bluuebunny/crossref_metadata_2025_split huggingface dataset:
West Delta Block 84-Methodology and Analysis of a Previously Orphaned Field
Authors: Kimbrell W.C. , Wojtanowicz A.K. 
Published: March 2010

Abstract
This paper describes the effort to justify, document, and confirm proven, unproven, undeveloped, and bypassed remaining oil and gas reserves in West Delta Block 84 Field; at one time an orphaned field off the coast of Louisiana. The methodology used for the evaluation provides an insight into how to quickly and efficiently identify worthwhile and economic marginal properties, even with incomplete or missing information. This methodology is being used as a part of the development of an expert system for the evaluation of marginal and/or orphaned wells, reservoirs, and fields.
West Delta Block 84 is located off the coast of Plaquemines Parish, Louisiana, near the mouth of the Mississippi River in about 20 ft of water. Conoco discovered it in 1955 with the drilling of the SL 2551 No. 1 well to a total depth of 14,500 ft. It has produced over 9.8 MMSTB of oil and 21 BCF of gas. It was shut in for a period of almost ten years while languishing in and out of bankruptcy court from 1990 to 2000, and was actually orphaned by the state at one point during this time.
Available data was organized and pieced together for the field, but was still lacking in completeness. As in most cases when dealing with older marginal fields, an ability to deal with missing and incomplete information was necessary to complete the analysis.

Introduction
There are reportedly 343,030 inactive, shut-in, and/or orphaned wells nationwide, of which 34,355 are in Louisiana. In many cases, these wells are idle and orphaned, not because their resources have been depleted, but because of other factors. These factors might include low product price, high cost of operations, unrelated financial problems, or the inability or lack of resources to properly describe the reservoir and identify the potential for additional recovery, among other things. It is simply not known, with any accuracy to an outside party looking in, exactly why a well is shut in or orphaned.
Historically, small and large independent producers have entered into fields previously operated and owned by the major oil companies. These underfinanced and understaffed independents find themselves working off cash flow and unable to find the financial resources to work over the idle wells, much less do the research that many of the wells and reservoirs deserve and need. The wells may have potential, but no one has the time or the money to pursue these presumably marginal targets.
There is an incentive to identify potential in these shut-in/orphaned wells since their plugging would be terminal and, in the case of orphaned wells, would cost taxpayers money. In a period of four years, from 1996 to 2000, there were reportedly 712 wells plugged in Louisiana for US$14,090,000, which is an average cost of US$17,890 per well. Presently, there is a new powerful incentive for not plugging wells that might be returned to production as the processing price of oil has reached US$56/STB with no signs of leveling or dropping in the future.
Simulation of Erosion in Drilling Tools for the Oil and Gas Industry
Authors: Arefi B. , Settari A. , Angman P. 
Published: March 2010

Abstract
Erosion is a form of wear that has been found on the drilling tools used in the oil and gas industry that can, in some cases, severely shorten the life of the tools. In spite of its importance, there has been virtually no attention paid to it in drilling engineering research. This paper focuses on the modelling of erosion and the application of the developed models to improve the design of drilling tools. The mechanism of erosion, which is controlled primarily by the impact velocity and angle, has been formulated based on experimental and theoretical work done in material science. These algorithms were developed for transient simulations of the erosion of any surface in 2D geometry. Based on these, an "Erosion Simulator(1)" has been written, which is able, in combination with any computational fluid dynamics (CFD) software, to simulate erosion in downhole tools. Actual data from TESCO Corporation casing drilling tools(2) has been used to calibrate the physics of the process and validate the software. The simulator has been used to modify the geometry of the under-reamer casing-drilling tool, which resulted in a substantial decrease in erosion rate and therefore an increase in the tool's life.

Introduction
Erosion, as a form of material wear, has been reported in many areas of the oil and gas industry. An example of erosion in drilling tools is the TESCO Corporation (hereinafter TESCO) "underreamer" tool used in casing drilling(1) (see Figures 1 and 2). Erosion in the drilling industry is important because it can lead to an increase in time and cost of operation. In the case of drilling tool failure from erosion, eroded parts must be replaced. This will cause unexpected extra rig time in order to pull out the drill string and run it with new parts into the wellbore. Besides the cost of operation, erosion may be dangerous. Tool failure can cause a blowoutand be a potential for loss of lives. This paper focuses on an erosion simulation in order to understand and predict erosion phenomena in drilling tools, with the ultimate goal of improving tool design and extending its life.

History of Erosion Research
Erosion (i.e., a form of wear) occurs when fluid containing solid particles impacts a solid surface. The intensity of erosion is commonly measured as a specific weight loss (rate of material removal from the surface) and expressed as Er (the weight of material removed by unit weight of impacting particles). During the 1960s and 1970s, a number of important experiments were done in the area of metal wear that laid the foundation for the current understanding of the phenomena. Erosion experiments during that period covered impact velocities up to 550 m/s and particle sizes of up to 1,000 μm [Tilly(3)]. Different velocities and particles can cause different types of damage. During this time, scientists and researchers determined the relationship between erosion rate, the type of material, size of particles, velocity, and angle of impact.
Determination of True Bed Thickness Using Folded Bed Model and Borehole Data
Authors: Xu S.S. , Velasquillo-Martinez L.G. , Grajales-Nishimura J.M. , Murillo-Muneton G. , Garcia-Hernandez J. , Nieto-Samaniego A.F. 
Published: March 2010

Abstract
The true bed thickness (t) is the actual thickness of a given formation perpendicular to the bedding plane. The value of t depends on the angle and the direction of the dip of the measured formation, as well as the drift angle and azimuth of the borehole. The traditional methods to calculate the parameter t consider only the case of monoclinal beds but not the case of a folded bed, which will cause deviations when the bed dip on the top is different from that on the bottom. To avoid these deviations, this paper shows an approach to calculate the values of t using a folded bed model. The deviations for the monoclinal bed model are positively related to the bed dip, the dip difference and the deviated angle of the wells. A case study from the Cantrell oil field complex in the southern Gulf of Mexico (offshore Campeche) is used to test the folded bed method. The results indicate that this model can yield more uniform spatial change of the values of t, whereas the monoclinal bed model will overestimate the average value of t. Compared to the folded bed model, the maximum relative deviation of t from the monoclinal bed model reaches 22.3% and the maximum absolute deviation of t reaches 34.5 m.

Introduction
In the subsurface of a bed formation, the true bed thickness can be estimated from information gathered from well logs such as the dipmeter and borehole images. The log thickness of a given stratigraphic interval can be thicker, equal to or thinner than that seen in a vertical well drilled through the same stratigraphic section because of well deviation and formation dip. Provided bed dips and well deviations do not exceed a few degrees, the simple vertical-horizontal case is approximated closely enough by the logs. But when deviations and dips do exceed about 10 °, corrections are needed. A previous method of corrections is based on the monoclinal bed model. But this assumption is approximate, because the tectonic events generally cause the beds to be not only tilted, but also folded.
True bed thickness is important in dipping beds and in deviated holes, since reservoir volume and isochore maps depend on these properties and not on the measured thickness. In this paper, a folded bed model is proposed to calculate the true bed thickness in the subsurface utilizing well log data.

Calculation of the Value of t in the Case of Monoclinal Bed
First, the case of a monoclinal bed is reviewed here. Figure 1a shows the case of a vertical well crossing a monoclinal bed. If the well enters the top of the bed at A, and leaves the base of the bed at B, the depth difference between A and B is defined as hd. The true bed thickness of the bed (t) can be expressed as:
Equation (1) (Available In Full Paper)
Figure 1b shows the case of a well deviated at an angle a from the vertical crossing a monoclinal bed.
Simulation Study of Acid Gas Injection Into an Aquifer
Authors: Wu R. , Heinrichs H.J. 
Published: March 2010

Abstract
A series of simulation runs using a compositional simulator were conducted to determine the area of influence that results from injecting acid gas (H2S) for 30 years at 330 e3m3 into a 75 m thick high permeability sandstone aquifer. In this study, the three-phase (gas-oil-water) equilibrium calculation was used. Initially, a 5 Township by 5 Range grid model was used to determine the area of influence; subsequently, a smaller grid model 1 Township by 1 Range was used.
Boundary producers were required to properly simulate an infinite aquifer. This study found that buoyancy and relative permeability, more than other parameters such as the perforation interval and the gas-water capillary pressure, affected the area of influence. A refined 75-layer model, one-metre thick, was constructed to check the gravity effect. The results of this refined layer model agree closely with a 13-layer model after 11 years of acid gas injection.
A blowdown simulation was also conducted to determine the time to significant water inflow from perforations at the bottom of the zone.
The effect of a 50 year shut-in after 30 years of injection was also simulated.

Introduction
The objective of the study was to understand the reservoir volume and the area of influence that would result from the injection of H2S into the Basal Sand aquifer of the Cambrian age Deadwood Formation. This was accomplished through the use of a compositional simulator (CMG's GEM).
The Husky Lloydminster Upgrader (HLU) produces large amounts of acid gas: mainly H2S. The existing sulphur plant removes the sulphur from the H2S. Implementation of H2S disposal into the Deadwood Formation would initially reduce the load on the existing HLU sulphur plant, and ultimately it might be shut-in. Any future expansion of the HLU would not require an additional sulphur plant if acid gas disposal was proven to be effective.
For safety reasons and regulatory requirements, it was required to know where the injected H2S would migrate to within the aquifer over time. The resulting area of influence would determine the penetrating wells and the mineral rights owners that might ultimately be affected by H2S injection.
In this study, a commercial compositional simulator (CMG's GEM) was used as the model as it can take H2S water solubility into account. In the simulation results, the area of influence is defined as the area that has an H2S concentration greater than 0.00001 mole fraction. This value is based on the numerical accuracy of the simulation.
The selected simulator was developed for oil-gas-water three-phase and multi-components usage. To simulate an H2S-water system, a small amount of methane (0.0005 gas saturation) was used as an oil phase for initialization. To distinguish the initial methane gas from H2S in the gas phase, all the gas saturation graphs used a minimum scale of 0.0005.

Deadwood Aquifer Formation and Reservoir Model
References (1) and (2) provide a detailed geological appraisal and a mineralogy study of the Cambrian Deadwood Formation Basal Sand.
Basic Investigations on Enhanced Gas Recovery by Gas-Gas Displacement
Authors: Turta A.T. , Sim S.S.K. , Singhal A.K. , Hawkins B.F. 
Published: March 2010

Abstract
The paper presents basic data on Enhanced Gas Recovery (EGR) by gas-gas displacement for nearly depleted natural gas reservoirs by injecting waste gases. The soundness of the concept of gas-gas displacement for enhancing gas recovery was investigated via laboratory investigations, compositional modelling and economic analyses. Paramount Resources is field testing the concept in their GRIPE Project in the Athabasca region of Alberta, to enhance production from a gas bearing stratum overlying the oil sand interval.
This paper is a part of a series of papers presenting results of EGR research conducted over a five-year period (2003 – 2007). The main targets were volumetric (closed) reservoirs in advanced phases of exploitation. Results of basic research on methane displaced from core samples by pure gases (pure CO2 or pure N2), as well as flue gases (mixtures of CO2 and N2), are presented.
A series of nine gas/gas displacement tests in 30 cm long, 4 cm diameter, Berea cores were conducted at a temperature of 70?C and a pressure of 6,200 kPa. Most of the tests were conducted in the presence of connate water, while others were conducted without connate water (dry cores) to confirm and benchmark the results by other investigators. The tests on consolidated cores showed that for pure nitrogen and pure CO2, used as the displacing medium, the recovery was comparable.
Where a mixture of CO2 and nitrogen displaced the natural gas, it was observed that there was a delay in CO2 breakthrough, associated with a period when only a mixture of methane and nitrogen was produced. This is so because solubility of CO2 in connate water is considerably higher than that of nitrogen. This leads directly to a higher gas recovery due to a longer exploitation period, given the fact that up to 20% nitrogen can be tolerated in the produced stream, as opposed to only 1% for the CO2 case. For this period of methane and nitrogen production, there are no operational problems associated with the corrosive nature of CO2.
EGR by gas-gas displacement is seen as a promising way of prolonging the productive life and economic recovery of many depleting volumetric gas reservoirs.

Introduction
Alberta currently has 42,000 gas pools, which are in different stages of exploitation. For these gas reservoirs, the pools that should be considered first in the implementation of large-scale EGR-CO2 and CO2 storage have not yet been identified, and no screening criteria have yet been developed. Currently, only the concept of "disused gas reservoirs" has been advanced(1) for CO2 storage. This concept implies that only those reservoirs that are in an advanced stage of depletion (with very little marketable gas left), traditionally with extremely low current pressure, or which are water invaded, should be considered. In this context, they have been considered exclusively for CO2 storage and not for enhanced gas recovery (EGR). This paper brings a new concept: that of simultaneous EGR and CO2 storage.
Operational Problems in the Arctic Islands
Authors: Usher J.L. 
Published: March 2010

Abstract
Geological exploration on the Arctic Islands encounters many operationalproblems that are new to most Canadian geologists. Although conditions aresimilar to those of the tundra on the northern Mainland, climatic andphysiographic differences impose modifications in transportation to the field, in planned reconnaissance and detailed surface studies, and in livingconditions in the field. The relative merits of small single-winged aircraftand helicopters are discussed; the change of method of field work with changeof ice conditions from spring to fall are examined; the effect of varioustopographies and bedrock on relative ease of movement are considered.

Introduction
Recorded exploration of the Arctic Islands has been in progress for nearly450 years. It began with the search for a Northwest Passage to the Indies, asearch that was forced upon European entrepreneurswhen they realizedthat not only was the earth spheroidal but that a major continent intervenedand barred the western route between Europe and Asia. In the words of Taylor(1955, p. 8), … North America, in European eyes, was not so much a goal to beachieved as an obstacle to be surmounted." Polar exploration was furtheradvanced by whaling and sealing enterprises and by the concerted efforts of themany expeditions that attempted to reach the North Pole. These numerous voyagesestablished the basic cartography of the Islands, but yielded only a smatteringof geological knowledge from widely separated points. It was not until thepost-war years of the late 1940's that the first long-range, systematicallyplanned, geological exploration of the Islands was instrumented by the Canadian Government. Today, through the efforts of the Geological Survey of Canada, whose work has been immeasurably aided by complete photographic coverage of the Islands, regional geological reconnaissance of the Arctic Archipelago is nearlycompleted. This work was obviously basic to the opening of the Islands'territory to oil and gas exploration and to the acquisition of lands bycompanies interested in this exploration. The value of the Geological Survey'sexploration is not, however, limited to geology; their operations on the Islands have provided us with important and valuable data on methods of groundand aerial transportation, on the climate, on the terrain, and on logistics. Inshort, they have provided us with the basic knowledge of how to live and workin the area.
Combination Gas and Water Injection Project - Leduc D-3 Pool
Authors: Buckles R.S. 
Published: March 2010

Abstract
The oil zone in the Leduc D-3 Pool is sandwiched between an extensiveoverlying gas cap and a large underlying aquifer. It is therefore free to moveto higher or lower elevations within the reef, in response to any imbalancebetween gas cap expansion and water influx. Recent studies have shown that itwill be necessary to control the movement of both the gas-oil and oil-watercontacts relative to well completion intervals for optimum recovery andperformance. The field has been unitized and both gas and water are beinginjected to achieve this objective. The results of a detailed engineering studyare being used to control injection ratios and pool performance.

Introduction
The discovery, geology, development and performance of the Leduc D-3 Poolhave been discussed in the past. Only a brief chronological summary of poolhistory will be given here to provide a basis for this review of reservoirengineering studies. The reservoir was discovered in 1947 about 12 milessouthwest of Edmonton. Early development was spread over a period of severalyears with a total of 535 wells being drilled to 5300 feet on 40-acre spacing.At least four separate pools have been defined as shown in Figure1. Thesubject of this paper is the "Main Reservoir", which covers almost 90 per centof the developed acreage. Its properties are summarized in Table 1.
It was in 1948 that Atlantic No. 3, drilling on the eastern edge of thepool, blew wild for six months. The uncontrolled production of oil and gas-capgas during this period resulted in a sharp decline of 50 psi in reservoirpressure. An estimated 28 billion cubic feet of gas was produced withapproximately a million barrels of oil, most of which was salvaged in earthenpits.
Eastern Canadian Oil and Gas Prospects
Authors: Boggs O.D. , Lloyd G.V. 
Published: March 2010

Abstract
A general assessment of exploration for and development of Oil and Gas inEastern Canada, Past and Present, and the possibilities for the Future, aregiven. The assessment is subdivided for purposes of convenient discussion, intothe Southwestern Ontario, St. Lawrence Lowlands, Gaspe Peninsula and MaritimeBasins areas. The general stratigraphic and structural natures of these Basinsin relation to their Oil and Gas prospects are stressed.

Introduction
There has been an increasing realization in recent years that thesedimentary basins in Eastern Canada have not been completely evaluated as tooil and gas prospects. This has lead naturally to increased leasing and torelated exploration and exploitation activity. The resultant high success ratiohas supported this activity and it is anticipated that the trend, in somecases, will expand even further.
It may not be that the results per unit effort will, everywhere, be the samein Eastern Canada as they are for the more promising areas in Western Canada, but the higher well-head prices for oil and gas in Eastern Canada still makethis area as promising or even more so on an economic basis than many areasbeing explored in Western Canada. The strong demand and firm prices make forrapid payouts in contrast to western areas where pro-rationing and competitionhave lead, in general, to extended payout periods.
Assisted recovery methods, such as water-flooding and improved productiontechniques, including fracturing of some of the more impermeable but porousbeds, are leading the way not only to increased profitabilities but also tore-evaluations of known, but marginal, pre-existing prospects.
Another important factor is that fully modern exploratory methods have notyet been applied to a reasonable extent to the Eastern Canadian basins. Thesituation might be likened to some extent to that of old mining areas, whereimproved knowledge of mining and of metallurgy permits the extension of oreveins or the re-opening of abandoned mines and even of the slag heaps, on amore economic basis than was originally experienced.