bluuebunny/crossref_metadata_2025 huggingface dataset:
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 >), 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.
Modelling of Sand Production From Wells On Primary Recovery
Authors: Tremblay B. , Sedgwick G. , Forshner K.
Published: March 2010

Cold Production is a recovery process used in uncemented heavy oil reservoirs in which sand and oil are produced together under primary conditions. Sand production is known to be necessary in order to better access heavy oil reservoirs. The production of sand into a casing perforation was modelled experimentally using a horizontal sand pack. Heavy oil flowed through the sand and out the orifice at one end of the pack. The pack was scanned using an X-ray CT scanner. A high porosity (53%) channel (wormhole) was observed to develop in the sand pack above a critical pressure gradient. The sand cut was 44% (by volume) as the wormhole was developing. When the wormhole broke through the inlet, the sand cut decreased sharply. CT images taken at this time showed that only the loose sand within the wormhole started to be scoured away from the top down. The experimental observations suggest that the high sand cuts (20% to 40%) from wells at the start of cold production are due to the growth of wormholes while the sudden decrease in sand cuts (to 1% – 3%) indicates that the wormholes stopped growing. The residual sand cuts observed in the field are likely due to the scouring of the sand within the wormholes.

Introduction

Several heavy oil producers(1–5) have recognized that producing sand with oil significantly enhances primary recovery. The widespread use of progressive cavity pumps has been a key factor in making the Cold Production process economical by reducing the damage to wells caused by the pumping of sand. Elkins et al.(1) were among the first to suggest that high permeability channels, which they called wormholes, develop in oil formations when sand is also produced. The wells were located in the Southeast Pauls Valley Field, Gavin County, Oklahoma. They inferred the presence of wormholes from tracer tests, caliper surveys of the well before and after sand production, permeability calculations and the large volume of sand produced. Vonde(2) reported a significant increase in oil production rates when wells, initially completed with 16 mesh (0.40 mm) liner slots, were recompleted with 250 mesh (6.35 mm) liner slots. The sand cuts also increased to 10% by volume. The wells they investigated were located in the Cat-Canyon Field, California.

Injectivity tests, performed by Amoco, Canada(6), have shown that the concentration of an aqueous solution of flourescent dye did not change after being produced from an adjacent well. In a separate laboratory experiment, these investigators observed that the dye was adsorbed completely after flowing through a sand pack. Since the concentration of the injected dye did not change significantly in the injectivity test they inferred that the dye did not flow through a porous medium. They concluded that the dye flowed through a channel.Undiluted slugs of dye travelled at speeds up to 7 m/min. through what they believed were channel systems over 2 km in length that connected up to 12 wells(6). The wells were located in the Elk Point/Lindbergh fields, Alberta, Canada.
Lithium Silicate Scale In Oilfield Steam Generation
Authors: Zalewski W. , Bulkowski P.
Published: March 2010

At Wolf Lake, steam for in situ recovery of bitumen has been generated from produced water for over two years. Conventional softening of the produced water with warm lime followed by weak acid cation exchange without silica removal was inadequate to prevent scaling of the boiler tubes. Analysis identified the scale as lithium silicate, a material not previously identified as a scale in steam generation. Treatment of the produced water to lower the silica concentration below 50 mg/L has been found necessary and at 25 mg/L adequate to prevent scaling under the operating conditions at Wolf Lake. The concentration of lithium in produced waters is expected to vary with the reservoir, and to be a previously unrecognized determinant in the allowable level for silica in boiler feed water.

Introduction

In situ recovery of bitumen is done primarily by steam assisted methods. This type of bitumen production requires substantial volumes of water for steam generation. The steam to bitumen ratio may be as high as 6:1 which means that to produce 1 m3 of bitumen, 6 m3 of steam as water equivalent are required.

In many areas of heavy oil deposits, fresh water supplies are not readily available. Those fresh water supplies that are available are needed for a wide variety of uses, including domestic requirements, wilderness preservation, agriculture, recreation and industry. Moreover, increasing stress and more stringent quotas for fresh water usage are likely to be imposed on the heavy oil producer.

Therefore, the oil companies producing bitumen, recognizing the competing demands, must recycle the water that is co-produced with the bitumen.

This was recognized a long time ago and extensive research has been conducted on the treatment that could allow reuse of the so called produced waters.

Basically, produced water to be recycled for steam generation must be de-oiled and components that will form scale in the boilers must be reduced to innocuous concentrations.

Traditionally, for oil field steam generation, the scale forming elements/compounds that have to be treated have been calcium and magnesium (hardness), iron and silica.

There is a general consensus what level of hardness and iron is acceptable in the boiler feedwater (BFW) to the oilfields oncethrough steam generators: total hardness expressed as CaCO3 should be less than 0.5 mg/L and iron less than 0.1 mg Fe/L.

However, a much more complicated problem arises with silica. The prevailing opinion among water treatment specialists appears to be that if the feedwater is free of hardness and its alkalinity is high enough (ratio of alkalinity to SiO2 equal to 3:1 being the minimum) silica in the BFW is not a particular problem and higher levels can be tolerated.

The two main manufacturers of the oilfield boilers, Struthers TIW Limited and C.E. Natco, suggest that satisfactory operation of their boilers can be maintained with silica content 100 mg/L and 150 mg/L respectively(1,2): trouble free operations were reported with silica exceeding 200 mg/L(3).
What Causes Booms And Busts In Heavy Oil?
Authors: Miller K.
Published: March 2010

Introduction

Development of Western Canadian heavy oil and bitumen production from the end of price controls in mid-1985 to today has been a roller coaster ride for oil companies and their employees. Activities in response to the current oil price drop suggest this trend is continuing. The results to the oil industry have been fragmented and inefficient efforts to advance technology and a need for repeated reorganization. The results to many employees have been insecurity, career disruption and general frustration. While some may point out that this period of time has seen a great deal of technical development, I feel that much more could have been accomplished under more stable circumstances.

It seems prudent that those of us in the heavy oil industry should periodically stop and ask ourselves why this cycling of activity occurs, and explore options for dampening the severity of the booms and busts. My main purpose in writing this article is to encourage candid dialogue.

Data Collection

When I was contemplating writing an article on this subject, I talked to a number of people working within the Calgary oil patch. Input was obtained from workers in industry, research, education and the government. Nearly everyone expressed strong opinions, but very few gave me the impression they wanted to be quoted or identified. From the perspective of the "soft science" of human behaviour, this high interest in expressing opinions but low interest in public ownership of them is likely an important piece of data.

Statistical data were not hard to locate, but most of these data were proprietary and likely unavailable for citation in this article. For example, some investment companies have detailed documents discussing current events in heavy oil and making predictions about its future. It is a little unnerving to read these sterile, economic prognoses of our chosen field of endeavour. One begins to wonder if the investment companies collectively have the ability to influence the economic state of the oil patch more than their workers do.

There are also a number of commercial analytical studies on the booms and busts experienced in the Canadian heavy oil industry. I will not try to duplicate or improve upon them. My statistics will be limited to noting the scale of the booms and busts by citing that over 26,000 Canadian workers appear to have been laid off between 1985 and 1994(1). The fraction working in heavy oil was not stated, but it was likely a significant number. It would also be very difficult to determine the number of these people who subsequently found employment back in the heavy oil field. Regardless of these unknown factors, it is apparent that significant disruption to the industry occurs during the boom and bust cycles.

Another important conclusion from the historic data is that all booms or busts will end within a few years. They should not be viewed as permanent.
Formation Evaluation of Triassic Naturally Fractured Carbonates In British Columbia
Authors: Aguilera R.
Published: March 2010

Triassic naturally fractured carbonates have proved to be very prolific in British Columbia. The fractures are of tectonic origin and were probably generated during the Laramide orogeny which created a series of compressional type structures.

The formation evaluation was conducted with a dual-porosity model which allowed estimates of matrix and fracture porosities from logs. Water saturation in matrix and fractures were calculated with the use of a statistical procedure without previous knowledge of water resistivity.

In addition, the interpretation led to estimates of bitumen content and percentages of siltstone, limestone and dolomite. The determination of the bitumen content is very important because bitumen can reduce effective permeability to gas quite significantly.

Log Interpretation

Well log analysis of Pardonet-Baldonnel formations was carried out with the use of a dual-porosity model which takes into account the presence of natural fractures and matrix porosity(1). Water saturation was calculated with the use of the P1/2 statistical procedure. P1/2 has a normal distribution for intervals that are 100% saturated with water. Hydrocarbon-bearing intervals deviate from the normal distribution.

Basic Approach

In this process, Archie's basic formation evaluation equations:

Equations (available in full paper)

In the above equations Φ?stands for total porosity (fraction), m is the porosity exponent of the composite system of matrix and fractures, I is the resistivity index, Rt is the true resistivity, A is a function of shaliness, F is the formation factor, Rw is water resistivity at reservoir temperature and "a" is a constant.

Analysis of Equations (4) and (5) indicates that (1) a crossplot of porosity or the response of a porosity log vs. Rt or (2) a crossplot of porosity vs. Rt/ Ash on log-log coordinate paper should result in a straight line with a slope of -m for zones with constant aRw and constant I (Figures 1-A and 1-B). For reservoirs with natural fractures, the value of m is smaller than the cementation exponent mb, determined from a matrix plug in the laboratory at simulated reservoir overburden conditions. This is reasonable because open unhealed fractures produce a reduction in tortuosity and cementation(4).

In many cases, it is possible to carry out the evaluation by crossplotting (Δt - Δtm) vs. Rt or (Δs - Δb) vs. Rt on log-log paper. In these crossplots Δt is sonic transit time as determined from the sonic log, Δtm is sonic transit time at zero porosity, ?s is grain density and Δb is bulk density.

When working with sonic logs in fractured carbonates the usual values of Δtm and Δtf no longer correspond to well defined physical parameters as they do in the case of the well known Wyllie(7) formula. Rather, these parameters have to be determined specifically for each case. We have found through experience that the sonic log is very useful in enlarged boreholes.

The value of m is determined by calculating the slope of the line drawn through the lower points in the log-log plot.
Carbon Dioxode Recovery: Large Scale Design Trends
Authors: Mariz C.L.
Published: March 2010

With renewed interest in enhanced oil recovery (EOR) as existing fields become depleted, there is renewed interest in supplying CO2 for flooding by CO2 recovery from flue gas. This paper examines key design and operating issues and trends for new unit designs which hold the potential for reducing the plant investment and operating costs associated with this source of CO2. The emphasis is on conventional processes using chemical solvents for CO2 removal (such as Fluor Daniel's ECONAMINE FGSM process) as these are either commercial or have been successfully pilot tested. Developments in new tower packings and solvents and their potential impact on plant and operating costs are discussed, as are the effects on these costs of the flue gas source. Operating and capital recovery cost data are provided for 1,000 tonne/d plants which would be a typical size for an EOR project.

Introduction

In the mid 1980s, when crude oil prices were over $30 per barrel, several plants came on line in West Texas in the U.S. which used 30 wt% MEA with special inhibitors to extract CO2 from boiler flue gas for use in EOR. However, when the price of crude oil dropped dramatically, these plants quickly became uneconomic and were scrapped. The then existing process licensors, Dow Chemical and Union Carbide, became less active in promoting these technologies and in 1989 Dow Chemical sold their FT-1 process to Fluor Daniel Inc. Fluor renamed the technology "ECONAMINE FG" and has since licensed three commercial plants, one 320 tonne/d plant at Bellingham, Massachusetts, U.S.A. (1989), a 150 tonne/d plant for Sumitomo Chemical at Chiba, Japan (1993) and a 90 tonne/d plant for Prosint Produtos Sint?ticos at Rio de Janeiro, Brazil (1997). All plants sell CO2 primarily to the food industry. The Bellingham plant, which has a gas turbine exhaust flue gas source, was constructed by Fluor. The Sumitomo plant was constructed by Mitsubishi Heavy Industries (MHI) with the flue gas source from a boiler fired by a variety of fuels including heavy fuel oils. The Prosint plant was owner-constructed and has a boiler flue gas feed source.

In addition, Fluor has performed a number of studies, several of which involved large-scale plants (1,000 tonne/d and larger). These studies were prompted by interest in using the CO2 for EOR and to avoid the new carbon tax being imposed in EC countries. In addition, the company designed two pilot plants for Japan which were used by the owners to study the process for greenhouse gas mitigation purposes. The results from the KEPCO pilot plant have been reported in the literature(1,2). Much of the KEPCO work is applicable to EOR applications as will be discussed later in this paper.

Interest in greenhouse gas emission mitigation has spawned a number of processes for capturing CO2 from boiler stacks that differ considerably from capture by chemical solvents. None of these processes are presently offered commercially and most will remain in the laboratory study phase at least for the near future.
SAGD Comes of AGE!
Authors: Butler R.
Published: March 2010

Canada's remaining resources of conventional crude oil are relatively slight and dwindling, but heavy oil and, particularly, bitumen resources are large. Their quantity approaches that of the resources of conventional oil in the Middle East. Without bitumen and heavy oil, Canada would face a growing requirement for funds to purchase foreign oil. This is already a severe problem for the United States whose large, unfavourable balance of trade stems from its need to import much of its crude oil.

Canada's success in producing bitumen by open pit mining of shallow Athabasca deposits by Suncor and Syncrude and by cyclic steaming at Cold Lake by Imperial Oil has already had a significant impact. However, although these approaches are economic, both have serious limitations.

Open pit mining is limited to shallow deposits and less than 10% of the total Athabasca resource is suitable. Also, open pit mining requires the disruption of the landscape and the handling of tonnages of tailings at least ten times greater than those of the produced bitumen. The disposal of the high clay content, "middling" stream from the hot water separation process which settles at a notoriously slow rate(1) and accumulates in tailings ponds that require prodigious areas is a severe environmental problem.

Imperial Oil's cyclic steaming has considerable environmental advantages since the reservoir solids are left in place. However, it is not a gentle process; the periodic injection of steam at pressures up to 14 MPa (2000 psi) sometimes results in well failure from the large cyclic, thermal, well-stresses. An important limitation of the process is that the recovery of the oil in place is only about 25%. Practical recovery processes for further recovery have not been defined(2). The consumption of fresh water equal in volume to the produced oil places a demand on the environment. SAGD gives a higher recovery and requires less water, less energy and fewer wells. Operation of the process is simpler than cyclic steaming because it is continuous and because of the fewer wells. Efficient recovery of heat from the produced fluids is possible and, because steam is required at a lower pressure, the cogeneration of electric power is more economic.

The SAGD Concept

Steam Assisted Gravity Drainage Process (SAGD) was introduced by the author and his former colleagues at Imperial Oil in the late 1970s(3, 4, 5). It was developed as a more systematic technique for the recovery of bitumen. The concept, shown in Figure 1, is now widely understood and is described in detail elsewhere(6, 7, 8).

It was predicted, from theory, and from scaled model experiments, that production rates of the order of several hundred to over a thousand B/day could be expected from well pairs about 500 m long; this has since been confirmed by the operation of full scale pilots-in Athabasca, in Cold Lake, in Peace River and in Lloydminster.

Essential Features of SAGD

Since gravity does not provide an adequate drive to move heated bitumens to a conventional well at an economic rate(9) horizontal production wells are used for SAGD.
Terra Nova: Building An Industry
Authors: Hawco C.
Published: March 2010

As Newfoundland's second offshore development, Terra Nova is building on the success of Hibernia, contributing to the birth of a new oil and gas industry in Newfoundland.

The decision to proceed with Terra Nova was announced on February 17, 1998. Project Sanction followed a Decision Report from the Canada-Newfoundland Offshore Petroleum Board, approving the Terra Nova development. This report was based on the culmination of a process that provided opportunity for individuals, concerned interest groups, and government to provide input into how the development of the Terra Nova oil field should proceed.

The Terra Nova oil field is located offshore, 350 kilometers east-southeast of St. John's, 35 kilometers southeast of Hibernia, in the most explored basin on the Grand Banks-the Jeanne d'Arc Basin. The field is composed of three fault blocks-The Graben, East Flank and Far East. It is estimated that the reserves for the Graben and East Flank are 370 million barrels of oil, with the undelineated Far East having the potential to add an additional 100 million barrels if successful.

For the Graben and East Flank a total of 24 wells are proposed. Should drilling prove the existence of economically recoverable oil in the Far East block, which appears to be a high probability, an additional five producers and five water injectors are anticipated. Starting in late 2000, Terra Nova expects that oil from the Graben and East Flank will be produced for the first six years at an average rate of 115,000 barrels of oil per day. In 2014, production will decline and be discontinued. If reserves are discovered in the Far East production could continue to 2017.

A Floating Production Storage and Offloading vessel (FPSO) is being developed as the production system for the Terra Nova oilfield. A first for Canada, the FPSO will be the size of three football fields laid end to end, with its hull at 291 metres long and 45.5 metres wide. The vessel's storage capacity is 960,000 barrels of oil, which translates into approximately eight days storage at peak production.

Daewoo Heavy Industries of Korea is under contract to construct the vessel. Detailed design is underway at the shipyard and construction of the hull will begin in August when the first steel plates will be cut. Following the start of vessel fabrication, the keel laying will commence in February 1999. The vessel will then leave Korea in November 1999, to arrive at Bull Arm in late January 2000, ready for the final hook-up phase to commence.

The Terra Nova FPSO will require four major modules between 1000 – 2000 tonnes each, as well as a turret, flare stack and miscellaneous deck assemblies. Two of the four major modules, the flare tower and deck assemblies will be fabricated at Bull Arm, Newfoundland. Additionally, the hook-up and commissioning of the FPSO and topsides will also take place at Bull Arm. The two remaining major modules will be fabricated by BARMAC, a company based in Scotland.
Formation Damage-The Impairment of the Invisible, By the Inevitable And Uncontrollable, Resulting In an Indeterminate Reduction of the Unquantifiable!
Authors: Bennion B.
Published: March 2010

Introduction

Formation damage is a a hot topic these days-with justifiable reason as we move to the exploitation of more and more challenging oil and gas reservoirs in tighter, deeper, and more depleted conditions. As the title of the article suggests, disappointing results from an oil or gas well can be related to a number of factors which may be difficult to diagnose. Some of these may center about inherent reservoir quality characteristics, others about mechanical considerations surrounding the condition and type of the wellbore obtained and still others about the nebulous catchall of "formation damage" which often (and sometimes unjustly) absorbs the majority of the blame for the poor results of many projects.

Formation damage in oil and gas wells is difficult to quantify in many cases, due to the inability of the reservoir engineer to retrieve exact samples and conduct detailed measurements on the area of interest, which usually represents a volume of rock surrounding the wellbore, which is generally several thousand meters below the surface of the earth. However, ongoing research over the years has allowed the development of a variety of techniques which allow the use of the information which is available to us, such as production and pressure data, pressure transient data, log analysis, fluid and PVT data and core, cuttings and special core analysis techniques. These methods provide one a much better indication of the type and degree of damage which different reservoirs may be sensitive to, and, thereby, allow one to adjust operating practices to attempt to minimize or reduce these permeability reducing factors. The subject of this article is to provide a synopsis of some of types of formation damage which commonly present themselves as problems for many oil and gas producing projects, and review some of the associated technology being used to overcome these problems.

How Much of a Concern is Formation Damage Anyway?

A more technical definition of formation damage than that given in the title would be: Any Process that Causes a Reduction in the Natural Inherent Productivity of an Oil or Gas Producing Formation, or a Reduction in the Injectivity of a Water or Gas Injection Well. Formation damage can occur at any time during the life of well: during drilling, completion, production, stimulation, kill or workover operations. Often the problem is ignored due to a combination of ignorance and apathy with the common rationale that-"We don't care about formation damage in this reservoir-we can always fracture through it." Surprisingly this pretense may make sense in certain situations, particularly when the formation is of such low inherent quality that it is obvious that the flow area and driving differential pressure available for production present in a normal cased and perforated or open hole completion are insufficient to sustain economic production rates, even with a totally "non damaged" well.
How to Measure Downhole Steam Quality Using a Thermocouple And a Non-condensible Gas
Authors: Kerr R.
Published: March 2010

One of the critical properties for a SAGD project is the steam quality at the injection point in the wellbore. Steam quality is critical because, in order for a SAGD process to work, a steam vapour chamber must be formed in the reservoir so that oil has a volume to drain into that is less dense than itself. Latent heat of condensation at the vapour chamber walls is the prime mechanism of heat delivery to the reservoir.

Unfortunately, there is no practical way to directly measure steam quality in a downhole environment. The problem is that for a pure-water system, at a given pressure, steam condenses at a fixed temperature as heat is lost. So if we monitor downhole temperatures, we cannot tell how much of our injection steam has condensed. This paper describes a simple, indirect technique that allows a calculation of downhole steam quality, with the single downhole monitor of a thermocouple.

Introduction

Suppose we have a pipe that is conveying high pressure steam. Suppose also, for simplicity, that the pipe is frictionless so that the exit and entrance pressures are equal. At the pipe inlet, the temperature is T1 which is the saturated steam temperature at the pressure of the system.

As the steam moves down the pipe, heat is lost through the pipe walls to the environment surrounding the pipe. These heat losses are reflected in some of the steam condensing to water so that steam quality is reduced continuously as steam moves down the pipe. But at the outlet of the pipe the exit temperature, T2, is exactly the same as the inlet because at a fixed pressure steam condenses at a single temperature.

In the real world there will be pressure drops down a pipe due to frictional losses. But this doesn't change the conclusion.

As long as there is some vapour steam at the pipe exit, measurement of outlet T2 and P2 conveys no information about exit steam quality. This is the problem with downhole steam quality measurements.

Solution

Suppose we have our same pipe as above but now we introduce a small amount of non-condensible gas (at steam conditions)- e.g., C1, C2, C3, N2 . . . etc. At the pipe inlet, assuming we have the same pressure as above, the inlet temperature will be reduced because steam saturation temperature is now determined by steam partial pressure-lower than total vapour pressure. The outlet temperature will not be the same as the inlet temperature because steam condensation will now follow a dew point curve when mixed with non-condensible gas.

In this case (and in the case of pressure drops down the pipe), it turns out that measurement of outlet temperature is sufficient to determine outlet steam quality if we know (or can calculate) inlet steam quality, inlet T1 and P1 and outlet P2. This determination is independent of the flow rate or concentration of the non-condensible gas, for small amounts.
Well Test Data Goes Electronic
Authors: Christie B. , Ibrahim S.
Published: March 2010

Introduction

As we approach the new millennium, the era of the paperless office is becoming a reality. In line with this trend, the Alberta Energy and Utilities Board (EUB) implemented the requirement for Electronic Submission (ES) of well test data, by e-mail, effective March 1, 1999. This is the culmination of a long-term joint initiative by industry and the EUB.

Although the implementation of this electronic process will allow the EUB to substantially improve its services to industry, many companies are struggling with acquiring the "know-how" of ES. In this article, attempts are made to remove some the ambiguities related to ES including software, hardware, and file format requirements.

EUB Database History

The EUB has one of the most comprehensive databases of the petroleum industry in the world. The number of pressure and AOF tests in the database and on microfiche are estimated at around 500,000 tests, with an additional 300,000 DSTs, that date back to 1945.

In the past, a summary of each test was keyed into the EUB database, and the entire report was stored on microfiche. This process is slow and labour intensive, which resulted in a backlog of data delaying its availability. Furthermore, data retrieval from microfiche is tedious, and does not capture the electronic capability of the data. In the situation where well test data was required to be re-analyzed, data from the microfiche was difficult utilize.

In the early 1990s, a joint industry/EUB committee discussed the standards and methods of well testing and data storage, as well as current and future needs. The concept of ES and dissemination of data evolved from these discussions. A system was defined to meet the following criteria:Acceptable standards to all companies, agencies, etc.Simple and user friendlyEasy and affordable accessibilitySecurity of confidential informationCompatibility with EUB legacy databases

The committee had several public meetings to obtain industry's feedback, and the EUB agreed to proceed with ES in 1995. However, government funds were not available until late 1997. On July 1, 1998, the EUB went into production with ES of well test data on a voluntary basis. The deadline of January 1, 1999, for full implementation of ES for well test data was extended to March 1, 1999, to give industry more time for preparation.

The infrastructure developed for ES has an 80 GB " jukebox," with ability to expand to 320 GB. A search engine has been designed for retrieval of electronic data, with selection available by UWI, test type, area, field, pool, operator, date, etc., or any combination.

Overview of Electronic Submission (ES)

In order to standardize the ES process, the EUB now requires all producing companies to provide well test data using only the "PAS" file format (Pressure Ascii Standard). Since no other file format will be accepted by the EUB, it is imperative to comply with this rule.
Gas Production And Decline Rates In the Province of Alberta
Authors: Samson L.
Published: March 2010

In excess of 6,400 new gas wells per year will be required to meet future demand, well above the current tie in levels. Total deliveries of gas from the province of Alberta increased by 56% to 127 E9M3 from 1990 to 1997. Pipeline expansions in late 1997 to 2000 are expected to add a further 26 E9M3. The. total demand by 2002 is expected to reach 177E9M3... A study was conducted to examine the decline trend ofgas wells over the last eight years with a view to predicting the future tie in requirements and the ability of Alberta to meet the increasing demand for gas. The study showed that new sources of gas < are coming on at rates of less than 30 E3M3/D and gas wens rates are declining at 27% the first year. Using the gas well productivity and performance results of the study, predictions were made of future tie in requirements.

Introduction

In 1997, total deliveries of gas from Alberta wells amounted to 127 E9M3, an increase of 56% over 1990 values. The volumes exported to the US almost doubled (Figure 1)(1). The Northern Border Pipeline and the TransCanada Pipelines expansions in late 1997 and 1998, and the Alliance Pipeline in 2000 are expected to add another 31 E9M3 to the annual demand for gas from the Western Canada Sedimentary Basin of which 26 E9M3 will come from Alberta. The EUB estimates that the annual total deliveries of gas from Alberta in 2002 will be 177.4 E9M3.

Part I-Producing Gas Well Statistics

In order to accommodate the increase in production, an increasing number of gas wells have been tied in. At year-end 1997 there were 43,262 producing gas wells (Figure 2), 13,491 more than in 1990. There was a net increase of 3,600 wells in 1994, 1,800 in 1995, 1,900 in 1996 and 3,200 in 1997(2). From 1994 through to 1997, more gas wells were being placed on production than in any previous year. In 1994, 4,456 wells were placed on production and in 1997,4,529 wells were placed on production (Figure 3).

Gas Well Replacement

By comparing the total number of gas wells placed on production in a given year with the incremental net increase in the number of gas wells on production, the number of new wells that replaced gas wells ceasing production can be determined. As expected, as the number of wells placed on production increased, the number of wells ceasing production in anyone year has increased. Over 1,300 wells ceased production in each of the last three years (Figure 4). The average proportion of gas wells required to replace wells ceasing production over the past ten years was 44.8% and over the last three years 39.5%.

Tie in Time for Gas Wells From Finished Drill Date

New wells are being tied in at a faster rate but there is still a significant elapsed time before some wells are placed on production.
Towards Commercialization of the UTF Project Using Surface Drilled Horizontal SAGD Wells
Authors: Komery D.P. , Luhning R.W. , O'rourke J.G.
Published: March 2010

The Underground Test Facility (UTF) Demonstration Project was started in 1984 and the first two phases have been completed. The UTF Project current Phase B-2 is proceeding with the testing of the tunnel drilled Steam Assisted Gravity Drainage (SAGD) wells. The UTF Project is producing about 320 cubic metres per day (m3/d) [2,000 barrels per day (BPD)] of dry bitumen which is trucked to market. The higher than predicted bitumen sales revenue has been reinvested into the project and these extra funds are being used to drill and operate SAGD wells from the surface.

This paper provides some important concepts for using SAGD well pairs drilled from the surface to produced bitumen on a commercially viable basis in the Athabasca Oil Sands.

The expansion demonstration program consists of drilling and completing from the surface, two 750 m SAGD horizontal well pairs, to produce an additional 320 m3/d. This will increase bitumen production from the UTF Project to 640 m3/d (4,000 BPD).

Key features covered are surface drilling and completion of long horizontal wells, steam injection and monitoring, well production control, surface facilities for producing dry bitumen and getting the product to market. The design and operating aspects of a 4,800 m3/d (30,000 BPD) commercial project are reviewed. Project costs and economics favour surface drilled horizontal wells over wells drilled from underground tunnels.

The purpose of this new SAGD technology is to economically develop the 140 billion cubic metres (900 billion barrels) of oil-in-place in the Athabasca oil sands region of Alberta. Of these, more than 50 billion cubic metres (330 billion barrels) are now recoverable using the SAGD technology.

The nine industry participants in the UTF project own about 50% of oil sands leases in Athabasca, hence the high level of interest in developing new technologies to extract the bitumen.

There are other major factors which need to be provided in order to commercially develop this resource.

The paper also outlines the requirements for oil sands development in Athabasca and discusses nurturing the expansion of existing USA heavy oil markets, building a heavy crude oil pipeline from Athabasca region to Edmonton and taking advantage of new technologies such as SAGD to significantly reduce capital and operating costs.

The Underground Test Facility (UTF)

The purpose of the UTF is to test the concept of in situ bitumen extraction using the Steam Assisted Gravity Drainage (SAGD) process.

The key features of the current UTF Project are shown in Figure 1. It consists of two vertical shafts 3.3 m in diameter penetrating 140 m of overburden, 20 m of oil sands and 15 m of limestone below which are located horizontal tunnels 5 m wide and 4 m high. The tunnels are in solid limestone and are larger where the wells are located (8 m wide × 5 m high) and smaller (4 m wide × 3 m high) where the tunnels serve only to complete the access and ventilation circuit.
UTF Project Status Update, May 1997
Authors: O'Rourke J.C. , Begley A.G. , Boyle H.A. , Yee C.T. , Chambers J.I. , Luhning R.W.
Published: March 2010

The Underground Test Facility (UTF) is producing from three tunnel drilled 500 m long horizontal well pairs which have produced effectively at their peak rates and reached recoveries of almost 55% OOIP. Two new pairs of 750 m and 300 m horizontal wells have been drilled from the surface and were started up in April 1996. Start-up performance and well control methods have been successful. Another 750 m horizontal well pair is to be drilled from surface in the spring of 1997 and started up in the fall of 1997. Its purpose is to test methods of operating a well pair next to a depleted reservoir without losing steam to it. Net revenue from the UTF Project has funded the costs of adding three surface well pairs and related plant facilities since September 1994. The UTF Project is owned by AOSTRA with nine industry participants, including Gibson Petroleum Company Limited who was appointed Project Operator in October 1995.

Introduction

This is the third in a series of papers presenting the development status of the Steam Assisted Gravity Drainage (SAGD) process at the Underground Test Facility (UTF) situated 70 km northwest of Fort McMurray, Alberta (Figure 1.1). The first paper(1), presented in 1991, covered the initiation of the UTF Project from 1984 to May 1991. It discussed the rationale for starting the UTF, the basic SAGD process, the facilities (shaft, tunnels, underground drill rig, Phase B plant), the results of the three Phase A well pairs, and the drilling and design of the three Phase B well pairs which had not yet started up. The second Paper(2) reviewed the start-up and performance of the three Phase B well pairs and facilities which had produced 500,000 barrels of bitumen at that time, May, 1994. It also discussed the economics of a potential 30,000 bpd commercial SAGD recovery project.

The current paper looks at the continuing performance of the Phase B wells and facilities which have produced over 2,400,000 barrels of bitumen; the design and April 1996 start-up of two pairs of SAGD wells drilled from the surface (Phase D) which have produced over 170,000 barrels of bitumen; the design of a third surface well pair to be drilled in the spring of 1997 to test the methods of placing and operating a new well pair next to a depleted reservoir without adverse effects; the features of a produced water recycle plant scheduled for start-up in the fall of 1997; and concludes with a brief discussion of some commercial aspects related to the economics of the SAGD process at the UTF and the marketing of bitumen.

The UTF Project is currently owned by the Alberta Oil Sands Technology and Research Authority (AOSTRA) and funded jointly by AOSTRA (25%) and nine industry participants (8 113% each). In addition to Gibson, the industry participants are: Amoco Canada Petroleum Company Limited, Chevron Canada Resources Limited, China National Petroleum Co. (Canada) Ltd., Imperial Oil Resources, Japex Oil Sands Limited, Petro-Canada, Shell Canada Limited, and Suncor Inc.
Beam Pump Balancing Based On Motor Power Utilization
Authors: McCoy J.N. , Drake W.A. , Collier F. , Ott R.E. , Podio A.L.
Published: March 2010

With more and more emphasis on reducing the operating costs for beam units, operators are examining several approaches to cut costs. One of the biggest costs in beam unit operations is the electrical power cost.

Controlling pumping units to adjust to the optimum counterbalance will reduce the electrical bill. Several pumping untits have been checked with a PC software program (POWER), which allows the operator to determine how far out of balance the units are and what it will take to properly balance them. Properly balanced pumping units will result in electrical savings both in demand and in consumption, thus reducing total electrical costs.

Examples from several fields are provided illustrating actual power costs and the reduction in expenses that occurred.

Introduction

The first approach in determining whether the pumping unit requires re-balancing or motor downsizing is to conduct a power survey of the field. When the POWER software first became available, it was used on several individual wells to determine if the unit had an out of balance problem or the motor was too large. The "POWER" program requires actual data. Two current and three voltage probes are connected to the incoming electrical lines. During two strokes of the pumping unit, power and current data is stored in computer memory for interpretation. The power data is converted to gear box torque and if out of balance condition is observed the program recommends the counterweight adjustment required to achieve a better balance. The actual time to measure these values is small, but all the data is necessary to properly interpret the condition of the well. If the well is operated with a pump-off controller, one must determine the condition of the well for the majority of the run time, since pumping conditions may vary widely from first coming on to just before pump-off.

The first small field surveyed consisted of 17 producing wells in the Waddell Field, near Crane, Texas. Production depths ranged from 2,635 m to 2,937 m (8,700 to 9,700 ft.) and all wells were equipped with beam pump units. The Waddell field has a history of high gas-oil ratios, which has caused some lifting problems in the past. Incomplete pump fillage is not uncommon since, in some cases, the tubing intake is located above the perforations, due to the presence of liners and open-hole completions.

Direction of pumping unit rotation was checked to determine the direction that resulted in lower electrical power consumption. In some cases, changing the direction of rotation did help reduce the electrical power costs and the rotation was permanently changed to take advantage of the savings. Other work was performed to determine which tap on a high-slip motor is best, and whether direction of rotation makes a difference in operations. Preliminary recommendations are to operate in the high-torque mode and rotate counterclockwise, unless rod overloading becomes a problem.

Table 1 lists the wells in the Waddell area and data gathered from the field survey.