bluuebunny/crossref_metadata_2025_split huggingface dataset:
Characterization Of Formation Damage By Particulate Processes
Authors: Millán Arcia Einstein , Civan F. 
Published: March 2010

Abstract
A model-assisted analysis of formation damage in the S and S3 facies of the Eocene B-Inferior formation in Ceuta field, Lake Maracaibo, western Venezuela, is carried out. The governing mechanisms and the estimated values of the phenomenological rate constants are determined using the formation damage model by Ohen and Ciyan. A skin factor chart is constructed based on this information as a practical measure of the formation damage potential.

Introduction
Reduction of injectivity of wells by formation damage can be of considerable magnitude during waterflooding of oil reservoirs. The origin of formation damage can be of chemical and mechanical caused by interaction between porous media and fluid flowing through it. Chemical damage occurs due to the incompatibility between the constituents of mineral rock and the flowing fluids. Mechanical damage can he caused either by external particle invasion, as in the case of suspended particles in completion fluids, or internal particle movement mainly influenced by hydrodynamic forces. Variation of pH of the flowing fluid is an indicator of the extent of chemical activity occurring in the formation. Dissolution of cementing - authigenic materials such as carbonates and/or ion exchange between fluid and minerals can cause pH variation, High pH (alkaline media) promotes formation damage by particle deposition within the porous media and consequently particle bridging at the pore throats. Occasionally, the particle bridges brake causing temporary permeability increase. This is reflected by the pulsating character of the pressure differential and permeability reduction data. Permeability reduction and skin factor are used as quantitative measures of formation damage. A detailed description of the processes involving formation damage of porous media is given in the literature(l-14).
This paper presents a model-assisted anaIy;is of formation damage in sandstone core samples belonging to the facies S and S3 of the Eocene B-Inferior formation, in Ceuta field, Lake Maracaibo, western Venezuela. The details of this study are given by Millan(l5) Due to the high content of carbonaceous and siliceous type authigenic materials the Ceuta field core samples are extremely sensitive to brine, rendering the pH toward alkaline media during waterflooding. As a result particles tend to disperse to reduce the formation permeability. Permeability alteration process is numerically reproduced by means of the Ohen and Civan model(l2) and extended beyond the experimental range. The values of the phenomenological rate constants involving the hydrodynamic and electrochemical processes, which controls the trapping and/or release of particles within the porous media, are determined and a skin factor chart is constructed using the Ohen and Civan method(13).
Non-Newtonian Effects On The Primary Production Of Heavy Oil Reservoirs
Authors: Poon D. , Kisman K. 
Published: March 2010

Abstract
A number of heavy oil and oil sand reservoirs in Alberta have been successfully produced by natural depletion at rates far in excess of the predictions based on radial Darcy flow. Production rates can exceed 20 m3/d and con be maintained at such a high level for several years. What exactly causes the high primary production rates is not known, but several mechanisms on the primary production of heavy oil and bitumen have been proposed by various authors. These include solution gas drive, influx of bottomwater, sand production, wormholes, fractures and channels. Laboratory measurements which have been reported on the rheological properties of bitumen indicate that at low temperatures (e.g. 20 °Cj a mixture of bitumen or heavy oil with a small amount of sand behaves as a non-Newtonian fluid. The flow characteristics of a non Newtonian fluid in a reservoir and their effects on the primary production of heavy oil have been investigated in this study using ana/ysica/ solutions of the diffusivity equation. It was found that di/atant (shear thickening) effects can provide an explanation for low apparent viscosities at a distance from the wellbore where shear rates are low. This mechanism is consistent with the pressure buildup test results and with field production data where high production rates can be sustained over an extended period of time.

Introduction
A number of heavy oil and oil sand reservoirs in Alberta and Saskatchewan have been successfully produced by natural depletion. Primary recovery at the Lloydminster heavy oil deposit, which began over 40 years ago, has been significantly higher than the predictions based on radical Darcy flow. The heavy oil deposits in this area are relatively thin (3 m to 6 m) and occurring at depths from 300 m to 1000 m. The formations consist of unconsolidated sands with a relatively high porosity (29% to 35%) and high permeability (3500 mD). The oil gravity is quite low ranging from 10 to 20 degrees API with an oil viscosity of 400 mPa.s to 2000 mPa.s at initial reservoir conditions.
Since 1985, Amoco have been producing significant amounts of bitumen from the Lindbergh Elk Point(1) area on primary production. The Clearwater formation at this location is 25 m to 30 m thick and consists of a moderately well sorted sand. The bitumen has a gravity of about 12 degrees API and a very high viscosity of 60 000 mPa.s at reservoir conditions (3900 kPa and 2O °C). The primary production rates average 15 m3/day 00 20 m3/day for over 3 years. These production rates are greater than can be predicted with radial Darcy flow calculations by a factor of more than 30.

Potential Mechanisms
It is not known what exactly causes these high primary production rates but a number of potential mechanisms have been suggested. in the literature: solution gas drive; influx of bottomwater; sand production; wormholes, fractures and channels; and rock compressibility.
Smith(2) suggested that a possible production mechanism could be solution gas drive which was assisted occasionally by the influx of water.
"Honey, I Shrunk the Pores!"
Authors: Beliveau Dennis 
Published: March 2010

Introduction
When I was young, my parents instilled in me a curiosity about the physical nature of the world. I remember Dad, an avid reader of "The Country Guide," explaining the enormous power or a prairie thunderstorm by telling me "an inch of rainfall on all acre of land is over one hundred tons of water." To bring this analogy closer to our own business, it still amazes me that a reservoir one foot thick with ten per cent porosity will also hold almost one hundred tons of oil per acre of land. Sometimes we get so bogged down by the details of our business, we don't have time to think about some of nature's simple wonders.
With thoughts like these in mind, it's neat to take a closer look at a parameter which is taken very much for granted: porosity. To ost of us, the only thing which matters is the absolute value of porosity, and obviously the higher the better! Some interestinghenomena pop to light, however, when one really visualizes things on a pore-scale. With that in mind, let's take closer look at some porous systems from the inside...

Conventional Pore Systems
Let's quickly review some basic geometric concepts, focussing at the pore-scale. Table 1 shows how Archie(1) and Lucia(2) classified carbonate pore sizes: a typical "medium"-sized pore is about 50 microns (0.002 inches). Pore throats, the inter-pore connections which determine permeability, are much smaller, often in the 1-10 micron range. Obviously, it takes an enormous number of these pores to form a reservoir. We also know that the size of the individual pores may not have much impact on the total porosity. Figure 1 shows the porosity resulting from a cubic arrangement of spherical grains is 48%, regardless of the size of the grains.owever, for a given porosity, the pore system surface area increases as the average pore size decreases (Table 2).
The surface areas in Table 2 assume pores are spherical: however, in reality their shapes are much more complex. As a result, urface areas in reservoir rocks may be 100 times higher than shown in Table 2 due to tile dramatic effects of surface roughness.good example is Donaldson's work(3), which showed the
TABLE 1: Pore size classifications. Table Available In Full Paper.
TABLE 2: Ways to make 11% porosity in 1 m3 of rock. Table Available In Full Paper.
surface area of many common reservoir rocks to be about 1 m2/gm.
These large surface areas are rather startling at first glance.
Imagine one cubic metre or oil-saturated rock with 11% porosity. Table 2 shows the resulting 0.11 m3 of oil would be spread over 10,000m2; accounting for pore surface roughness the area would actually be about 1,000,000 m2. To put it in more real terms, this would be like spreading a couple of cups of oil across the surface of a foothall field. Is it any wonder that oilfield recoveries average only about 25%?
Numerical Simulation of Electromagnetic Heating of Alaskan Tar Sands Using Horizontal Wells
Authors: Wadadar S.S. , Islam M.R. 
Published: March 2010

Abstract
In an effort to develop a novel recovery technique for tar sand reservoirs of Ugnu in Alaska, electromagnetic heating using horizontal wells is proposed. One of the bigger technical problems with thermal injection on the North Slope is the large permafrost region. The permafrost reduces the effective heat that can be transmitted to a reservoir, even with insulated tubing. Applying the heat with a down-hole device, such as electromagnetic heating is a much more efficient process than conventional thermal recovery techniques. The horizontal well addresses another problem by heating and producing from the same well bore. The drainage radius is normally very limited due to the inability to conduct or convert heat away from the wellbore. A horizontal well, particularly one located at the bottom of a thick sand with vertical permeability, allows gravity drainage of a much larger reservoir volume. This paper presents numerical simulation results of such a process for Alaskan tar sand reservoirs using a horizontal well simulator. Numerical simulation results show oil recovery as high as 40% of the oil in place for tar sands. The recovery is even higher for heavy oil of moderate viscosity.

Introduction
The state of Alaska is estimated to contain some 70 billion barrels of oil in place. More than 50% of this reserve is in the form of heavy oil and tar sand in the Alaskan North Slope(1). Some 15 billion barrels of this reserve is in the form of tar sand in the Ugnu reservoir of the North Slope.
With recent decline in oil production from the Prudhoe Bay light oil reservoir, there is a need to develop techniques for expanding oil production from other oil resources of Alaska. One such reservoir is the tar sand of Ugnu.
Oil in the Ugnu reservoir was discovered by BP in the eastern region in the range of 828–994 m depth. Ever since the original discovery, there have been several drilling activities in the area during the 1970's. The Ugnu sand is divided into a lower and an upper zone. Figure 1 shows a cross sectional view of Ugnu and West Sak reservoirs. The lower Ugnu is mainly medium grained ranging from fine to coarse grained. The thickness of the lower Ugnu ranges from 75 to 92 m tbroughom most part of the northern Kuparak area. There are three to five major sand beds in the lower Ugnu interbedded with silts and muds. However, sand beds range from 3.5–10 m at the base to 20–31 m thick at the top of the member. The lower Ugnu is separated from underlying West Sak sands by a regionally extensive shale and mud sequence.
FIGURE 1: Cross-sectional view of Ugnu and West Sak. (Available in full paper)
The upper Ugnu sands are thicker than lower Ugnu sands and are mainly fine to medium grained. The upper Ugnu has an average thickness of 100 m in the Kuparak area and is composed of five to seven major sand beds. Each sand bed has an average thickness of 10–20 m.
Theoretical Analysis Of Miscible Displacement In Fractured Porous Media By A One-Dimensional Model: Part I -- Theory
Authors: Tan C.T. , Firoozabadi A. 
Published: March 2010

Abstract
A one-dimensional model is formulated to describe miscible displacement in fractured porous media. Four parameters, R1 (normalized fracture capacity), B (productivity capacity ratio), M (viscosity ratio), and Ngr (gravity number) that characterize the process are identified. No-crossflow and crossflow equilibrium assumptions are made, and solution methods for both cases are provided. In the case of crossflow equilibrium, the flow is balanced by the viscous and gravity forces. Three branches of solution characteristics are discovered. These are:dominant viscous crossflow,moderate gravity crossflow, andstrong gravity crossflow. The criterion for each case is given in terms of viscosity ratio and gravity number.
Depending on the magnitude of viscosity ratio and gravity number, crossflow direction changes along the length of matrix-fracture interface.

Introduction
One of the main characteristics of a fractured petroleum reservoiris high rate wells in the early life of the field. Depending on the drainage rate. the high rate can continue for a long time for some fractured reservoirs and for a very short period for others, Fractures increase the effective single phase permeability of the combined matrix-fracture porous media. The magnitude of the increase of effective single phase permeability depends on the (kA)r/(kA)m ratio (fractures are assumed perpendicular to the well). For most naturally fractured reservoirs, (kA)r/(kA)m is in the range of 10 to 100. Therefore, wells could produce at rates of 10 to 100 times more than a nonfractured matrix. The above picture of a fractured petroleum reservoir changes for the two phase gas-oil now process. The oil drained from the matrix to the fracture could partly or totally reinfiltrate to the blocks underneath due to capillary and gravity forces(1,2). The reinfiltration process, therefore, substantially reduces the rate of oil production in the two-phase gas-oil region. Another parameter which could lower the rate of drainage in fractured porous media is the fracture gasoil capillary pressure. Visual observations have revealed that the oil now in the fractures for the gas-oil immiscible system is mainly film now, and higher fracture aperture (i.e., fracture capillary pressure effect) reduces the liquid film flow across the matrix blocks(3). Both the reinfiltration process and the capillary pressure contrast between the matrix and fracture lower the rate of drainage. In other words, the rate of drainage from fractured porous media, when the oil is derived from the matrix. is less than in an unfractured medium with the same matrix permeability, provided oil compressibility effects and fracture storage are negligible. After an infinite lime period due to capillary continuity, the ultimate recovery will be the same for both fractured and unfractured porous media.
The key to drainage rate enhancement for fractured porous media is:to increase gas-oil gravity drainage rate, andto reduce rein filtration rate.
Managing Hydrocarbon Injectionat At Judy Creek
Authors: Lloyd C.J. 
Published: March 2010

Abstract
Tile Judy Creek Beaverhill Lake ‘A’ and ‘B’ Pools have been undergoing pattern hydrocarbon miscible flood (HCMF) since 1985 and 1987 respectively. This paper describes the evolution of the hydrocarbon injection strategy for the Judy Creek Pools from 1985 to today.
The original HCMF design for each pattern was a water-alternating- gas (WAG) ratio of 1.0. minimum solvent bank of 15% of the continuous hydrocarbon pore volume (CHCPV), and a minimum chase gas bank of 20% of the CHCPV. Analysis of performance data has resulted in an evolution of HCMF design parameters and operating strategy, injection strategy is now specific to each pattern and zone. Downhole isolation equipment has been used extensively to improve zonal control leading to better reservoir sweep: examples of this are presented. Both ofthese changes have significantly improved tertiary recovery, but also have greatly increased the data management required. Imperial Oil's current method of designing, scheduling, and reporting hydrocarbon injection banks and WAG ratios by pattern and geologic zone is discussed. This includes a computer program that has been developed to calculate pattern and zonal hydrocarbon banks and WAG ratios.
Approximately 1,400 103m3/d (50 mmcf/d) of hydrocarbon is injected into the Judy Creek HCMF3. Optimal use of injectant is a key lever in maximizing profitability of these hydrocarbon miscible floods.

Introduction
The Judy Creek "A" and "B" Pools are located about 200 km northwest of Edunonton. Alberta, and were both discovered in 1959. Figure 1 is a gross thickness of 70m (230 ft). The "B" pool is geologically similar but smaller its original oil in place is estimated at 39.8x 106 m3 (250 MMSTB) and it covers an area of 4.915 ha (12,000 acres). Examples from both pools have been included, but the paper will focus on the "A" pool.
Geologically, the "A" Pool is an atoll-like reefal limestone. It can be generally described as a highly porous organic reel margin surrounding a more stratified interior lagoon. Figure 2 shows a cross-section through the reef. Pore volume and continuity vary widely. The reef margin geology exhibits high porosity and permeability and good lateral and vertical continuity. In contrast, the ref interior is characterized by varying porosity and permeability, with thin pay zones separated by thicker tight streaks. There is poor lateral and vertical community. Core studies have defined five cycles of reef growth (denoted as the R1 and R5 zone). Except in the reef margin, there is no vertical flow between these boundaries.
The "A" pool was originally developed on 64 and 160 acre) well spacing, under solution gas drive. A peripheral waterflood scheme was implemented in 1964. In 1974, a pattern waterflood scheme was implemented, as he penpheral waterflood injections were unable to support production wells in the red interior In 1975 and 1978, extensive infill drilling occurred., reducing the well spacing to 32 ha (80 acre) in many areas off the pool.
Recent Advances In Horizontal Drilling
Authors: Maurer W.C. 
Published: March 2010

Abstract
This paper describes recent advances in horizontal drilling technology including multibrach wells, geosteering, advanced drilling bits and motors; new short-radius tools, and small diameter drilling systems. Multibranch horizontal wells can reduce horizontal drilling costs by 20 to 30 % and the size and number of offshore platform by up to 50%.
Geosteering systems utilize logging-while-drilling tools to accurately guide horizontal wells to avoide obstacles and gas water contacts and to significantly increase horizontal well productivity. Improved PDC and TSP bits and new high-power motors have potential wells. New short-radius motor systems 12 to 30 m (40 to 100 ft) radii allow 305 to 457 m (1000 to 1,500 ft) horizontal wells to be drilled more rapidly. Advantages of short-radius wells includesidetracking wells below gas caps or troublesome shales,intersecting fractures close to vertical wellboressignificantly reducing the length of the build sectionreducing drilling time and cost andallowing pumps to be placed lower in the wells
New small diameter systems allow 92 mm (3 5/8 in) single and multibranch horizontal wells to be sidetracked from 114 mm (4 ?) casing Implementation of these new technologies should significantly increase the use of horizontal wellsworld wide.

Multibranch Wells
One of the most important developments with horizontal drilling is the increased use of multibranch wells. Figure 1 shows a Soviet (1) multibranch well with ten lateral. This well was drilled in the 1950's with nurbodrills. The laterals produced a 17-fold increase in oil production in this well.
Figure 2 shows a Soviet dual branch well drilled in the Macova field in 1968. This well cast 1.23 times more than a conventional well and produced 10.5 times more useful length in the pay zone.
By 1975, the Soviets had drilled over 30 multibranch and horizontal wells(2). They typically drilled vertical well just above the pay zone and then used turbodrills or electrodrills to drill five or six stand or horizontal branches 61 to 305 m (200 to 1,000 ft) into the pay zone. These multibranch wells cost 30 to 80% more han vertical wells, but produced up to 17 times more oil or gas.
From 1953 to 1980, the Soviets had drilled over 30 multibranch and horizontal well2. Including:57 development36 exploratory8 relief wells10 injection wells
A total 329 slant and horizontal branches were drilled in these wells with an accumulated pay-zone penetration of 175,260 m (575,000 ft.). This included 2120 sharply curved brances sidetracked from open holes (i. e. no cement plugs) with a total extension of 21,336 m (70,000 ft). Build rates up to 10 °/30 m (10 °/100 ft). Build rates up to horizontal branches were drilled with a maximum length of 640 m (2,100 ft) and a total length o 4,724 m (15,500) ft).
Petro-Huun 3 used a dual branch well to drain an entire Austin Chalk lease as shown in Figures 3 and 4.