bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

Abstract
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

Abstract
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 &lt; 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

Abstract
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&apos;Rourke J.C. , Begley A.G. , Boyle H.A. , Yee C.T. , Chambers J.I. , Luhning R.W. 
Published: March 2010

Abstract
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

Abstract
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.