bluuebunny/crossref_metadata_2025_split huggingface dataset:
Simulation Of The Saner Ranch Fracture-Assisted Steamflood Pilot
Authors: Soni Y. , Harmon R.A. 
Published: March 2010

Abstract
Conventional steamflooding of heavy oils and tars in thin reservoirs generally suffers from excessive heat losses to the over- and under-burden. High rate steam injection is often constrained by limited reservoir injectivity. A recently developed FAST process (Fracture-Assisted Steamflood Technology) allows high rates of steam injection in thin shallow sands through hydraulically created horizontal fractures. This process limits the heat losses by shortening the steamflood life for a 5 to 7.5 acre (2 to 3 ha) pattern to less than two years.
Conoco demonstrated the technical feasibility of the FAST process in two pilot tests in south Texas where −2 ° API (1 093 kg/m3) tar was successfully produced. In an attempt to understand the dominant flow mechanisms in the FAST process and to develop a technique for predicting performance of future FAST steamfloods, numerical simulation was used to achieve a comprehensive history match of the second pilot test at the Saner Ranch in south Texas.
Despite the complexity of this recovery process, a commercially available steamflood simulator was used to match the performance of one-twelth symmetry element of the inverted 7-spot, 7.5 acres (3 ha) pattern. In addition to matching the tar and water production, the temperature and pressure histories, temperature profiles, water cuts and volumetric tar recoveries were also matched.
One of the key elements was the modeling of multiple phase flow through an open fracture. This was accomplished by a simple technique which did not require reprogramming of the conventional steamflood simulator. The numerical simulation of the FAST process revealed dominant flow mechanisms in the process. The calibrated model is now being used for on-going predictive and process optimization studies.
This paper briefly describes the FAST process, pilot history, details of the technique used to model flow in an open fracture, and results of the numerical modeling study.

Introduction
Conoco conducted two pilot tests of the FAST steamflood process in the south Texas tar sands deposits (Fig. 1). These formations contain −2 ° to + 3 ° API (1 093 to 1 052 kg/m3) tar with viscosities of 1 to 20 million centipoise at reservoir temperatures. The first pilot was conducted from November 1977 to June 1980 at the Street Ranch lease where 169,040 barrels (26 875 m3) of −2 ° API (1 093 kg/m3) tar were recovered from a 5-acre (2 ha) pattern after injecting 1,847,500 barrels (293 730 m3) of steam(1). The second pilot test was conducted at the Saner Ranch from April 1981 to January 1983. A total of 133,260 barrels (21 190 m3) of tar was recovered from a 7.5-acre (3 ha) pattern after injecting only 1,069.000 barrels (169 950 m3) of steam(2). The main objective of the first pilot was to prove the feasibility of the FAST process for recovering −2 ° API (1 093 kg/m3) tar. The objectives of the second pilot test were to demonstrate the FAST process in a different part of the reservoir and to improve performance.
Interim Progress Report On Husky's Pikes Peak Steam Pilot
Authors: Miller K.A. 
Published: March 2010

Abstract
Husky's Pikes Peak Steam pilot was initialed in 1981 to evaluate cyclic steam recovery in a Lloydminster area Waseca channel sand reservoir, and has since been expanded to include a total of fifty-four thermal wells. Development has been based on three-hectare seven-spot patterns to facilitate eventual conversion to steam drive, and directional drilling has been in use the last two years.
The over-all performance of the pilot has been very good, although data are limited as only three fully contained wells have completed two or more cycles.
Studies are underway at the pilot to evaluate the following: use of a post-cyclic steam drive process production from wells with bottom water, production following the establishment of inter-well communication, and methods of improving steam sweep. A data management system is being developed, and both semi-empirical and numerical modelling studies are underway.

Introduction
Husky's Pikes Peak steam pilot is located in Township 50, Range 23 and 24 west of the 3rd Meridian approximately 40 km east of the town of Lloydminster (Fig. 1). The discovery well, Husky A9-1-50-24, was drilled in 1970 and completed in the General Petroleum Sand. Attempts at primary production from the Waseca formation in 1977 to 1980 were not successful, likely due to the high viscosity of the crude and to high sand cuts.
An application seeking approval to initiate a steam pilot was submitted to and accepted by the Saskatchewan Energy and Mines in 1981, and by the end of 1981 seven producers and two observation wells were drilled. Additional wells have been drilled each year, and the pilot presently has 54 thermal wells. Directional drilling was initiated in 1983 to reduce the effects on surface land, and there are now 30 directional thermal wells.
The Pikes Peak Waseca reservoir sand is well sorted and is primarily quartz. The pilot is located in one of the few areas in a north-south aligned channel which has thick oil-bearing sands that are not underlain by bottom water. Net pay in the developed pilot area ranges from 7 m to 28 m, and averages 15 m.
Pilot wells are normally completed open hole with wire wrapped screens, bur cased-through completions arc used if bottom water is indicated on the logs or if the potentially gassy underlying Sparky zone is penetrated.
The over-all pilot performance has been very good, with a cumulative pilot SOR of 1.5 and an average calendar day oil rate of 15,5 m3/d/producer. Data for totally confined wells are limited, however. Inter-well communication became common in mid-1983, and the performance of neighbouring wells is now also considered when determining if a well should be re-steamed. A continuous injection test is underway in one pattern to help evaluate use of steam drive when cyclic simulation is no longer economic. Studies are also underway to improve oil recovery from wells with bottom water.

Geology and Reservoir Description
The Pikes Peak steam pilot is located on an east-west structural high within a north-south-trending channel complex.
The Expansion Of Tar Sands During Thermal Recovery
Authors: Butler R.M. 
Published: March 2010

Abstract
When tar sands are heated by steam injection there is a tendency for the reservoir liquids to expand; this increases the pore pressure.
If the bitumen is more confined the effect is larger. Factors which promote the increase of pore pressure include high bitumen viscosity, low reservoir temperature, low permeability, and high steam injection pressure. The pore pressure can rise to the level needed to fracture the reservoir even though the steam injection pressure is below the fracture level.
The effect of injecting steam into a permeable layer on the adjacent reservoir has been studied theoretically. It is assumed that heat flows only by thermal conduction and that the expansion of the bitumen is accommodated by flow of the bitumen and by expansion of the pore volume of the reservoir material. The water in the reservoir is assumed to be immobile. It is found that significant disruption and physical expansion of the reservoir matrix may occur. The predicted volumetric expansion is sufficient to lift the surface of the ground above the reservoir several centimeters.
The mechanism which is described is useful in explaining the "surface " heave found in steam recovery pilots. It may be important in the recovery process because matrix expansion, particularly of low permeability streaks, improves the effective permeability. It may be possible to choose conditions which optimize the effect.

Introduction
This paper is concerned with the possibility that, during steam heating, the thermal expansion of bitumen within reservoirs can create pore pressures high enough to produce reservoir expansion, i.e. to move the sand grains apart.
The reason that a mechanism such as this can be considered is that the volumetric coefficient of thermal expansion of the liquid pore fluids is far greater than that of the rock; these are compared in Figure 1.
The uplifting of the surface above in-situ recovery pilots has been observed. A study reported by Texaco(1) indicated surface heaves of the order of six inches. It is thought that changes of this order are larger than could be accounted for simply by the thermal expansion of the reservoir rock. It is suggested that the mechanism described in this paper is probably responsible for much of the heave.
The expansion of the reservoir matrix as a result of thermally induced pore pressures is of more interest than that due to the simple thermal expansion of the rock because it can also modify the recovery process. In particular, it can provide a mechanism for the permeability improvement of low permeability sections of the reservoir.

Theoretical Approach
As the bitumen becomes heated, its tendency to expand is balanced by three factors;Relief of pressure by flow;Compression of the bitumen; andExpansion of the pore space.
The last of these factors can be looked upon as consisting of two parts:
The elastic expansion of the pores as a result of an increase in pore pressure and, also the disruption of the pores which arises when the pore pressure exceeds the local geostatic stress.
Optimized Drilling Through Use Of Downnhole Motors
Authors: Diaconescu P. , LeBlanc L. 
Published: March 2010

Abstract
It has been established that rate of penetration (ROP) is directly related to rotational speed (RPM) of the drill bit in most formations. The Wembley area of northwest Alberta shows a proportionate increase in drilling rate with increases in rotary speed.
Pan Canadian Petroleum Ltd. (PCP) optimized bit RPM by supplementing the rig's rotary capability with downhole motors. This paper will summarize the results of using downhole motors to Increase penetration rates in the Wembley field and will provide the drilling plan which PanCanadian uses to optimize vertical drilling with downhole motors.

Introduction
The relationship for soft and medium soft formations, between rate of penetration and rotational speed has been established as(1):
(1) R = KWN a
where:
R = Rate of penetration
K = Lithology factor
N = Rotary speed
W = Weight on bit
a = exponent (equal to 1 for Wembley)
For Wembley area this equation may be reduced to:
(2) R = constant ( N )
Although the constant includes the bit weight, which is a variable, by drill off tests and manufacturer's recommendations bit weight has been optimized at a relatively constant value between 18 000 and 20 000 daN.
Equation (2) suggests the rate of penetration can be enhanced through rotary speed increases. Factors which place an upper limit on rotary speed include:Drill string limitations.Drilling rig limitations on rotary speed.Drill bit limitations.Mechanical hole erosion.Casing wear.
Drill string limitations include resonant vibration, joint strength, wear due to erosion and cyclic bending fatigue. Contractors limit rotary speed to 150 RPM or less and will not warrant the operational integrity of the string at higher rotary speeds. An excellent reference paper has been prepared by D. Dareing of Maurer Engineering Inc. (Ref. SPE 11228).
Therefore most conventional drilling rigs are limited to rotary speeds of 150 RPM. Chain drive rotary tables are in common use and are usually coupled from the drawworks power take-off directly to the rotary drive pinion. Due to substructure space limitations it is not often possible to include a transmission on the rotary table. Chain sprockets also tend to be fixed by rotary torque requirements and chain speed limits. Torque tubes and electric drive rotaries have added flexibility to available RPM but these systems are not always available. Retrofit on existing rigs cannot be economically justified unless a long-term rig commitment is possible.
Drill bit manufacturer's suggest RPM limits for their products but recent developments in premium sealed bearings have allowed greater flexibility. Also, insert bits have been improved in the bonding of carbide teeth to the cone matrix, allowing higher rotary speeds.
Casing wear is a concern to all operators and, in some cases, optimum drilling performance has been sacrificed to limit wear. Non-rotating stabilizers have been used successfully but, again, stabilizer wear increases substantially when the drill string is rotated above 100 RPM.
Heated Acids For Improved Stimulation
Authors: Walker M.L. , Fredrickson S. , Norman L. , Hoch O.O. 
Published: March 2010

Abstract
A simple and practical process has been developed to heat hydrochloric acid to improve its performance as an oil well stimulating agent. Heated acid is used in cold formations, such as cold dolomites, to increase the rate at which the formation is dissolved, thus improving flow capacities. The new technique heats the acid by causing an exothermic chemical reaction that uses a portion of the HCl as one of the reactants.
Heated acid reacts at a faster rate and aids in the removal of acid-retarding materials such as oil, asphaltene and paraffins from the formation to give a better acid-to-formation contact. Some other benefits of heating acid are:Helps prevent precipitation of organic materials from oils that have been cooled by acids.Limits the amount of tubing contraction due to temperature Change.
Problems presented by the slow reaction time of HCl in cold formations and the special problems of conducting winter time acid treatments are largely solved by heating HCl up to bottomhole temperature or more prior to pumping. This paper presents laboratory and field results to illustrate the effectiveness of the heated acid method of stimulation and compares the various methods of bringing the acid to its ideal temperature.

Introduction
Stimulation of formations with cold treating fluids causes a variety of problems to the oil industry.Cold treating fluids are not reactive enough, especially when the formations are themselves cool.Tubular goods will contract excessively when the formation is hot and the treating fluid is cool. Contraction can cause strain on the tubular goods and unseating of packers.
Historically, in acidizing, emphasis has been on the use of retarded acids or retarded systems that place live acid deeper into the formation(1–2); however, sometimes accelerated acid systems are necessary because of cold formations or short acid pumping times. Although surfactants can aid to some degree, heating the add has been found to be the most practical means to accelerate acid reaction.
Hot oilers and steam have been used to heat acid, but-their application with many acid systems was limited or they were impractical for the type of treatment to be run. A system to heat acid chemically has been developed and tested in the laboratory and field, showing excellent results.

Methods of Heating Acid

Chemically Heated Acid
Heating acid by chemical means can be accomplished by either batch or continuous methods. The batch heating process consists of flowing ammonia into the container below the surface of the acid by means of a perforated lance. Ammonia is added until the desired temperature or acid concentration is reached. Figure 1 shows the heat derived from three different acid solutions. Large volumes of acid can also be heated simply by the continuous method. Ammonia is metered into the acid while the acid is being pumped into the well. Heat is developed rapidly and there is little heat loss on the surface because there is no exposure or delay.
Multiple Contact Phase Behaviour In The Displacement Of Crude Oil With Nitrogen And Enriched Nitrogen
Authors: Sayegh S.G. , Wang S.T. , Najman J. 
Published: March 2010

Abstract
Phase behavior tests were carried out on a Nisku crude oil (a candidate reservoir for nitrogen flooding) with nitrogen and nitrogen mixed with carbon dioxide or propane. These measurements were carried out in a batch wise multiple contact mode to simulate what occurs when gas displaces oil in a porous medium. None of the mixtures achieved miscibility with the oil in four contacts at pressures up to 35 MPa. Nitrogen and methane were exchanged between the gas and oil phases in an almost 1:1 ratio, while gas enrichment with C2–5 hydrocarbons proceeded at a much slower pace.
The experimental data were matched using the Peng-Robinson equation of stale. Good agreement between experimental and calculated results was obtained in most cases. This applies to the equilibrium phase compositions, as well as to the liquid phase densities and gas/oil ratios. The largest deviations were in the amount of heavy ends found in the vapour phase.

Introduction
Nitrogen may be applied for enhanced oil recovery (EOR) in several modes, e.g. pressure maintenance, cycling condensate reservoirs, attic oil production, producing gas-cap gas, chase gas for hydrocarbon or carbon dioxide slugs and miscible displacement of oil.
These applications were discussed by Clancy et al.(1) and reviewed in detail by Sayegh et al.(2). Recently Leonard(3) summarized EOR activity worldwide. From this article it was noted that there are seven nitrogen injection projects in the U.S.A., four of which have already showed profit, while it is too early to tell the remaining three. In addition, there are three flue gas injection projects. In Canada, two ongoing floods utilize nitrogen. The first is in a Pembina Nisku reef, wherein the injection gas consists of a mixture rich in nitrogen along with carbon dioxide and light hydrocarbons. The second is the Willisden Green flood, where nitrogen is being used as a chase gas for a hydrocarbon slug.
The advantages of using nitrogen for EOR include: widespread availability from air liquefaction, non-toxicity, non-flammability and non-corrosivity.
In addition, the price of nitrogen appears to be competitive with that of dry hydrocarbons, although it is difficult to give more precise estimates because of the many variables involved in costing. Wilson(4) noted that nitrogen has some disadvantages in its use for enhanced oil recovery, which include:The cost of separating nitrogen from the produced hydrocarbon gases. This is offset if the produced gases are recycled into the reservoir.Nitrogen asphyxia.If air separation units are used to produce nitrogen, then a by-product stream rich in oxygen is produced. This stream has to be well separated from any hydrocarbon streams in the vicinity.
In summary, the use of nitrogen in enhanced oil recovery has many advantages that can outweigh its disadvantages. This is a new topic, and there are many gaps in the information available for its proper application. It is the purpose of this work to try and fill in some of these gaps.
Logging With A Coiled Tubing System
Authors: Latos Jeff , Chenery Dale 
Published: March 2010

Abstract
A completion technique has been developed for highly deviated wells which uses a conductor cable placed inside coiled tubing. All conventional cased hole logging and perforating tools C(In be run. The advantages of this system include a shorter completion time, precise positioning of the downhole tools, the ability to maintain an even logging speed, the ability to circulate fluid while logging, and the elimination of a workover rig.
This paper reviews a successful completion program performed on three gas wells in the Bantry Field of southern Alberta, and presents details on open hole logging procedures conducted on two wells in England. Aim being presented and discussed are the equipment modifications that were necessary, and possible future developments of this innovative technique.

Introduction
The major problems associated with highly deviated wells have been logging(l) and completions(2). Logging has traditionally been accomplished using drill pipe conveyed systems(3) or pump down techniques(2). Completion of horizontal wells has been accomplished through the use of slotted liners or with tubing conveyed perforating guns.
Electric wireline conductor cable placed inside coiled tubing creates new possibilities in well logging and completions. The method involves running downhole electrical tools in and out of the hole with conventional coiled tubing. The tools are linked to surface by the conductor cable inside the tubing. A coiled tubing / wireline method for open hole logging and casing inspection was earlier presented by Howell et al.(4), but their system had not been put into practice.
The system presented in this paper was initially developed to log wells in Germany and France(5,6). Similar equipment was then used to log and complete three Medicine Hat/Milk River gas wells with deviations as great as 78.25 degrees. These zonesare normally produced from shallow vertical wellbores, but irrigation dictated that minimal land be used. The three wells weredirectionally drilled from a single location.
Conventional completion methods (performed on lower zones) had been both expensive and time-consuming. A slant hole service rig had been required., and in most cases, spotting the tools required pump down techniques. Perforating guns had been limited to either tubing conveyed guns or guns with diameters small enough to fit through the tubing. Cleanout and bridge plug movement had caused multiple tubing runs and the necessity to kill the well several times during the completion. Coiled tubing/wireline proved an effective system that successfully:decreased completion time,eliminated tubing and casing wear,avoided having to kill the wells, andallowed the use of larger perforating guns
The coiled tubing/wireline system was also used to open hole log two wells in the south of England. These wells had deviations to 60 degrees. The system was required after conventional logging techniques had proven unsuccessful.