bluuebunny/crossref_metadata_2025_split huggingface dataset:
Qualification Testing Towards Utilizing an In Well Flow Meter for Production Optimization and Allocation in Nigeria
Authors: Ong J. Tim , Meinert David , Oyewole Anthony , Blowers Michael , Thomson Russell 
Published: October 2009

Abstract
The Agbami project offshore Nigeria uses a suite of production monitoring, control and optimization tools and techniques. The project uses an intelligent well completion whereby production and injection is optimized from the well through the relevant time feedback of information from downhole pressure, temperature gauges and flow meters. A downhole interval control valve provides the capability to control production and injection, thus maximizing the recovery of hydrocarbon from the field.
The field consists of both injection and production wells. Oil production is from multiple zones, which are co-produced into the wellbore. Due to the complexities of the subsea production and injection manifold and riser configurations, downhole flow meters are used for production and injection allocation purposes for the different formations within the reservoir.
Agbami Field utilizes an in-well flow meter. The technology is based on a differential pressure full bore electronic flow meter which is first in the industry. The sensors utilized are high resolution pressure and temperature sensors. In order to demonstrate the robustness and the capability of the flow meter for production and injection allocation purposes, a series of flow loop qualification testing have been designed. One of the tests used a mixture of oil and water in a test facility to demonstrate the capability of the flow meter to accurately measure oil and water production. This test is probably the first of its kind using a test structure over 100 ft in height.
The paper will outline the aims, the preparation requirements, the conducted test and the resulting qualification testing. It will also demonstrate how the results will assist in the production allocation and optimization of recovery from the field. Through this testing, the operator demonstrated commitment to the intelligent well completion initiative as well as the provision of an accurate method of allocating production using in-well flow meter and pressure and temperature gauges.
Increased Production Through Microseismic Monitoring of Hydraulic Fracturing Over a Multiwell Program
Authors: Barker William 
Published: October 2009

Abstract
Surface based microseismic monitoring enabled an E & P company to optimize their hydraulic fracture treatments. This case study covers a six well program, consisting of 25 stages with 84 hours of continuous microseismic monitoring. The first part of the program consisted of stimulations in three vertical wells. This part of the program provided information indicating fracture orientation and lateral extent of the asymmetrical hydraulic fractures. This was then used to design optimal spacing and fracture design of the stimulations in the remaining three horizontal wells. The common fracture azimuths are 320° +/− 10° and 40° +/− 8°. More complex multi-stage stimulations in the horizontal wells showed microseismic activity growing before the proppant injection with a significant fracture half length. However, microseismic activity occurred near the wellbore during the mid and late portion of the proppant injections indicating the bulk of the proppant load was delivered near the wellbore. High initial post-stimulation production with a rapid decline was observed, supporting this interpretation. This led to the redesign of the fracpack treatment using smaller proppant sizes resulting in larger fractures and more productive wells. We also estimated a stimulated reservoir volume for each stage. The data were then combined into a table for reference, along with aerial extents of activity for the six wells. The microseismic activity then increased with more optimized treatments. We show that generally the production of each well is proportional to the stimulated volume. These results have given the operator an insight to the fracture orientation, and fracture effectiveness of 25 individual hydraulic fracture treatments.
Rapid, Interactive Assessment of Petrophysical and Geometrical Effects on Density and Neutron Logs Acquired in Vertical and Deviated Wells
Authors: Heidari Zoya , Torres-Verdín Carlos , Mendoza Alberto , Ijasan Olabode , Voss Ben , Preeg Bill 
Published: October 2009

Abstract
Borehole, geometrical, and petrophysical effects can significantly affect density and neutron logs. Tool location around the perimeter of the borehole, tool standoff, and wellbore deviation have a measurable effect on density and neutron logs, hence on the estimation of porosity and fluid density. It is difficult to diagnose and quantify these effects a priori without numerical modeling. The multiple-particle, radiation-transport Monte-Carlo code (MCNP) has traditionally been used by the logging industry to simulate borehole nuclear measurements acquired in complex rock formations. Despite its versatility and accuracy, MCNP is not numerically efficient for rapid simulation of nuclear logs and does not lend itself to interactive testing of multiple petrophysical/fluid hypotheses.
We describe the successful application of a new method for nuclear-log simulation based on linear iterative refinement of nuclear sensitivity functions pre-calculated with MCNP. The procedure is fast, accurate, and efficient in most practical logging applications, including the simulation of nuclear logs acquired in invaded formations and in highly-deviated wells. Density and neutron logs acquired over a depth segment of 1000 ft can be accurately simulated within minutes of CPU time, compared to days with MCNP. Simulations are successfully verified against MCNP in a number of extreme cases of borehole, petrophysical, and fluid conditions wherein the error of the simulations does not exceed 2 porosity units.
We implement the new simulation method to reproduce several field examples where logs are affected by presence of clay and invasion with water- and oil-base muds. Our rapid simulation procedure enables the interactivel quantification of the relative effect of clay, invasion, fluid density, and rock petrophysical properties on field logs. It also permits efficient integration with induction resistivity measurements for assessment of free and clay-bound water saturation, as well as for the assessment of residual hydrocarbon saturation. Additional simulations of density and neutron logs are performed to quantify the influence of shale laminations on hydrocarbon-bearing and invaded thinly-bedded formations. Because of their longer radial length of investigation compared to density logs, neutron logs may exhibit false cross-over effects across thin beds.
A Placement Model for Matrix Acidizing of Vertically Extensive, Heterogeneous Gas Reservoirs
Authors: Nozaki M. , Hill A. D. 
Published: October 2009

Abstract
A critical issue in matrix acidizing of vertically extensive carbonate reservoirs is the acid distribution along the wellbore. This estimation is very important especially for the case where the reservoir properties (permeability and damage distribution) vary along the wellbore. Several acid placement models for oil reservoirs have been developed and applied in the field successfully. However, when evaluating acidizing in a gas well, the models are not adequate because of the viscosity contrast between the reservoir fluid (gas) and the injected fluid (acid) and because of relative permeability effects. We have developed an acid placement model for acid injection into vertically extensive gas wells in heterogeneous carbonate reservoirs that includes gravity segregation in the wellbore, viscosity contrast, relative permeability effects, and a wormhole model. The effects of all of these factors on the local injectivity during acid injection are incorporated into a dynamic skin factor model.
To test this new model, we analyzed coreflooding data in the literature. The analysis showed that the differential pressure across a gas saturated core did not linearly drop during acidizing, but instead increased during a large part of the acid injection period. From this analysis, we determined that the pressure drop in a spent-acid zone ahead of the wormholes dominates the overall pressure drop behavior.
Applying this model to typical field conditions, we find that a natural viscous diversion takes place in heterogeneous gas reservoirs because of the viscosity contrast between the gas and the injected acid. In particular, we have modeled thick carbonate gas reservoirs having a few thin, very high permeability thief zones. Before wormholes break through the damage zone in the high permeability parts of the reservoir, this viscous diversion effect distributes acid more uniformly than expected. However, after wormholes break through the damaged zone, thief zones will take a large portion of the injected acid. Another important prediction with this model is that the injection pressure often increases during acid injection into gas wells. Without an understanding of the role of mobility contrast on the injection pressure response, operators may incorrectly conclude that the injected acid is not stimulating the formation.
Transport Properties of Hydrate Bearing Formations from Pore-Scale Modeling
Authors: Phirani J. , Pitchumani R. , Mohanty K. K. 
Published: October 2009

Abstract
Gas hydrates are an attractive source of energy as natural gas can be produced from these deposits by depressurization or thermal stimulation. Empirical correlations developed in hydrology and petroleum engineering have been used for describing transport properties of sediments containing gas hydrates in hydrate simulators. The goal of this work is to estimate the transport properties of hydrate-bearing sediments from pore-scale modeling. Sediment particles have been packed using a discrete element method and pore radius distribution is calculated using Delaunay triangulation. Hydrate deposition is modeled in a single pore to develop pore-scale laws of hydrate occupancy. Pore radius distributions are recalculated after hydrate deposition. Percolation theory is used to numerically calculate effective transport properties of the medium at different saturations. Pore-scale models showed that the hydrates form at the pore walls if deposited from the flow of methane-saturated water alone. The saturation of hydrate deposited in different size pores was found to be uniform. A Gaussian distribution of particle size of the sediment results in a Rayleigh distribution of pore throat radius. As the variance of the particle size increases, so does the width of the pore size distribution. As the hydrate saturation increases, the permeability of the sediment decreases. This decrease follows Civan's correlation with a β of 0.75. The relative permeability becomes increasingly dependent on water saturation as the hydrate saturation in the sediment increases. A new correlation for relative permeability is developed by matching the percolation theory estimates.
Numerical Modeling of Multi-Stranded Hydraulic Fracture Propagation: Accounting for the Interaction Between Induced and Natural Fractures
Authors: Dahi-Taleghani Arash , Olson Jon E. 
Published: October 2009

Abstract
Recent examples of hydraulic fracture diagnostic data suggest complex, multi-stranded hydraulic fractures geometry is a common occurrence. This reality is in stark contrast to the industry-standard design models based on the assumption of symmetric, planar, bi-wing geometry. The interaction between pre-existing natural fractures and the advancing hydraulic fracture is a key condition leading to complex fracture patterns. Performing hydraulic fracture design calculations under these less than ideal conditions requires modeling fracture intersections and tracking fluid fronts in the network of reactivated fissures. Whether a hydraulic fracture crosses or is arrested by a pre-existing natural fracture is controlled by shear strength and potential slippage at the fracture intersections, as well as potential debonding of sealed cracks in the near-tip region of a propagating hydraulic fracture. We present a complex hydraulic fracture pattern propagation model based on the Extended Finite Element Method (XFEM) as a design tool that can be used to optimize treatment parameters under complex propagation conditions. Results demonstrate that fracture pattern complexity is strongly controlled by the magnitude of anisotropy of in situ stresses, rock toughness, and natural fracture cement strength as well as the orientation of the natural fractures relative to the hydraulic fracture. Analysis shows that the growing hydraulic fracture may exert enough tensile and shear stresses on cemented natural fractures that they may be debonded, opened and/or sheared in advance of hydraulic fracture tip arrival, while under other conditions, natural fractures will be unaffected by the hydraulic fracture. Detailed aperture distributions at the intersection between fracture segments shows the potential for difficulty in proppant transport under complex fracture propagation conditions.
The Impact of Oil Prices on Oil Shale Development in the United States
Authors: Biglarbigi Khosrow , Killen James , Carolus Marshall 
Published: October 2009

Abstract
The United States has the largest oil shale resources in the world, in excess of 6 trillion barrels. Potential U.S. oil shale reserves could exceed 800 billion barrels, depending on oil price. New technologies may soon enable these resources to be produced efficiently and economically. Recently, increased oil demand, tightening supplies, and higher oil prices stimulated investment in energy projects around the globe, driving up the cost of materials, skilled labor, and other project inputs. A clear example can be seen in the rapid increase of capital and operating costs in Alberta's oil sands. Similar experiences could be expected during the development of a domestic oil shale industry. This raises questions about the effect of oil price on oil shale economics, including both capital and operating costs.
To answer this question, an analysis was conducted using the oil price as a surrogate for energy costs, tightness of the labor market, the costs of materials, and other factors which impact the development of oil shale projects. After developing a relationship between the oil price and the cost of development, an analysis was conducted to determine the impact caused by increasing oil prices on the minimum economic price of four representative oil shale development technologies.
This paper will discuss the relationship and impact of oil price and oil shale development costs. In addition, the paper will describe the impact of the cost relationship on production and other macro-economic benefits which can be realized.
Corrosion Inhibition of New 15 Chromium Tubulars in Acid Stimulation Fluids at High Temperatures
Authors: Boles Joel , Ke Mingjie , Parker Carson 
Published: October 2009

AbstractOver the past several years, a substantial increase in deep water exploration and production has brought new challenges to corrosion and material technology. The production environments in deep wells normally involve high temperature, high pressure, and sweet/sour gas. These severe conditions require corrosion resistant alloy (CRA) for well completions and production. To meet industry demands, one manufacturer has recently developed a new 15 chromium (15Cr) steel tubular as a high strength tubular (125 ksi) to control CO2 corrosion. With its modified metal composition, the new 15Cr further improves the corrosion resistance of some of chemically enhanced 13Cr, and can be applicable at temperatures up to 392°F where the use of 22Cr duplex would otherwise be required. In other words, if not for this new 15Cr, they would have to use the 22Cr, which is more expensive. With the introduction of new 15Cr to oil and gas well operations, it becomes necessary to evaluate its corrosion behavior in acid stimulation fluids at high temperatures. Due to the corrosive nature of acids, understanding its corrosion behavior and optimizing effective acid corrosion inhibitors/inhibitor packages for 15Cr tubular are critical to maximize the life of tubulars and further improve overall well completion effectiveness.This paper presents results of acid corrosion tests performed on new 15Cr tubular samples at temperatures from 260 to 350°F. The acids tested included hydrochloric acid, hydrochloric-hydrofluoric acid (mud acid), acetic acid, formic acid and their combinations. Several acid corrosion inhibitors/inhibitor packages normally used for 13Cr were evaluated to determine their effectiveness on new 15Cr. Results indicated that corrosion behavior of 15Cr in acids can be completely different from that of conventional API 13Cr. It appears that the chemical compositions of 15Cr and heat treatments during the process of steel manufacturing play a significant role in corrosion behavior. Also, the data shows that some inhibitor packages typically used for 13Cr do not provide adequate corrosion protection on 15Cr materials. Furthermore, practical guidelines for the use of acid corrosion inhibitors/inhibitor packages with 15Cr CRA metallurgy are discussed.
A Study of Heat Related Factors Caused by Color Selection of Hard Hats and FRC Garments in Out Door Work Environments
Authors: Davis Michael , Kaminski Don , Oliver Michael Chase , Graf Jake , Pilling Lee 
Published: October 2009

Abstract
The purpose of the study was to validate comments from the field employees describing increased heat stress and discomfort wearing the dark hard hats and dark coveralls during the hot sunny weather during the summers.
The purpose of this study is to determine the following: What criteria should be used to evaluate any potential heat stress created by the color of the fabric or hard hats?Does the color of the fabric or hard hat affect the potential heat stress on a worker in the sun?If there is a difference, which color would contribute least to potential heat stress?Would the data clearly suggest which color to select?
With these goals in mind, a testing protocol was developed to determine if the color would affect the perceived comfort and apparent heat stress of the user in hot sunny conditions.
The color of hardhat and garment does make a significant difference in the surface temperature that would affect conduction and radiation as a method to cool the body. The differential in surface temperature is significant between the dark and light colors as expected. Surface temperature differentials ranged up to 49° F on the hard hat and 45° F on the garment. The dark colors add heat load to the body, therefore color does make a significant difference in the ability to radiate heat as a method of cooling the body.
Dark colors absorb more energy and therefore have a higher surface temperature limiting the bodies' ability to radiate heat that is either absorbed from the sun or created by activity. The study indicates the selection of the hard hat and garment colors significantly contribute to the bodies' ability to dissipate heat. Further study will determine the physiological impact to the bodies' ability to regulate its core temperature.
Evaluating Horizontal Well Placement and Hydraulic Fracture Spacing/Conductivity in the Bakken Formation, North Dakota
Authors: Lolon E. P. , Cipolla C. L. , Weijers L. , Hesketh R. E. , Grigg M. W. 
Published: October 2009

Abstract
The success of horizontal well completions in the Bakken formation has increasingly attracted much interest within the oil and gas industry. Improved stimulation techniques including the use of new fluids and proppants, better zonal coverage through improved diversion and staging, and/or re-fracture treatments contributed to this success. This paper presents the results of a fracture modeling and multi-well simulation study to evaluate down-spacing potential for horizontal wells. This study also examines how the number of stages along the lateral, proppant type, treatment volume, fracture conductivity, and effective oil permeability affect production profiles and oil recovery in the middle Bakken formation, North Dakota.
In this work, a lumped 3D fracture growth model was calibrated with direct fracture mapping observations that showed significant upward height growth into the Lodgepole formation. The horizontal well orientation is selected to promote transverse fractures. This paper provides details about the fracture treatment designs and subsequent integration of the fracture geometry and conductivity descriptions into the reservoir model. Various fracture treatment designs are evaluated, with the goal of optimizing fracture conductivity and minimizing upward height growth (which can be a problem in the middle Bakken).
The results of this study showed a significant infill drilling potential because of the low estimated effective oil permeability (0.002-0.04 mD). Reducing the horizontal well spacing from one to two or three wells per 640 acres should significantly increase oil recovery. The optimum number of fracture treatment stages along the horizontal lateral depends largely on reservoir permeability, lateral length, and number of wells per section.
CO2 Sequestration: Temperature and Gas Compositional Effects on the Kinetics of Mineralogical Reactions
Authors: Mandalaparty Prashanth , Deo Milind , Moore Joseph 
Published: October 2009

Abstract
It may be possible to lower costs of Carbon Capture and Sequestration by keeping constituents such as sulfur dioxide (SO2) in the flue gas stream. The reactive behavior of pure CO2 and CO2 + SO2 mixtures within a geologically realistic environment was examined. The experimental apparatus consisted of a series of four high-pressure reactors operated at different conditions and with different feed gas compositions to observe changes in both the rock and water compositions. The rock consisted of equal proportions of quartz, calcite, andesine, dolomite, chlorite and magnesite (constituents in arkose or dirty sand stone). The brine was prepared from laboratory grade sodium chloride and by varying the amount of magnesium concentration in the brine. Several long-term batch experiments with pure CO2 were carried out at different temperatures. Each mineral in the mixture showed evidence of participating in the geo-chemical reactions. Layers of calcite were seen growing on the surface of the arkose. Analcime deposits were omnipresent, either occurring as large connected aggregates or as deposits on the surfaces of other minerals (Quartz). Ankerite and calcite depositions were observed as amorphous masses intergrown with the feed. The CO2 + SO2 mixture experiments showed growth of euhedral anhydrite crystals and pronounced dissolution patterns over the examined surfaces. The growth of these new phases would lead to significant changes in the petrophysical properties of the rock. The trends in ionic concentration changes in the aqueous phase complemented the changes in the rock chemistry. The rates of these reactions were computed by measuring the changes in the compositions of the initial and the final samples. The rates of these reactions were computed by computing the changes in the compositions of the initial and the final rock samples (both individual and mixture) provided by the XRD analyses and were observed to be lower than expected.