bluuebunny/crossref_metadata_2025_split huggingface dataset:
Liner Completion Difficulties Resolved With Expandable Liner Top Technology
Authors: Smith P. , Williford J. 
Published: March 2010

Abstract
Liner top packers, which are run as a standalone unit or integrally with conventional liner hangers, are set through the application of weight applied through the drill pipe or landing string. The capability of the liner top packer to seal at the stated pressures rated for which they are designed requires that a sufficient setting force of up to 355857.7 N (80,000 lbf) be applied through the drill pipe to the packer mechanism. Recently, work performed by an operator in Latin America showed the limitations of this process when used in shallow liner top installations where the available string weight alone to apply a sufficient setting force to the liner top packer is not available. Picking up a string of large drill collars in order to have the capability to supply the significant setting force required was an alternative. However, it was not a preferred option, safety being the main concern, followed by handling time, as was seen on the first well utilizing conventional liner hanger and liner hanger packer technology.
The expandable liner hanger (ELH) was developed as a solution to resolve the problem of weight down required to set the liner top and allowing a setting force to be applied to the packer elements locally through the hanger body with the use of hydraulic pressure. The setting force for the packer is measurable and consistent, ensuring that a liner top seal and hang weight is obtainable without requiring weight down. This system contains no moving parts, which makes it possible to function with a drill string. Once deployed in the well, the liner hanger body expands radially through the pressurization of its elastomeric elements, thus, creating a gas-tight seal and achieving zonal isolation. The operator chose to deploy the expandable liner hanger system on two subsequent wells following the initial attempt to utilize a conventional system approach. The ELH installations were successful, saving the operator several days of rig time on each well.
The case study discussion and system description presented in this paper will explain the flexibility and integrity of the expandable liner hanger in providing a liner top seal upon setting in a shallow liner top installation.

Introduction
Historically, problems obtaining a good primary cement job at the top of the liner have been associated with the installation of liners in oil and gas wells. Conventional liner hanger systems have relied upon the primary cement job to provide liner top pressure sealing integrity within the liner/casing overlap. In many wells however, cementing the complete liner and liner lap is often not achievable due to various problems, which include loss of circulation, fluid loss or other wellbore/formation conditions. In cases like these, obtaining a primary cement seal across the liner lap is not obtainable, and a liner top packer must be deployed on a second run to make the primary liner the top seal.
Cold Flow: A Multi-Well Cold Production (CHOPS) Model
Authors: Tremblay B. 
Published: March 2010

Abstract
A multi-well cold production (CHOPS) model, developed at the Saskatchewan Research Council, was used in conjunction with a commercial reservoir simulator, to predict the effect of well spacing and in-filling on oil recovery in cold production. The oil and sand production from the Lindbergh/Frog Lake cold production wells was history matched initially. The comparative economics of five different well spacings (10 acre, 20 acre, 40 acre, 60 acre and 80 acre) was estimated. The 20 acre spacing was the most economic overall for heavy oil prices varying between C$251/m3 (C$40/barrel) and C$502/m3 (C$80/barrel). The multi-well model was used to estimate the additional oil recovery from in-fill wells at different in-fill times. In-filling a 40 acre spacing well with 10 acre spacing wells was not economic for a Lindbergh/Frog Lake type of reservoir. In-filling the same well with 20 acre spacing wells was economic at higher oil prices in the C$502/m3 range (C$80/barrel).

Introduction
The main mechanisms which contribute to the success of the cold production process are solution gas drive and sand production. Maini(1) argued that the greater oil recovery for heavy oil compared to light oil was due to the formation of a gas in oil dispersion which he called "foamy oil." This dispersion would have a greater compressibility which would maintain the reservoir pressure for longer times. Firoozabadi(2), based on a series of solution gas drive experiments performed at reservoir-type oil velocities, attributes the greater oil recovery for heavy oil to a higher critical gas saturation and to reduced gas flow leading to reservoir pressure maintenance.
Three basic scenarios were proposed in the literature to explain how sand production leads to greater oil recovery:a limited dilated sand region around the wellbore(3),a dilated sand region around the wellbore with wormholes extending into the formation(4) andonly wormholes extending out into the formation(5, 6).
The third scenario can best explain the rapid (within a few hours) travel time of a fluorescein tracer dye between an injector and a producer, observed by Amoco in a tracer test(5). Since the concentration of this dye, which is known to adsorb on the surface of a porous medium, did not change at the producer, Squires(5) concluded that an open (sand-free) channel connected the injector and producer. This observation contradicts scenarios 1 and 2 since these scenarios preclude the existence of an open channel throughout the length of the wormholes. Field engineers have observed that they sometimes lose fluid circulation while drilling into cold produced reservoirs. The location at which fluid loss occurs can help in mapping the wormhole network in the field. For example, when Nexen Inc. drilled two horizontal wells in a field after cold production, they observed lost circulation to neighbouring wells at the locations indicated by the ? marks in Figure 1. These 40 acre spacing cold production wells had produced large quantities of sand.
Impact of Concentration-Dependence of Diffusion Coefficient on VAPEX Drainage Rates
Authors: Okazawa T. 
Published: March 2010

Abstract
The VAPEX analytical model is extended to cover situations when diffusion coefficients are dependent on concentration due to the extreme viscosity reduction with solvent dissolution into bitumen. The new analytical model covers such situations along with the cases in which the diffusion coefficient and viscosity relate to each other under the Stokes-Einstein law. In the process, a new concept of the 'average flow fraction of bitumen' in the flowing mixtures is introduced.
The modelled result on overall functionality of the drainage rate of bitumen has confirmed the square-root relationships to most of the key reservoir parameters as the previous theories indicate. However, its dependence to the inverse of kinematic viscosity at the interface is closer to linear rather than square-root correlation with the concentration-dependent diffusion coefficient. The theoretical relationships are confirmed by the correlations of the unified bitumen rates to kinematic viscosity at the interface using the existing VAPEX and SAGD experimental data in the literature. This finding indicates that VAPEX process in heavy oils with lower native viscosity can be more effective than originally recognized.

Introduction
Dunn et al.(1) developed the theoretical model of the gravity drainage process for bitumen recovery known as VAPEX based on the model of the steam-assisted gravity drainage (SAGD) process by Butler et al.(2) This model assumed that the diffusion coefficients of solvent-bitumen systems are constant similar to the case of thermal diffusivity. Thus, the steady-state profiles of solvent concentration ahead of the solvent-bitumen interface is the smooth exponential decay towards an infinite distance. In reality, the diffusion coefficients of both solvent and bitumen are strongly dependent upon compositions due to the extreme viscosity contrasts between the solutes and solvents. As a result, the observed concentration profiles in diffusion experiments exhibit the abrupt front-end profiles(3). The theoretical endeavour here is to understand the impact of the non-exponential concentration profiles on the VAPEX drainage and bitumen rates.

Governing Mechanisms
The most fundamental mechanism of the process is the gravity drainage caused by the density difference between the liquid-bitumen phase and the injected vapour phase. The drainage flow of the bitumen phase occurs only from viscosity reduction due to the impact of the injected solvent (or heat in the case of SAGD) of the otherwise semi-solid bitumen. Therefore, how the injected solvent penetrates into the bitumen phase in the reservoir is of primary importance to the process. According to Fick's law, a material balance across a differential distance, dx, in this situation can be expressed as a continuity equation for the change of concentration (volume fraction is chosen), C, with time, t, by using the diffusion coefficient, D:
Equations (available in full paper)
Cutting Efficiency of a Single PDC Cutter on Hard Rock
Authors: Hareland G. , Nygaard R. , Yan W. , Wise J.L. 
Published: March 2010

Abstract
Polycrystalline diamond compact (PDC) bits have gained wide popularity in the petroleum industry for drilling soft and moderately firm formations. However, in hard formation applications, the PDC bit still has limitations, even though recent developments in PDC cutter designs and materials steadily improves PDC bit performance. The limitations of PDC bits for drilling hard formations is an important technical obstacle that must be overcome before using the PDC bit to develop competitively priced electricity from enhanced geothermal systems, as well as deep continental gas fields. Enhanced geothermal energy is a very promising source for generating electrical energy and, therefore, there is an urgent need to further enhance PDC bit performance in hard formations.
In this paper, the cutting efficiency of the PDC bit has been analyzed based on the development of an analytical single PDC cutter force model. The cutting efficiency of a single PDC cutter is defined as the ratio of the volume removed by a cutter over the force required to remove that volume of rock. The cutting efficiency is found to be a function of the back rake angle, the depth of cut and the rock property, such as the angle of internalfriction.
The highest cutting efficiency is found to occur at specific back rake angles of the cutter based on the material properties of the rock. The cutting efficiency directly relates to the internal angle of friction of the rock being cut.
The results of this analysis can be integrated to study PDC bit performance. It can also provide a guideline to the application and design of PDC bits for specific rocks.

Introduction
PDC bits have gained popularity in drilling for petroleum due to its long bit life together with its ability to maintain a high rate of penetration (ROP). The shearing action induced by fixed cutters has shown to be more efficient for penetrating rock than the crushing effect of the teeth or inserts on the rolling cones of a roller bit(1–4). However, PDC bits have traditionally had limitations when encountering hard formations(5). Therefore, PDC bits are not yet preferred for hard formations encountered with mining, petroleum or geothermal energy. Enhanced geothermal energy, i.e., geothermal energy from considerable (+3 km) depths, is seen as one of the promising energy sources in the U.S.(6) Deep continental gas developments also suffer from a low rate of penetration and high bit wear for wells drilled.
The objective of this paper is to develop an analytical model to study the cutting efficiency of PDC bits in hard rock formations which can improve the future design of PDC bits and, thereby, improve the cost efficiency of wells in hard formations.

PDC Bit
Most PDC bits are composed of a hard matrix body which is milled out of a solid block of steel. The matrix body is milled out in such a shape that the bits contain blades where the actual PDC cutters are 'glued' or 'braced' on, and open areas where the cuttings and mud flow can escape to the annulus (Figure 1).
The Impact of Pressure Drop on SAGD Process Performance
Authors: Thorne T. , Zhao L. 
Published: March 2010

Abstract
Pressure drop along the horizontal wells and between the injector and producer could have a significant impact on SAGD process performance. However, this issue is poorly understood due to difficulties in simulating pressure drop. This paper presents the results of a numerical study on the topic.
When pressure drop between the injector and producer exists, the downhole vapour production rate must be increased significantly. Without adequate vapour production, the oil production rate is lower and SOR is higher. Increasing the vapour production rate may affect pad facility design as more vapour handling capacity is required under these conditions.
On the other hand, pressure drop inside the injection well may also alter steam distribution. However, the impact on oil production is limited as steam can move relatively easily inside the steam chamber. In the present case, oil production is reduced by approximately 5% when a pressure gradient along the injection well is considered.

Introduction
Steam-Assisted Gravity Drainage (SAGD), a thermal process that involves the application of steam and the use of horizontal wells, is a bitumen recovery method used in the Athabasca Oil Sands. The most common implementation involves the use of two horizontal wells drilled parallel to one another with a vertical separation distance of about 5 m. The upper well is known as the injector and the lower well is known as the producer.
Through the operation of commercial projects, it has been observed that once steam is injected into the reservoir, a pressure gradient is observed along and between the wells. There have been a number of publications addressing this issue(1, 2).
As the SAGD process has been applied to more locations in recent years, considerable interest has been generated around the topic of pressure drop and its effect on SAGD process performance. It is generally understood that a pressure drop across or along the wellbore could result in wells with a non-uniform steam chamber, a reduced effective wellbore length, liquid build-up above the production well or reduced oil production rate.*
When a new reservoir is developed, a great effort is required to understand the reservoir characteristics and how to incorporate them into production forecasting models. Petro-Canada is currently expanding their MacKay River project and, in order to develop a better understanding between pressure drop and oil productivity, the field data from their existing project was analyzed so that recommendations could be made to increase the project's productivity.
One factor that needs to be addressed for drilling and completion planning is the wellbore size. Larger wellbore size results in more uniform steam distribution in the injection well and increased productivity from the production well. However, a larger wellbore size incurs a higher cost.
In some existing wells, it was found that liquid build-up was occurring due to limited lifting capacity. In addition, a larger pressure drop between the injector and the producer has been observed.
A Rapid Approximate Method for the Estimation of Hydrocarbon Dew Points of Clean Pipeline Natural Gases
Authors: Aziz K. , Govier G.W. 
Published: March 2010

Abstract
A "theoretical" correlation of the effect of pressure on the hydrocarbon dewpoint temperature of clean pipeline gases is presented. The correlation wasdeveloped from calculated dew point data on thirteen gas analyses from ten gasfields in Alberta. The dew points were calculated by conventional trial anderror method and NGAA equilibrium ratio charts. The data are correlated bymeans of a wetness parameter based on the amounts of propane and heaviercomponents in the gas and equilibrium ratios for those components atarbitrarily selected conditions.
The correlation allows the quick estimation of the hydrocarbon dew points ofclean pipeline gases without the usual trial and error procedure. For moreaccurate results the dew points calculated from this correlation may be used asthe first estimate in the conventional trial and error calculations. Thecalculated dew points are usually within +4°F of the results from conventionalcalculations over the normal range of pipeline operating pressure and, forpipeline natural gases free of contaminants, such as glycol or compressor oil, are within about the same limits when compared with measured dew points.
The correlation does not apply to the prediction of dew point temperaturesfor pipeline gases containing even small quantities of alcohol, glycol orcompressor oil.

Introduction
Pipeline natural gases, which are composed mainly of a mixture of paraffinhydrocarbon gases, nitrogen, carbon dioxide and water vapor, normally exhibittwo kinds of dew points. These are hydrocarbon dew points and water dewpoints.
The dew point is the temperature, at a certain pressure, at which the firstdrop of liquid is formed or is just about to form. In the case of water dewpoints, the liquid formed is water and in the case of hydrocarbon dew pointsthe liquid formed is a mixture of the hydrocarbons contained in the gas. If apipeline gas, as a result of processing, contains contaminants such as glycol, a third type of dew points may also be observed. The liquid formed in this casewill be a mixture of hydrocarbons and the contaminant. Because of the higherboiling point of the contaminant, the presence of this component in the gaswould raise the dew point temperature. Small amounts of nitrogen, carbondioxide and other non-hydrocarbon constituents may also be present in the dewformed, depending upon the concentration of these components.
Petrogas Processing Calgary Plant
Authors: Manley H.W. , Lewis G.H. 
Published: March 2010

Abstract
Thirty Corporate Oil &Gas Working Owners in the Calgary Gas Fieldsbecame shareholders of Petrogas Processing Ltd. for the purpose of establishinggas plant processing facilities to process their combined gas reserves of inexcess of 1500 billion cu. ft. Jefferson Lake Petrochemicals has been appointedthe Operator of the Petrogas Plant Facilities.
This $13,000,000 Plant facility consists of some 135 miles of field pipeline systems; a gas purification section design for 150 million cu. ft./daycapacity utilizing the Hot Potassium and Conventional Amine treating processes;a modified Claus process to produce 875 long tons/day of elemental sulphur; aconventional refrigeration unit for 125 million cu. ft./day of pipe line gasdelivery to meet water and hydrocarbon dewpoint specification; and, a 2200bbl./day liquid condensate stabilization unit.
The combined plant inlet gas streams have approximately 24% acid gas, or 16%hydrogen sulphide and 8% carbon dioxide. The use of the Hot Potassium gaspurification section is proving very satisfactory for extracting a large partof the acid gas having this ratio of acid gas volumes. The plant design hasresulted in lower capital costs, less gas fuel consumption and comparativelylittle chemical losses as compared to other gas processing plant designs in Canada.
Glycol pipe line delivery and gathering systems to and from each wellheadfor gas dehydration in the fields is used whereby central plant regeneration ofthe glycol can be obtained. This type of functional design will reducecorrosion in the gas gathering systems and prevents excessive gas hydratesoccurring at the 1200 psia gas gathering pressures. With the Crossfield gasfield now having proved 81.4 square miles and the Elkton gas field havingproved 47.7 square miles of productive area, the field gas dehydration designcapital cost has proved to be comparatively low for the five Elkton gas wellsand eight Crossfield wells now connected to the Plant. As additional gasproducing wells are completed in these large fields, the unit cost/wellheaddehydration will continue to be reduced.
Prediction of Miscibility
Authors: Adamson J.A. , Flock D.L. 
Published: March 2010

Abstract
Recent studies of the mechanisms involved when a reservoir fluid isdisplaced miscibly by a light hydrocarbon mixture have resulted in thedevelopment of theoretical methods to predict the approximate conditionsnecessary in order that miscibility may occur. One of these methods employs theuse of a pseudo-ternary diagram and requires the calculations of the criticaltemperature and pressure of both the displacing and displaced phases.
Preliminary and theoretical studies have been conducted in an attempt toverify the theoretical considerations involved in this particular method aswell as to modify the procedure by employing newer means of calculatingcritical conditions.
In conjunction with this study a unique method of recording pressureprofiles as a function of time during an actual miscible displacement has beendevised. This paper presents and discusses some of the results obtained in thisproject.

Introduction
Miscible displacement of reservoir oil depends upon the formation of agraded saturation bank between the original oil in place and the injecteddisplacing fluid. This bank is all in a single phase with no interfaces presentand therefore they are no capillary forces to cause the oil to be retained inpore channels as residual oil. This situation can be achieved by employing oneor more different methods; namely solvent flooding, LPG slug process, highpressure gas drive or condensing gas drive.
Three of the factors which influence the efficiency of miscible drives arethe reservoir temperature and pressure and the composition of the injectedfluid. A certain pressure for a given temperature must prevail to maintainmiscible conditions between oil and injected fluid. Proper requirements forpressure control of the reservoir must therefore be known in advance ofcommencement of a project for properly controlled miscible drive operations.The intermediate composition of the injected gas must also be controlled suchthat the composition will be a critical one and miscible drive can beachieved.