bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Nature And Control Of Geyser Phenomena In Thermal Production Risers
Authors: Edmunds N.R. , Good W.K. 
Published: March 2010

Abstract
Efficient application of Steam-assisted Gravity Drainage (SAGD) for bitumen or heavy oil recovery requires production of large fluid volumes, close to the boiling point of water. Flowing or gas/steam lifting such wells is an attractive alternative to rod pumping, but evidence is given that the flow can be unstable, due to the large energy release of flashing water. The instabilities are the same phenomena that drive cyclic eruptions in geothermal geysers.
A unique finite difference simulator is used to model and study the transient thermohydraulics of superheated water in an idealized wellbore. It is shown that some form of dynamic wellhead choking system is probably required for satisfactory control of a surface access SAGD well.
The advent of horizontal wells for thermal recovery and especially for SAGD has led to the need to produce very large fluid volumes from individual wells, at high temperatures. For optimum SAGD, the temperature in the production liner should be kept close to the steam point at bottomhole pressure (steam trap production control)(l), so as to maintain the steam chamber as deep as possible. Sustained fluid production rates of 300 m3/D or more(2) are anticipated from single producers; at this rate, wellbore heat losses will have a limited cooling effect. In most SAGD applications, then, produced water will flash as pressure declines on the way to the surface.

UTF Production Lifting Experience
At the AOSTRA Underground Test Facility (UTF)(3), SAGD testing is carried out using horizontal wells that are drilled from a tunnel located below the oil sand reservoir. Steam generation and production treating facilities are on the surface, and standard piping carries fluids to and from the well chambers. The wellheads and production control valves are about 20 m lower in elevation than the production liners. This arrangement takes advantage of gravity to avoid flashing in the wellbore and the tunnel facilities, but production is still subject to flash conditions in the riser, during the 185 m climb to the surface.
This was recognized during the design of the Phase A facilities, and it was hoped to exploit the resulting steam lift effect. The underground pump was de-rated and a steam sparge system was installed at the base of the riser to enable the lifting of cold fluids.
A summary of experience with this system is shown in Figure 1. This is a scatter plot showing the average riser pressure gradients for about 700 days of Phase A operation, as a function of riser bottomhole temperature. This temperature is expressed in terms of subcooling below the steam point, to account for varying pressure. Most days fall into one of three groups indicated, corresponding to the (I) no flashing, (II) slight flashing, and (III) high enthalpy (est. 15 – 30% quality) conditions.
The large gap between regions II and III represents conditions that were avoided due to extreme and persistent instability. In this region, flow consisted of geyser-like eruptions occurring at periods from one-half to several hours.
Redevelopment of the Brazeau River Nisku A And D Vertical Miscible Floods With Horizontal Wells
Authors: Lee J.I. , Jerhoff T.F. 
Published: March 2010

Abstract
A 400 m long horizontal well was drilled in both the Brazeau River Nisku A and D pools at a true vertical depth of 3,200 m. Both pools have been under vertical hydrocarbon miscible floods for over ten years. The purpose of these horizontal wells was to increase ultimate pool recovery by reducing well drawdown leading to improved GOR behaviour.
The location of the horizontal well in the Nisku A pool was selected based on the existing 2-D seismic data in an effort to further exploit the undeveloped portion of the reservoir. Two side track horizontal holes were drilled to search for the porous zone in the bottom of the reservoir prior to drilling the final horizontal hole approximately 2m above the base of the porous zone. In the Nisku D pool, vertical seismic profiling was conducted to locate the porous zone and to aid in the design of the length, depth and azimuth of the horizontal wellbore.
Both wells were open-hole completed. The initial oil rates were 300 - 400 m3/d, and the expected incremental reserves are approximately 300,000 m3 for the Nisku A pool and 260,000 m3 for the Nisku D pool, or 4 and 10% of their respective OOIP. Because of the relatively high initial oil rate of the horizontal wells, the high expenditures of $ 5 million for the Nisku A pool and $3.4 million for the Nisku D pool were paid out during the first year of production.

Introduction
The Brazeau River Nisku A and D pools are located approximately 150 km southwest of Edmonton, Alberta. Figure 1 shows the location of the Brazeau River Nisku A and D pools along with other producing Nisku reefs in the area. The first A pool well, 11- 31–48-12 W5M, was drilled in January 1978. The Nisku D pool was discovered in June 1978 with the drilling of well 7–33-48–12 W5M. The A and D pools are both sweet oil reservoirs containing light, volatile oil having a density of approximately 800 kg/m3. The respective solution GORs were 180 and 140 m3/m3. Average porosity ranges from 7 to 10% and the respective net pays are 80 m and 40 m. Average pool permeability of the A pool is 330 mD while the D pool is significantly lower at 50 mD. Table 1 summarizes the reservoir properties of the Nisku A and D pools. The oil properties and pressure information are described in Table 2.
The Nisku reefs are of the Upper Devonian Winterburn group at a depth of 3,200 m. The base of these reefs covers approximately one section (259 ha) in areal extent. The Nisku A pool is almost entirely dolomitized containing moldic vuggy pores. In the Nisku D pool, sparry calcite cement results in porosity and permeability reduction by complete or partial plugging of both intercrystalline and moldic vuggy pores. The reefs are extremely variable in terms of primary facies and diagenetic modifications; therefore, reservoir properties are difficult to correlate between wells.
Opportunities And Challenges Ahead
Authors: Ziff P. 
Published: March 2010

Post-deregulation-A Decade of Growth
The Canadian Gas Industry is about to enter its twelfth year since deregulation which commenced on November I, 1985. The past decade has been one of rapid growth for the industry. Total Canadian production will reach 5.4 Tcf in 1996, double the 1985 level of 2.7 Tcf. This growth was almost entirely due to exports, which more than tripled from 740 Bcf in 1986 to 2,810 Bcf in 1996. This growth was facilitated first by existing spare export capacity, which was used up during the late '80s, and then by two major pipeline projects. The Iroquois project to the U.S. Northeast came partially onstream in late 1991, reaching about 575 MMcf/d in 1992, followed by the massive PGT expansion commenced incremental shipments of 900 MMcf/d to markets in Southern California and the Pacific North West.
With Canadian gas deregulation, the previously strict formulae based methodqlogies to protect future domestic demand were largely dropped. Today, we rely on price to ensure adequate supply. Canadian consumers have benefitted from this arrangement. The wholesale cost of gas supply (before transportation and distribution charges) under regulation averaged $2.76IMcf in Alberta from 1980 to 1985, and $ 1.72l Mcf since this time. The benefit for producers has been the volume growth described above. Although some critics have been concerned with the decrease in the Canadian reserve life from 20 plus years to 10, the U.S. has been running very nicely on an inventory of nine to 11 years for over two decades! The reserve life of proven reserves is simply the near term inventory. This has been reduced, but has had little disruptive effect. This inventory still is a far cry from the ‘just in time’ practices of the manufacturing sector.

Today-Lots of $$$, but Waiting for Transportation
The major pipeline expansions of the early '90s have stalled out in the mid '90s. Only modest expansions are planned for 1995 to 1998, until the Northern Border expansion begins. While 1994 production benefitted from the full year of PGT expansion, 1995 export growth slowed to 245 Bcf or 9%, and 1996 year to date (seven months) is up a scant 1.4%. As a result, increased sales by one company can be achieved only through decline of another company's production, or by competing for an increase in market share.
In the late '80s and early '90s it was generally thought that with the start-up of the Iroquois and PGT expansion and the Northern Border expansion around 1998, there would be adequate pipeline capacity from western Canada to release the excess supply that existed after the deregulation process in Canada. However, since the early to mid '90s there has been a substantial influx of capital into the Canadian oil and gas industry which has been translated into record drilling levels and another build-up of excess deliverability in the western Canadian producing region.
Even with the Northern Border expansion, now delayed by one year to the end of 1998, excess deliverability and a need for additional pipeline capacity will remain in western Canada.
Oil Re-injection to Mitigate Solvent Coning
Authors: Patel R. , Tang J. , Batycky J. , Lai F. , Okazawa T. 
Published: March 2010

Abstract
After solvent breakthrough, vertical miscible floods are characterized by rapid increases in producing gas-oil ratios, which in, turn are accompanied by rapid declines in oil production. At this advanced stage of depletion, the vertical floods have a low reserve life index and, hence, major investments cannot be justified to extend the producing life of these floods.
Imperial Oil Resources Limited, in its search for new low cost techniques to increase reserves while maintaining/increasing oil production, began to examine the concept of oil reinjection in its Pembina Nisku reservoirs. Exploratory laboratory tests and numerical simulation work demonstrates that a dual completion to re-inject part of the produced oil back into the formation, a few metres above the producing perforations, could lead to incremental recoveries. Simulation results specifically showed a 2 – 3% of the original-oil-in-place (OOIP) increase for the model studied.
A field test to evaluate the benefits of the oil re-injection process is presently being conducted in the Pembina Nisku "Q" pool. Initial results indicate that oil re-injection is successful in controlling solvent production while maintaining oil rates. As a consequence, additional piloting to expand the applicability of the oil re-injection process is being planned for other Nisku and Imperial Oil reservoirs.

Introduction
The Pembina Nisku area is located approximately 120 km west of the city of Edmonton, Alberta, Canada (Figure 1). The Pembina Nisku discoveries were the result of a seismic exploration play initiated by Chevron in the mid 1970's(1).
Imperial Oil operates seven vertical miscible floods in this area, These pools are relatively small in areal extent (130 ha - 325 ha) with OOIP ranging from a low of 1,700 km3 to a high of 5,000 km3. Vertical miscible floods were initiated in these pools in the 1982 to 1987 time frame.
Figures 2 and 3 show the oil production and GOR performance of the Imperial Oil operated miscible floods. Oil production from these pools peaked in 1987 at approximately 5,100 m3/day. The gas-oil ratios (GOR) remained at the base level of 150 m3/m3 through 1987 but then, as a result of solvent breakthrough, started increasing rapidly to the present level of280 m3/m3. As is the case with all vertical miscible floods, the increase in the GOR was accompanied by a rapid decline in the oil production rates. The pools presently produce approximately 1,900 m3/day, and this represents a decline of more than 60% from their peak rates.
The Nisku pools have now recovered approximately 88% of their reserves with individual pool recoveries approaching 70% of the OOIP. The low remaining reserves combined with high individual pool recoveries make it difficult to justify major capital
FIGURE 1: Nisku regional geology and pools, Pembina area, Alberta, Canada.
FIGURE 2: Imperial Oil operated Pembina Nisku miscible flood-oil rate. investments to extend the producing life of these pools.
Computers-Black Box Or Tool Box?
Authors: Mattar Louis 
Published: March 2010

The, theme of this issue is "Computer Applications." Accordingly, it isbefitting to comment on the effect that this technology has had on ourpetroleum industry. As I am preparing this editorial, I reminisce about a Christmas 21 years ago, when my wife bought me a calculator (programmable) for$ 1,000! Today, its equivalent does ten times more for one tenth the price! As Robert Cringila said: "If the automobile had followed the same developmentcycle as the computer, a Rolls Royce would cost $100 today, get a million milesper gallon and explode once year, killing everyone inside." So, what has thismind-boggling silicon chip done to improve the oil and gas industry in Alberta?
Of course, today, the first thing one talks about at coffee is the Internet. Yes, both the post office and the telephone companies are on their way toextinction! There are singing Christmas cards (messages) I could have e-mailedall over the world, at no cost (and donated the savings to the food bank). But I am told, the Internet is not only transistory, it is also transitory. Itwon't be long before it is replaced by some form of Globalnet in whichtelevision, radio, telephone, computing etc., are all one amorphoustelecommunications ganglia (cellular phones will be replaced by implants inyour ear, and who knows, TV and computer screens by LCD colour retina chips). But, "with the sound of sugar plum fairies dancing in my head" am I beingcarried away by the spirit of Christmas?

Video Games
The graphics technology of video games has been implemented in computerprograms for reservoir visualization. We can integrate seismic images, petrophysical logs and geological models to build a 3-D picture of ourreservoir-slice it, dice it, rotate it, look inside and monitor the rate ofadvance of a water flood, or determine the regions of unswept oil for infilldrilling (in 64 million colours). It is very easy, and tempting to spend moretime "playing" with our computer programs than "studying the problem."Presentation has taken over from technical content-sad but true. Have computersimproved our productivity? In the areas of automation, communications androbotics, clearly yes. In many other areas, our efficiency has decreased. Onestudy shows that the average document goes through a word processor thirteentimes before it is completed! Today, we can learn more and more about less andless, and it is easy to lose sight of the forest for the trees. We can measure100,000 pressures with electronic gauges, at one-second intervals, withunprecedented accuracy, in an attempt to define our reservoir which, in fact, is being modelled as a simplistic homogeneous box-a little overkill, don't you think?

If I had a Hammer
When we have a new tool (toy) that we like, it tends to dominate our thinking. If I have a hammer, suddenly everything looks like a nail! When the concept ofdual porosity was first introduced, many reservoir models "became" dualporosity overnight.
Tips, Tricks And Traps of Material Balance Calculations
Authors: Carlson M.R. 
Published: March 2010

Abstract
The author has encountered a number of situations where drastically different interpretations are possible from oil material balances. The paper focusses on two of these field situations. In the first case, a gas cap could be interpreted which subsequent analysis disproved. In the second case, regression techniques converged to a total of three different combinations of gas cap and oil leg sizes. The existence of multiple solutions was not readily apparent.
The discussion is approached from three different perspectives, which are referenced to two different field examples:How production, geological, PVT (oil, gas and water) and historical information may be used to screen results and to apply the mathematical technique.A new mathematical approach to error analysis for the Havlena and Odeh material balance has been developed which the author has not seen elsewhere in the literature. Additionally, graphical interpretation can identify situations where multiple interpretations are likely.A spreadsheet has been used to implement the Havlena and Odeh material balance. Using some simple macros it is possible to quickly generate all of the diagnostic plots. This is a cost effective alternative to purchase of a specialty program. Aquifers are also included as well as statistical regression. Convergence is demonstrated as a criteria for confidence in material balance calculations.
The new interpretations were significant. In the first case, it was an important factor in deciding to proceed with a string of successful workovers designed to recover attic oil. In the second case, the new interpretation cut short a field extension drilling, program which was resulting in unexpected dry holes.

Introduction
This paper is based on half a dozen material balance studies that the author has prepared on a consulting basis. Four were for carbonate reservoirs and two were for sandstone reservoirs. The contents are based on this experience and thus represent a mixture of field case, theoretical analysis (developed during projects) and an evolving approach to material balance calculations. Two examples are given, however, they represent the combined experience on all of the above reservoirs. Scales have, for the most part, been removed; since the data is from actual studies. The paper has been structured as follows:A quick summary is made of the material balance equations. These are used for the derivation of the error analysis. No derivation of the equations was made since this is comprehensively covered in many reservoir engineering textbooks. A summary of the various Havlena and Odeh plots is also made, since this material is discussed in the paper.An analysis of the effects of errors in pressure measurement is presented. The author uses this for weighting data points.Some practical observations are made on statistical minimization.The general approach used by the author is outlined.Two typical material balance situations are described, which highlight error analysis and data screening.
The paper differs slightly from the norm for a technical paper.
Reservoir Management For Waterfloods-Part II
Authors: Baker Richard 
Published: March 2010

Forward
This paper is the second part of a two-part article (part one published April 1997). Waterflood management is critical, particularly for poor quality or geologically complex reservoirs. In part one, we examined oil production response to a waterflood. In the second part, we investigate gas and water production response as well as injection analysis and reservoir pressure response.

Gas-oil Ratio and Water-oil Ratio
An indicator of bypassing is a premature drop in gas-oil ratio; i.e., earlier than expected collapse of gas saturation. Early gas collapse (water fillup) may indicate that channeling has occurred. In layered reservoirs with no or little vertical crossflow, water injection in an initially depressurized layer will cause GOR to drop rapidly. Often naturally fractured reservoirs exhibit fast gas collapse because water fills up the fracture system and does not initially invade the matrix, the desired target for waterflooding. Figure 1 shows an example of a pattern where channeling has occurred. This type of pattern should be reviewed geologically to attempt to identify the thief zones/natural fractures.
Other key performance indicators are water breakthrough times and subsequent WOR trends, which also can be indicative of channeling and bypassing problems. However, since wells or patterns showing high WOR rise or quick gas collapse may simply be due to high injection rates, one should plot WOR and GOR versus hydrocarbon pore volume injected (HCPVI). In general, if water breakthrough occurs before 20% hydrocarbon pore volume injected (HCPVI), channeling or bypassing due to heterogeneity is likely occurring.
Like the WOR or GOR versus time plots, the log of WOR versus cumulative oil produced (Np) is used as an indication of channeling and heterogeneity (Figures 2 – 4).(1, 2) In an unfavourable mobility ratio situation (M &gt;), the late time slope of the graph is primarily controlled by the oil water relative permeability curves; therefore, volumetric sweep efficiency can be derived from this plot.(2) In a favourable mobility ratio situation (M (1), the late time slope of the graph is controlled primarily by permeability heterogeneity or fluid segregation. In layered systems, the WOR versus Np plot may have a stair-type profile as various layers breakthrough (Figure 4). Plotting WOR versus Np and comparing individual patterns against a group average (e.g., for an entire unit operation) gives a qualitative indicator of volumetric sweep efficiency. This should be evaluated in the context of known or suspected geological trends. Stylized representations of waterflood performance in simplistic geological cross sections are depicted in the companion insets to Figures 3 and 4.
Extrapolation of the WOR versus Np plot and changes in its slope can indicate incremental oil recovery. Therefore, an examination of the log of WOR versus Np plot is useful in determining the incremental recovery due to infill drilling or operational changes, as shown in Figure 5. The changing slope of the curve indicates increased reserves after infill drilling.