bluuebunny/crossref_metadata_2025 huggingface dataset:
Oilfield Hospitality-worldwide
Authors: Welsh George
Published: March 2010

Introduction

In mid-1973, my wife and I made our first venture overseas-an assignment in Africa. During the next eight years, we worked and lived in Zaire, Angola, Iran, Dubai and as a sort of anticlimax, in Scotland. Being in the oilfield service business meant fairly extensive travel throughout southern and western Africa, the Middle East and Northern Europe.

The experience was pleasurable, startling, frustrating, exciting, but never dull. Wherever we went, we found that "oilfield types" made us welcome and helped us get started-this was especially important at the outset. On given days during the first few months, if we"d both said out loud what we felt, we"d have come home in a hurry.

Africa

For a couple of Prairie types, it was quite a shock to be plunged into equatorial Africa with its masses of people (well below the poverty line), the heat and the humidity and the "crawlies"; and above all, the smell-a strong pungent odour unique to Africa that took a lot of getting used to. The mostly "dictatorial" regimes were abrupt departures from the Canadian way of life.

We stopped in Lagos, Nigeria (our company's West African regional headquarters) for the first ten days, where we received many good tips on overseas living that were to help us considerably in our subsequent postings. It was very enlightening to see how our expatriates and those of others in the oil business were coping and had coped through tough (even war) times.

My first posting was in Kinshasa, Zaire (formerly Leopoldville, Belgian Congo), where I was to set up an office from which I could manage and sell our company's land and offshore services in Zaire, Cabinda, Angola, South Africa, etc. It was also necessary to the company's other West African operations in Gabon, Congo-Braza, Cameroons, Nigeria, etc.

As a Canadian working for an American-French company, I was able to caU on several embassies, as the occasion required. In this instance, I received the most help from the French Embassy's commercial attache-a lady who has spent several years in Africa. We also were helped greatly by a major oil company's employees and their wives, who opened their homes to us and made adjusting so much easier-especially as I travelled a lot. Being made welcome at the U.S. Embassy's Social Club also made life much more enjoyable.

We will always remember Louie, our local driver in Kinshasa, an excellent chauffeur who knew the city like the back of his hand and was just a little bit larcenous. He was mostly happy, but when I was away, he had to take orders from my wife, which didn"t please him because women in Africa usually take orders from men. Communications with Louie were in so-called French (his badly fractured and ours little better than the "corn flakes box" level), plus a lot of arm waving. It's interesting as to how well this kind of communication can work when both sides really try.
Administration Ofthe Bituminous Oil Sands Of Alberta
Authors: Warne G.A.
Published: March 2010

The exposed bituminous oil sands at Athabasca appear to have first received the attention of white settlers in 1719 when Henry Kelsey, one of Hudson's Bay Company's early Governors, observed a sample of bituminous sand brought to him at Fort York(1)). One of his Cree employees had travelled to the Athabasca valley and brought back a sample of "gum or pitch" taken from the river bank. Although the bituminous sands sample did not impress Kelsey in 1719, the resource was recognized as having enormous potential by others who followed close behind him. Extensive efforts have been made since then, by provincial, federal and industry interests to improve the understanding of the resource, establish its economic potential and ensure that it is developed in the best interests of Alberta and Canada.

Early Disposition of Rights

The first disposition of rights to develop the oil sands was made in 1901 by the Privy Council of Canada(2). Seven tracts comprising 12,725 acres along the Athabasca River at and north of Fort McMurray were patented for surface, asphalt and petroleum and natural gas. Regulations for the "Disposal of Tarsands, the property of the Crown", in that portion of Alberta lying north of Township 80 between the 4th and 5th Meridians were approved by Order of the Governor in Council in 1910. Tar sands were interpreted in the regulations as:

" ...the sands and other material impregnated with tar, bitumen, petroleum, oil and other like substances found in deposits in the northerly portion of the Province of Alberta".

Soon after this in 1912 the regulations were suspended and each application was considered on its own merits.

In total some 21 leases were issued by the federal government. However, only four were in existence at the time of the transfer of the administration of the resources to the province in 1930. It appearsonly the leases held by Mr. Draper resulted in the construction of a plant and other significant operations prior to the transfer. However, in the late 1920s International Bitumen Company had commenced work at Bitumount leading to the major pilot extraction operations there in the 1930 to 1950 period.

The first regulations issued by Alberta for the disposal of bituminous sands deposits, the property of the Crown in the Province of Alberta, were issued by order in 1930.

Between 1930 and 1951 provincial agreements for development of the sands were entered into with companies and individuals including: Max Waite Ball, International Bitumen Company Limited, Abasand Oils Limited, and Lloyd Rogers Champion.

Of this group of dispositions only that of Max Waite Ball of Denver, who also formed Abasand Oil, was continued. His work led later to the Great Canadian Oil Sands (now Suncor) development.

A major bituminous sands conference was arranged by the Alberta government in September 1951 to study factors affecting bituminous sands development. In conjunction with the conference, Honourable N.E. Tanner, then Minister of Mines and Minerals, gave a: policy statement regarding prospecting permits and leases.
Chemistry In Enhanced Oil Recovery- An Overview
Authors: Boon J.A.
Published: March 2010

During the primary production stage of a reservoir, oil moves to producing wells under the influence of "natural forces" provided by mechanisms such as expansion, compaction, gas drive,' natural water drive and solution gas drive. During the secondary recovery stage, water is injected at appropriate points into the reservoir to displace the oil toward the producing wells. Because of bypassing and capillary forces, 40% to 70% of the original oil in place is left behind. Further, many reservoirs are not amenable to waterflooding. The term ‘Enhanced Oil Recovery’ refers to all processes (other than water flooding) in which energy and chemicals are supplied to the reservoir to establish pressure gradients, modify interfacial tensions and wettability, adjust the mobility of the driving fluid, alter the permeability of selected zones and change fluid properties in such a way that oil flows toward the producing well in a controlled manner(1).

Incremental recovery potential on a world scale amounts to 32 × 109 m3, whereas new discoveries are estimated at 32 –64 × 109 m3(2). The EOR potential in Canada is 0.64 × 109 m3, as compared to remaining conventional reserves of 1.0 × 109 m3(2).

Background Theory

The residual oil saturation that can be achieved is determined by both macroscopic and microscopic displacement efficiency. The former is reduced by large permeability variations in the reservoir and an unfavourable mobility ratio: if the displacing fluid is more mobile than the displaced fluid, viscous fingering occurs. The latter refers to the entrapment of oil blobs at the pore-size level by capillary forces. The most important parameters characterizing these forces are interfacial tension γ, contact angle θ and capillary pressure Pc= Po - Pw (Fig. 1). Both macroscopic and microscopic phenomena can be manipulated by controlling the chemistry at the oil-water-sand interfaces and in aqueous solutions, hence the great importance of chemistry to enhanced oil recovery.

Contact Angle

Contact angle influences fluid distribution, displacement processes and oil-water relative permeabilities. Recently, Teletzke et al. (3), on the basis of gradient theory predicted that when a solid phase is contacted with two liquid phases that coexist near their critical temperature, one of the two will perfectly wet the solid (Fig. 2). They also predicted that a first-order film transition occurs at the "critical surface temperature" Tcs; two wetting films of different thickness are in equilibrium with each other (Fig. 2). At the "critical wetting temperature" Tcw, perfect wettability is lost and the fluid-fluid interface appears to intersect the solid surface at an angle 8 (Fig. 2). Gradient theory assumes that the Helmholtz free- energy is composed of a homogeneous fluid term, a species interaction term in regions where density gradients occur and a term that accounts for molecular interactions between fluid species and the solid. There is good experimental evidence for the existence of Tcw but empirical proof for the film-film transition at Tcw has not yet been reported.
Incorporation Of Vertical Permeability Test Results In Vertical Miscible Flood Design And Operation
Authors: Gillund G.N. , Kamal M.
Published: March 2010

The original analysis of the Bigoray Nisku B miscible flood indicated potential coning problems related to the level of vertical permeability. This paper presents the results of a vertical permeability lest which were incorporated into a coning study. Additional reservoir data, along with the rate information from the coning study, will be used to revise the original reservoir simulation prediction and depletion Strategy.

Introduction

The miscible flood in the Bigoray Nisku B pool was initiated in February 1980. It was recognized at the time that the pool was subject to coning and that controlled production rates would be required to control solvent breakthrough. Since that time, additional work and studies have been carried out to refine and optimize production strategy.

History and Description

The Bigoray Nisku B pool (Fig. 2), part of the West Pembina play shown in Figure I, was discovered in April 1978 with the drilling of Well 13–9. Well 8–8 was drilled about one year later, in June 1979. Soon after that time, the possibilities of a miscible flood were investigated(1) and solvent injection was started into Well 13–9 in February 1980. The same studies showed that an additional well would increase recovery and allow higher producing rates since coning prevented the wells from reaching their full potential As a result, Well 9–8 was drilled in July 1980 and Well 16–8 in October 1982.

The historical production rates are shown in Figure 3. Note that prior to drilling Well 16–8 the allowable of 266 m3 /d was not being met. The full allowable is now being produced as a result of drilling this well.

The Nisku B pool is a pinnacle reef with a maximum thickness of 95 m and an oil in place of 1500 × 103m3. The measured core permeability averages 130 md; however, the indicated effective permeability value is much lower. Pay is streaky and vugular. Well 13–9 is limestone, 9–8 and 8–8 have been do1omitized and 16–8 partially so.

Vertical Permeability Test

The original model study demonstrared that coning was going to be a potential problem and some preliminary coning studies confirmed this tendency. Prior to conducting a proper coning study, it was felt that it was necessary to compare core and in-place values of permeability and Well 9–8 was chosen for this purpose.

Well Location and Test Intervals

The location of the test (9-8-52-8W5M) is shown in Figure 2. The well bore configuration during the test is shown in Figure 4. Due to the relatively large thickness of the formation it was recognized that testing more than one interval would be preferable and, therefore, two tests were run over two different intervals. However, only the first test, which is discussed in this paper, was successful. In this test, oil was injected in the upper perforations, centred at 2357.0 m. and the pressure were measured at the lower perforations centred at 2374.1 m. After the conclusion of the first test, a third set of perforation (not shown in Fig. 4) were shot at 2322.9 m.
Ice Management In The Labrador Sea
Authors: Miller J.D. , Greenhorn M.J.
Published: March 2010

Introduction

The Labrador Sea is known as a hostile environment to all forms of marine activities. The region is buffetted by numerous storms every year which bring high winds, severe seastates and superstructure icing. For vessels attempting to navigate through the region the presence of icebergs present a year round hazard and sea ice, present during the winter and spring months, restricts the trafficability of vessels.

It is in this environment that the Labrador Group of Companies has undertaken an extensive program of exploratory drilling over the last decade. To date, some 23 wells have been drilled by this consortium, primarily on the offshore banks and the saddles between these banks. To ensure a safe and successful drilling operation, special attention has been given to the environmental constraints and programs have been developed to minimize their effect. In this paper we will present some of the aspects of the iceberg problem and the ice management techniques in place to deal with them.

Setting

Icebergs are found throughout the region encompassed by the permit acreage within the Labrador Sea. It is difficult to generalize on the presence of icebergs over the entire Labrador Sea region as their presence is variable in time and space. There exists an annual variation which sees the largest numbers of icebergs present in the May and June period, decreasing throughout the summer to a local minimum in October and November and then increasing to a late spring peak. The variability between years, in terms of the total numbers of icebergs recorded, is largely unknown in this region although there are large differences between a light and a heavy iceberg season. Farther south, at the boundary of the Grand Banks, the variation is from a minimum of zero icebergs to a maximum of about four times the mean annual value. The distribution of icebergs within the Labrador Sea shows a decrease in the number of icebergs present with increasing distance from the coastline. Also, at a given point in lime more icebergs will be present in northerly regions than in those farther south. The reduced fluxes with distance offshore and southward along the coast indicate both the deterioration of icebergs and the divergence of icebergs from the surveyed region. A variety of mechanisms, both mechanical and thermal, influence the decay of icebergs in this corridor and their interrelationships are only qualitatively understood.

The Equipment

On the Labrador Shelf drillships have been used predominantly. Their deck load and cargo capacity permits operation in remote areas with minimum resupply. Dynamically positioned drillships have been preferred due to their ability to move off and back onto a well quickly when threatened by Ice or icebergs. This capability maximizes vessel safety and minimizes costs due to downtime.

The dynamic positioning system enables such a drilling unit to maintain position over the wellhead using ship's power alone.
CESAR
Authors: Hobson George D.
Published: March 2010

CESAR (Canadian Expedition to Study the Alpha Ridge), a program of the Department of Energy, Mines and Resources, was conducted from an ice station on the Arctic Ocean between March 30 and May 23, 1983. The base camp was established near 85 °52' north and 112 °34' west, 420 km north and west of Ellesmere Island and drifted in an irregular manner for the duration of the project. Preliminary disclosures were made at a one-day symposium (May 31, 1984) at the CMOS/COU meeting in Halifax. A digest of the geological and geophysical interpretations follows.

In cooperation with the Canadian Hydrographic Service some 1300 individual depth soundings and gravity measurements were established over the Ellesmere Island Continental Shelf and Alpha Ridge to the 116 degrees west Meridian. In addition, about 120 kilometres of echo sounding and gravity recordings were established along the drift track of the CESAR station. A 100-m contour bathymetric map and a 10-m Gal contour free-air gravity anomaly map have been compiled and include data collected from Ice Island T-3 between 1969 and 1974 just before grounding for several months off the northern coast of Ellesmere Island. Unlike the Lomonosov Ridge, investigated in 1979 during Project LOREX, the topography of the Alpha Ridge is complex and rugged, showing ridges, grabens, seamounts, etc. in profusion. The minimum depth recorded over the Alpha Ridge is 1087 m. The Alpha Ridge joins the Continental Shelf at a depth of between 1800 and 2000 m. In general, the gravity free-air anomalies mirror the ridge topography and, over this portion of the Continental Shelf, the gravity map reveals similar positive elliptical free-air anomalies that have been mapped all along the Canadian Arctic and the Alaskan Continential Shelf; these are considered to be indicative of the transition between continental and oceanic crust. Based on gravity data alone, the Alpha Ridge might be interpreted as continental crust.

During CESAR, sixteen Benthos piston cores and twelve gravity cores recovered as much as 6 m of sediment from the southeastern Alpha Ridge. In total to date, approximately 600 cores have been recovered and studied from the various ice stations in the Arctic Ocean. The cores provide the first information on the lithology and age of sediments covering the Alpha Ridge crest and adjacent grabens. Initial studies indicate a correlatable sequence of litho-facies that range in age from ate Cretaceous to Recent. The graben and basins on the flanks of the northern Alpha Ridge are filled with about 250 m of unconsolidated sediment of which the top 6 m is a continuous section of Lower Pliocene to Recent mud. Most facies of this mud can be correlated with U.S.G.S. cores from the Southern Ridge, western Alpha Ridge and Chukchi Rise. Planktonic and benthic foramanifera appear at intervals in the cores with coarse detrital material interspersed. Pollen has also been observed in the cores but is not as yet identified.
"Safety Offshore Eastern Canada"
Authors: Charchuk Noel
Published: March 2010

The Royal Commission Goint Federall Provincial) on the Ocean Ranger Marine Disaster that occurred on the Continental Shelf off Newfoundland and Labrador on February 15, 1982, was established to investigate the sinking of the Ocean Ranger. The first section of its report was made public in mid-August.

The conclusions reached by the Commission were similar to those of the U.S. Coast Guard and the National Transportation Safety Board. The disaster was caused by a chain of events, starting with a severe storm breaking the glass in the porthole of the control room, allowing seawater to contact the ballast control panel, causing short circuits. This event, in turn, caused the ballast control valves to open and close. The lack of knowledgeable crew intervention caused the list of the rig to worsen, until the chain lockers began to take on water, leading to the capsizing of the rig.

Several weaknesses in design were pointed out in the report. The location of the control room and the strength of the glass in the porthole were not satisfactory. The ballast control panel had many sensitive electronic controls which were not suitable for use in an area where seawater could conceivably enter. The openings to the chain lockers were not water tight and could not be pumped out so that when water began to enter, the severe list was worsened.

Also condemned in the report was the delay in starting search and rescue proceedings as well as the lack of adequate search and rescue capability stationed in St. John's. The second phase of the Commission's task began the, next week when a three day conference was held in St. John's.

The conference, Safety Offshore Eastern Canada, took place August 21 to 23 and featured an international cross section of experts. The reports and Submissions will be used by the Commission in preparation of the final report.

Representatives of various companies involved in the offshore regulatory bodies from other countries having offshore activities and consultants presented papers and discussions on environmental and design criteria, safety considerations and on excape and survival in cold ocean environments.

A further session of public hearings will be held in the fan prior to the final report of the Royal Commission.
Enhanced Oil Recovery: Retrospect And Prospect
Authors: Watkins G.C. , Sharp K. Chant
Published: March 2010

Introduction

Outside of the ‘oil patch’, few people are aware that an oil reservoir normally will yield only a fraction of the oil held underground. However, much time and effort has been devoted to projects designed to recover a higher proportion of oil-in-place, to what in industry jargon is called enhanced recovery techniques.

At present, enhanced recovery schemes1 account for about one-third of Alberta's conventional recoverable crude oil reserves. And as in the fullness of timeexploration prospects suffer from depletion, the ability to obtain more from what has already been found becomes of progressively greater importance as a source of additional oil supply.

This paper looks at various aspects of enhanced recovery over the last decade or so, focussing on experience in Alberta where some 85 per cent of Canada's current conventional oil reserves is located. Trends in the nature and volume of reserves, costs, pricing provisions and economic incentives are examined. Finally, comments are made on the future outlook.

Enhanced Recovery Reserve Trends

Table 1 shows data for selected years on key features of Alberta oil reserves over the past decade. Over the 1973 to 1983 period, the

TABLE 1. Recent trends in Alberta oil reserves. Available in Full Paper.

average recovery factor for Alberta crude oil reserves fell by four percentage points [Column (2), Table 1], a reflection of a shift in the mix of reserves toward those with lower primary recovery factors especially heavy oil deposits such as Suffield and Provost. The relatively static volume of enhanced recovery reserves [Column (3) has somewhat reduced the share of such reserves in the over-all total [Column (4)] 2. The decline of late in the enhanced reserves recovery factor [Column (5) J is caused by the downward revision of many light and medium oil waterflood schemes. Examples here include Judy Creek BHL and Pembina Belly River.

In short, the story of the last decade is that enhanced recovery reserves have shown no distinctive trends: they account ow for much the same proportion of provincial reserves as they did in 1973;similarly, the average recovery factor for enhanced recovery schemes has remained virtually constant.

These trends seem disappointing in that although oil prices have been subjected to government controls nevertheless average wellhead prices rose over the decade by some $164/m3 ($26/bbl), an increase very considerably in excess of the rate of inflation. In other words, prices rose markedly in real terms. Ostensibly, suchan environment should and/or would ake the inception of new enhanced recovery schemes-especially those economically dubious at lower price levels more attractive and lead one to expect a strong growth in enhanced recovery reserves3. What, then, has happened to thwart the inception of more enhanced recovery schemes? The answer must lie in the interaction of the key elements of costs, ‘net back’ prices and technological scope. We look at each of these in turn.
Round-Up Of 1984 Tax Cases
Authors: Parsons Robert B.
Published: March 2010

Some years go by without Canada's courts hearing any tax cases of interest to the oil and gas sector. However, 1984 offered ample reading for the industry. This month, Tax Topics reviews four cases which could impact in some way on various aspects of doing business in the oil and gas industry. The score: Revenue Canada 2 – taxpayers 2. Read on.

Investment Tax Credits

The investment tax credit system was first introduced in 1975 as a means of stimulating capital expenditures in Canada. Under the system, taxpayers can earn a credit equal to a percentage of the actual cost of qualifying expenditures. The credit can be applied to reduce the taxpayer's federal income tax liability. The rate of credit varies from 7% to 35% of the cost of eligible assets. The determination of the amount and availability of the credit depend upon the asset's location, the type of asset, the activity in which it is employed, and the tax status of the taxpayer.

Section 13(7.1) of the Income Tax Act requires, generally speaking, that a taxpayer reduce the capital cost of a fixed asset by the amount of government assistance received by the taxpayer with respect to the asset.

In two recent decisions by the Federal Court, Trial Division, the court concluded that the income tax legislation did not require the taxpayers to reduce their capital cost of fixed assets for capital cost allowance purposes by the amount of investment tax credits claimed by the taxpayers during their 1975 to 1977 taxation years. Although these particular cases did not deal specifically with the oil and gas industry, the issue addressed by these cases should be of interest to any oil and gas investment which involved fixed asset acquisitions in the years 1975/77.

In the 1984 cases of AEL Microtel Limited vs The Queen and British Columbia Forest Products Limited vs The Queen, the court held that Section 13(7.1) did not apply from 1975 to 1977 to investment tax credits available under the Income Tax Act. The court noted that the intention of subsequent amendments to Section 13(7.1) in 1978 was to enact, in explicit language, that investment tax credits claimed by a taxpayer are to be deducted from the capital cost to the taxpayer. Since no such explicit provision was in the prior legislation, the court concluded that there was no intention that investment tax credits should reduce the capital cost. "The amendment demonstrates a different intention clearly expressed, but applicable only to the 1978 and subsequent taxation years." Revenue Canada has appealed the decision. In the interim. Revenue Canada has stated that their position remains unchanged.

In light of the decision, aggressive taxpayers may consider the possibility of adding the amounts of any investment tax credits claimed in the period 1975 to 1977 to the opening balance of the current year's undepreciated capital cost of fixed assets, if the amounts were previously excluded.
Heavy Oil Research In Saskatchewan
Authors: Hutchinson Jim
Published: March 2010

Saskatchewan's estimated 25 billion barrel heavy oil resource presents a ajor business opportunity for the oil industry, a major economic opportunity for the province, and a significant source of supply of petroleum products for Canada. However, the nature of the oil -viscous and heavy, and the nature of the reservoirs-thin and heterogeneous -make it a difficult resource to recover, transport and process. Less than two per cent of our heavy oil resource is, at present, considered to be producible and of this less than half remains.

What are the opportunities and challenges that lie ahead? The 1990 demand for Saskatchewan heavy oil ranges from 100,000 to 150,000 barrels/day. Primary production by 1990 is expected to be between 50,000 – 60,000 barrels/day. Therefore, enhanced recovery of heavy oil will need to be between 40,000 and 100,000 barrels/day to meet the anticipated demand in 1990. This is a far cry from the present 9,000 barrels/day. Thus with the added complications of price uncertainty and diluent supply, the oil industry in Saskatchewan faces a major challenge over the next five years.

What can the government do to help? The Saskatchewan Government has made it a priority to encourage greater production and use of this very large, but elusive heavy oil resource in order to optimize the economic benefits to the province. The four-point strategy being used to realize this policy to increase heavy oil production has been designed to:Create a more attractive fiscal regime.Establish more secure markets for heavy crude.Stimulate the development of the technology and know-how needed to effectively recover and utilize heavy oil.Ensure environmental and land-use issues are addressed.

This article deals with the third point stimulating the development of new heavy oil technology.

New technology is not the factor that will drive heavy oil development-prices and markets will But new technology is needed to allow heavy oil development. Permit me an analogy. Current recovery technology is analogous to a family sedan. While prices may fuel activity and markets may provide a destination to set out for, it is enhanced recovery technology that is our vehicle to get there. Unfortunately, heavy oil represents very rough terrain. Our current recovery technology-the family sedan-is not likely to get us over this terrain, ven if prices provide the necessary fuel and markets provide a clear destination. What we will need to get over this rough terrain is new enhanced recovery technology that is the equivalent of a 4 by 4 off-road vehicle. That is, new recovery technology and know-how will be needed if we are to take full advantage of improved prices and markets.

How will we solve these technical problems? From a "funding" point of view, the oil industry is allocating funds to in-house research and to field pilot demonstrations. As well, the Governments of Saskatchewan and Canada have established The Heavy Oil Research Program, which is making $28 million available between April 1985 and March 1988.
Simulation Of The Saner Ranch Fracture-Assisted Steamflood Pilot
Authors: Soni Y. , Harmon R.A.
Published: March 2010

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

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

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

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

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.