data to prove sand continuity, structure and stratigraphy. The conventional practice of mapping sand facies is important for depositional understanding but for EOR projects it is the flood designer's interest to have flow units mapped.
This paper incorporates an existing method, used and proven, early in the life of a wide array of reservoirs, together with revised and new concepts in conducting analysis on shallow heavy oil reservoirs. The use of the core data, log data, Winland35 equation, together with Stratigraphic Modified Lorenz plots have reduced uncertainties and have introduced more confidence in forecasting. The end products are flow units with assigned reservoir properties, to be used in simulation and smarter field development.