bluuebunny/crossref_metadata_2025_split huggingface dataset:
Decentralized Continuous-flow Gas Anchor
Authors: Podio A.L. , Mccoy J.N. , Drake B. , Woods M.D. 
Published: March 2010

Abstract
A new gas separator has been developed and successfully field-tested in more than 40 beam pumped wells which were subject to severe gas interference.
The new design is based on several innovations:Decentralization of the gas separator in the casing ensures that a maximum amount of liquid enters the separator.The presence of two or more ports on the gas separator near where it touches the casing wall.Construction of the gas separator so that the outer tube of the gas separator is pressed against the casing wall to prevent cross-flow of liquid and gas.The addition of a diverter at the bottom of the separator to direct most of the gas flow, towards the wide side of the annulus.
These innovations have resulted in a gas separator efficiency much greater than that of conventional designs.

Introduction
Numerous studies have been performed in recent years in an attempt to improve the performance and efficiency of a beam pumped system [see References (1) through (8)]. The studies include the motor or power unit, the surface pumping system, the rod string and the downhole pump. In wells which produce gas, the inefficient separation of gas from liquid at the pump inlet often results in very poor pump performance and low overall efficiency of the entire pumping system. This can be verified by obtaining a dynamometer pump card which indicates considerable free gas in the pump even though liquid is present in the casing annulus in the form of a high gaseous liquid column.

Terminology
When discussing downhole gas separators in pumped wells, there appear to be various terms which are used indiscriminately: gas anchor, mud anchor, dip tube, perforated sub, etc. In order to avoid confusion, the terminology adopted in this paper is as follows:Gas Separator: The complete assembly of elements installed below the seating nipple and the pump intake with the purpose of maximizing the amount of liquid entering the pump.Outer Barrel: The outermost element of the gas separator which is connected to the tubing (often called mud anchor).Dip Tube: The innermost element of the gas separator which is attached to the pump intake (often called gas anchor).

Natural Gas Separator
The preferred technique for separating gas from the pump is to place the tubing fluid entrance ports (or gas separator ports) below the bottom of the formation's perforated interval as shown in Figure 1. The natural separation of gas and liquid by gravity will result in relatively gas-free liquid entering the pump intake if the downward liquid velocity in the casing/tubing annulus is less than approximately 6 in./sec. The gas separator inlet should be placed at least l0ft. below the formation gas entry zone to allow free gas separation from liquid between the tubing outer diameter and the casing inner diameter See Table 1 for natural gas separator capacities.
For greater capacity, it is necessary to use a modified gas separator with an outer diameter smaller than the tubing (see Figure 2).
Effect of Gravity On Movement of Water-oil Interface For Bottom Water Driving Upwards to a Horizontal Well
Authors: Butler R.M. , Jiang Q. 
Published: March 2010

Abstract
In a previous paper from our laboratory, an equation was developed to predict the movement of the water-oil interface produced by bottom water driving upwards to a horizontal well; the oil and water were assumed to have the same viscosity and density. If the oil has a lower density than the water, as is usually the case, the interface will be flatter due to the effect of gravity. This will improve the performance. In the present study, the effect of gravity on the movement of the interface and on the oil recovery has been studied physically and theoretically. The new theory allows the effect of gravity to be included.
Two sets of experiments were carried out in a Hele-Shaw cell to investigate the effect of gravity on the movement of the water-oil interface. The first set involved upward displacement of oil by bottom water to a horizontal well. It was found that the higher the flow rate, the lower the oil recovery at breakthrough even when the two fluids have the same viscosity. This effect is caused by gravity. In the other experiments, a water crest established previously in the Hele-Shaw cell was allowed to fall driven by gravity alone, with both the injection and production wells shut in. The interface fell at the centre and rose at the two ends and thus became progressively flatter. The interface was photographed periodically.
Analytical and numerical studies were carried out to predict the movement of the fluids. The predictions from both techniques are in agreement with the experimental results. These equations can be used to predict the relaxation of water crests in the field and a numerical example is given.

Introduction
Gravitational segregation due to the density difference between displacing and displaced fluids is one of the important factors affecting oil drainage from the reservoir. The overriding of the injected gas or steam and the down-flow of injected water, for example, usually reduce the vertical sweep efficiency. In some cases, the effect of the net gravitational force to assist the oil drainage has been utilized commercially for both conventional and heavy oil reservoirs. The process of steam-assisted gravity drainage (SAGD)(1,2,3,4) by using a horizontal production well at the bottom of the reservoir, with either a parallel horizontal injection well or several vertical injection wells located above in the reservoir, has been applied successfully to the tar sands in AOSTRA's UTF project in Fort McMurry, Alberta, and to the Tangleflags North heavy oil reservoir in Saskatchewan. The Vapex process(5), which uses a vapourized hydrocarbon to extract the bitumen, is an analogue to SAGD but a non-thermal process. Downward displacement of oil from the depleted reservoirs by gas cap or injected gas(6) is another example to take the advantages of the density difference between gas and oil phases.
Gravitational forces can act as either a de-stabilizing force or a stabilizing force for the interface(7), depending on the sequences of two fluid layers.
Gas Production Modelling-A Case Study
Authors: Smith Steven 
Published: March 2010

Computer models are increasingly used in production optimization of gas fields because they offer a practical way to detect all potential bottlenecks. A single model takes into account reservoir performance, sandface inflow performance, well bore pressure losses, gathering system pressure losses, and field facility performance. Furthermore, many scenarios can be quickly evaluated without incurring significant expense.
This article presents a case study of an actual Alberta gas-condensate field evaluated with computer models three times over the course of more than a year.

February 1996–0riginal Model
A study was commissioned by the minor partner in an Alberta gas-condensate field when the major partner wanted to install additional compression in hopes of accelerating drainage in a competitive situation. The minor partner, whose share of the cost was expected to be approximately $250,000, doubted the value of installing the compressor.
Field A included a plant with compression, three wells, and the associated gathering lines (see Figure 1). Each well is completed in a tight Glauconite formation and all wells were thought to be in competitive drainage with Field B to the south and west.
Reservoir Characterization
A review of the static bottomhole pressures (BHP) for the wells in Field A suggested that the three wells did not share a common pool. On May 29, 1995, the static BHPs of Wells A, B, and C respectively, were 11.79 MPa, 11.59 MPa, and 8.27 MPa. On September 12, 1995, the static BHPs of the three wells were 11.73 MPa, 11.56 MPa, and 8.03 MPa respectively.
Static BHPs for Wells A and B were both below the expected initial reservoir pressure for the Glauconite formation. While the pool may have experienced some drainage, the pressure decline over 106 days, as noted above was very small and close to recorder accuracy. It seemed unlikely that there was any significant drainage during this period. Wells A and B were modelled as sharing a common pool (Glauc AB) with no competitive drainage.
Reserves for the Glauc AB pool were calculated by both material balance and the volumetric method. The original gas in place (OGIP) calculated by material balance was 160 E6m3. The OGIP calculated by the volumetric method, based on an assumed areal extent of two sections, was 500 E6m3. As a conservative estimate an OGIP of 160 E6m3 was initially assumed for this pool.
Well C static BHPs were also below the expected initial reservoir pressure of the Glauconite formation. Unlike the Glauc AB pool, this pool continued to exhibit some drainage, with a modest pressure decline of 242 kPa over 106 days during which Well C was not producing.
As an example of the observed pressure variations across Field B, a well in the extreme south of Field B had a measured static BHP of 11.80 MPa in July 1971, while a well adjacent to Well C had a measured static BHP of 11.84 MPa in October 1981. Although Well C may be in communication with wells in Field B, pressure data like those noted above suggested that the communication was not strong.
Prediction of Gas Phase Volumetric Variations In Diphasic Reservoir Oils
Authors: Varotsis N. 
Published: March 2010

Abstract
The gas and liquid phases present in diphasic mixtures often have distinctly different physical properties. Hence, the ability to predict the changes in their relative saturation as the conditionsvary during their flow in a conduit or in the porous media is highly desirable.
This work presents analytical expressions relating the gas phase volume variations with physical properties of the reservoiroils. It was established that the gas phase volume variations, as pressure changes, can be correlated with the saturation pressure of the fluid and the dimensionless pressure regardless of thetemperature and the kind of fluid at conditions far from the critical state. These equations proved to provide the volume variations with remarkable accuracy and can be applied to surface separation processes, surface multiphasic pumping and flowmetering and e prediction of variations in the phase saturation in the reservoir.

Introduction
In several petroleum engineering applications gas and oil coexist, having established equilibrium either in the pores of the reservoir or as they flow in the production tubing or t1rrough the pipes and the surface separation unit. As a result of the reservoir depletion or of the fluid flow, the pressure of the system varies with time and distance. Hence, it is considered useful to be able to estimate the influence that the pressure change bears on the gas phase volume, acting both with the compressibility of the gas and with the incremental volume of the condensed liberated gas. This piece of information helps to evaluate variations of the fluid saturationsn the reservoir and the possible displacement of fluid interfaces, under certain conditions, during depletion or prolonged testing. For the applications concerning the flow at the surface, it can be used to determine the variations of the flowrates of each phase and consequently, the phase cuts as the stream passes through valves and restrictions and is subjected to subsequent pressure drops. The prediction of the gas void fraction (GVF) at operating pressure is reported as a key parameter in the design of the recently developed subsea multiphase pumping systems (1).
The change of the gas phase volume can be quantified in two ways:as the fractional change that the fraction Vfg of the total volume of a mixture occupied by the gas phase undergoes as the pressure drops:Equation (1) Available In Full Paper.as the fractional change of the gas volume Vg of a mixture as the pressure changes:
Equation (2) Available In Full Paper.
The first expression relates the change of the gas volume to the total volume of the mixture and is used to express the change in the gas phase cut. The second expression, however, deals exclusively with the changes in the volume of the gas phase and is used to express the incremental volume of gas available in the system. Obviously the fractional changes of Vfgand Vg obtain the same values when a given mass of a mixture continues to occupy practically the same volume (Vt1, Vt2 even after it was subjected to a pressure change Δp.
Atlantic No. 3 1948
Authors: Kerr A. 
Published: March 2010

Abstract
Atlantic 3 was to be the signal for the world to really understand the fury of the new hitherto unknown Devonian reef which catapulted Alberta into the oil age. The above date marked the "point of no return" for what should have been the completion of this otherwise ordinary development well. That was the day Atlantic No. 3, just one mile east of Imperial's 1947 discovery well, blew out of control. It would continue its wild caper until Labour Day 1948 when the well caught fire sending media shock waves literally around the world.
The drama of Atlantic No. 3 - 1948 began shortly after Imperial's Devonian discovery in the spring of 1947 when Frank McMahon, a down and out promoter, somehow or other detected a flaw in a quarter section freehold title leased to Imperial Oil. Imperial's drilling of their step-outs No. 3 and No. 4 virtually proved up this parcel (NW 23-50-26-W4M). Frank with his optimistic stance paid the Rebus family over #x0024;200,000 bonus (where he obtained the funds is a mystery). His company, Atlantic Oils, then hired a contractor (Cody Spencer, also on the edge of bankruptcy) to drill up the lease with an old steam rig.
Atlantic No. 1 and No. 2 were completed as D-3 oil wells without incident, providing Frank with much needed revenue. The rig then moved over to No. 3 wellsite, spudding in, January 21, 1948. Only 300 feet of surface casing were set. When the hole reached the D-3, severe loss of circulation prevented the deepening to the production casing point. Many cement plugs later (none of them successful), the decision (not unanimous) was to "drill dry" (using water) hoping to make a run for the casing point. The bottom dropped out of the water column and No. 3 blew out March 8, 1948, spewing 15,000 bbls/day over the frozen ground.
The next two months were spent trying to kill the well. Finally with pressure from Imperial Oil (they owned 80% of the reservoir) the Conservation Board bit the bullet, seized the well on May 12 and retained V.J. "Tip" Moroney to take complete charge over the project. Tip was a veteran of hole problems in South America. In January 1948, he had just been transferred (providently!) to Imperial's Calgary office. Quoting Tip: "I said I would take the job if I was to be absolutely in charge." He immediately contracted two more steam rigs with a remote boiler location and drilled two directional holes to intersect Atlantic No. 3 pay zone.
After many trials and tribulations (much of it self-inflicted) the two relief wells whipstocked their way to near their D-3 targets. West Relief ran casing and started pumping 36,000 b/d of water from the North Saskatchewan. This watered out the formation. The wild well caught fire Labour Day, September 6, and only burnt three days-but it was a spectacular fire, the word travelling around the world.
Effect of Nitrogen On the Solubility And Diffusivity of Carbon Dioxide Into Oil And Oil Recovery By the Immiscible WAG Process
Authors: Nguyen T.A. , Ali S.M. Farouq 
Published: March 2010

Abstract
In the immiscible displacement of oil by carbon dioxide gas, the solubility and diffusivity of carbon dioxide are important factors that determine the efficiency of the process, because an increase in the carbon dioxide solubility and diffusivity into oil leads to an increase in oil recovery. It is shown by experimental studies that the solubility and diffusivity of carbon dioxide into oil are governed by the saturation pressure, reservoir temperature, composition of the oil and purity of the gas. The solubility and diffusivity of carbon dioxide into Aberfeldy heavy oil were measured, using impure carbon dioxide gas containing nitrogen as the main contaminant gas. It was noted that increasing the concentration of nitrogen in the carbon dioxide stream decreased the solubility and diffusivity of carbon dioxide in oil, consequently leading to a reduction in the swelling of the oil by carbon dioxide.
Displacement experiments were also conducted to observe the effect of using impure carbon dioxide in place of pure carbon dioxide in the immiscible displacement WAG process. It was noted that the presence of nitrogen in carbon dioxide adversely affected oil recovery by the process and that increasing the nitrogen concentration up to 30 mole% could result in 10% loss in oil recovery.

Introduction
The solubility of carbon dioxide is the most important effect in the immiscible displacement of oil by carbon dioxide gas since it was found by Rojas(1) that among other mechanisms, an increase in the carbon dioxide solubility in oil leads to an increase in oil recovery. This is true because the solubility of carbon dioxide greatly reduces the viscosity of the oil and promotes the swelling of the oil. Viscosity reduction and swelling of the oil lower the water-oil mobility ratio, consequently leading to an increased oil recovery.
Early work in 1926 by Beecher and Parkhurst(2) showed that carbon dioxide was more soluble on a molar basis in a 30.2 °API oil than air and natural gas. Svreck and Mehrota's data(3) for carbon dioxide, methane and nitrogen showed that and Mehrotra's data(3), carbon dioxide is the most soluble and nitrogen the least soluble in bitumen.
The solubility of carbon dioxide in oil is governed by the saturation pressure, reservoir temperature, composition of the oil and purity of the gas. Miller and Jones(4) and Chung, Jones, and Nguyen(5) measured the solubility of carbon dioxide in Canyon and Wilmington heavy oils and found that the solubility of carbon dioxide in heavy crude oils increased with pressure but decreased with temperature and reduced API gravity. Briggs and Puttagunta(6) reported sets of data for carbon dioxide solubility in Aberfeldy oil and swelling of oil at 20.6 °C. Their data showed that both carbon dioxide solubility and oil swelling increased when pressure increased. Later, Sayegh and Sarbar(7) established that carbon dioxide is more soluble in oil at lower temperatures than at higher ones.
Oil Recovery From Tarmat Reservoirs Using Hot Water And Solvent Flooding
Authors: Okasha T.M. , Menouar H.K. , Abu-Khamsin S.A. 
Published: March 2010

Abstract
The existence of tar accumulations (tarmat) beneath the oil zone in some reservoirs creates productivity problems through restricted aquifer support during the primary recovery stage. It also affects the performance of peripheral water injection when the tar/oil boundary is irregular.
The objective of this study was to investigate and evaluate combined solvent and hot water injection beneath the tarmat to improve aquifer support by displacing and dispersing the tar. Displacement runs were conducted in one-foot long Berea sandstone composite cores, simulating a tar zone and an oil zone in series, at injection rates of 1 ml/min. and higher.
The results show that although the oil recovery from hot water displacement is lower than cold water displacement in the absence of tar, the gain in recovery for hot water over cold water is substantial in the presence of tarmat. Driving a slug of solvent with hot water to displace tar increases the hydrocarbon recovery even further. However, for each of the two solvents studied, there is an optimum slug size with which the hydrocarbon recovery is maximum. Moreover, the recovery was found to increase further when the optimal slug is divided into portions separated by small slugs of hot water.
The injection rate had a profound effect on the recovery for all hot-water flooding schemes. The results showed consistently that the recovery increased at lower injection rates.

Introduction
Many oil reservoirs are characterized by the presence of a highly viscous hydrocarbon layer (tarmat) at the oil/water contact. Such tarmats are found in many major oil reservoirs in the world and, particularly, in the Middle East. They are reported in the literature to vary widely, ranging from highly viscous hydrocarbon fluids to near solid materials(1). The thickness of the tarmat varies from place to place in the same reservoir and sometimes reaches few hundred feet; while their extent can reach several kilometres. In Ghawar field, for example, the tar zone extends more than 25 km and reaches up to 150 m in thickness(2).
Several geochemical studies presented by various authors attribute tarmat formation to gravity segregation which leads to a compositional grading with depth(3–5). Depending on reservoir conditions and tar viscosity, field experience shows that some of these tarmats can become mobile under conditions of moderate differential pressure(2).
The presence of tar deposits at the oil/water contact in a tarmat reservoir can have serious adverse effects on the effectiveness of natural water drive as well as secondary recovery projects. When the tarmat completely surrounds the oil zone, the oil reservoir behaves like a finite lens where the pressure decreases rapidly as soon as the first well starts producing. This leads to an alarming increase in gas/oil ratio during the primary stage of depletion which has been the case with Minagish reservoir in Kuwait(2). Another such example is El Bundug reservoir in Qatar(6).