COILED TUBING: When and how

Coiled tubing was first developed during World War II as a part of Project PLUTO.
PLUTO stands for PipeLine Under The Ocean. To support the landing of allied troops in Normandy it was necessary to provide sufficient amounts of fuel for the front in France. There had to be some supply from England and it seemed too dangerous to transport the required amount of fuel by tanker. Besides, there were initially no harbors to offload.
What was needed was a pipeline under the channel from England to France.
The pipeline had to be laid in a single night during the hours of darkness and this
was impossible using standard pipeline technology.
The solution that was proposed and developed was coiled tubing: a continuous
string of tubing, spooled onto a drum and unspooled across the English Channel.
By the end of WWII, a total of 23 pipelines had been laid across the English
Channel, supplying fuel for the allied forces. Seventeen pipelines were 30 miles
long and six pipelines were 70 miles long.

WORLD DEPOSITS

Origin

There is no single explanation for the origin of all heavy and extra-heavy crude oils or bitumens. There is evidence that light ends have been lost through differential migration or microbiological attack on some medium and light oils while in their reservoirs. It has also been suggested that some heavy and extra-heavy crude oils and bitumens are formed as a result of oxidative processes that occur when oxygen-bearing ground water invades a petroleum-bearing reservoir. Neither of these processes, however, can account for the particularly high content of vanadium or combination of vanadium and sulfur, in some of these crude oils and bitumens.

Occurrences

Heavy and extra-heavy crude oil and bitumen occurrences are widespread, being known on all continents, at depths as great as 4,000 metres, in rocks of various lithologies and ages, and under all climatic regimes both on and offshore. Reliability of information on these occurrences has been improving with time in the last few years. In the past, such information was scarcely available even with respect to heavy and extra-heavy crude oil deposits discovered and left “behind the pipe” to produce higher quality reservoirs, plugged and abandoned, or else never tested. The amount of heavy and extra-heavy crude oil and bitumen resources estimated in the world today and recoverable by existing or presently visualized technology exceeds 160 billion metric tons (1,000 billion barrels). Estimates of the total amount of resources in-place range between 600 and 1,000 billion metric tons (3,800 and 6,100 billion barrels). Current annual world heavy and extra-heavy crude oil and bitumen production is believed to be in excess of 190 million metric tons (1.2 billion barrels) and cumulative production in excess of 7 billion metric tons (45 billion barrels); these estimated are incomplete with respect to the Russia and China. The countries with the largest reserves of heavy oil and bitumen are Kuwait, Former Soviet Union, Venezuela and Canada. In Canada, Alberta and Saskatchewan have the majority of the deposits; there is a small deposit at Hay River in northeastern British Columbia.




Heavy Oil and Bitumen in Alberta

The bitumen or oil sands of Alberta are found in the oil sands ‘triangle’ of northern Alberta: from Peace River to Fort McMurray and south to Cold Lake. Heavy oil is found south of Cold Lake along the Alberta – Saskatchewan border to the US border.

In 2001, heavy oil production surpassed conventional oil output for the first time, producing about 120,000 m3/d vs 115,000 m3/d for conventional oil. Bitumen production is about 43% of Alberta’s crude production in 2001. In 2004, it was more than 50%.

Table HOB-2 shows the Alberta original-bitumen-in-place (OBIP) and reserves; taken from the EUB Statistical Series 2002-98:



Recovery Method
OBIP
(109m3)
Initial Reserves
(109m3)
Cumulative Production (109m3)




Surface Mining
18
5.6
0.4
In-Situ
241
22.7
0.2




Total
259
28.3
0.6

Table HOB-2 Bitumen Reserves

The surface mineable area is defined by the EUB as an area of 37 townships north of Fort McMurray consisting of the Athabasca Wabaskaw – McMurray deposit where the overburden is less than 75 m. Deposits greater than this depth will require in-situ (“in-place”) methods such as SAGD, CSS, steamflooding, Vapex and other techniques.

The three active mineable projects are, in respective sizes, Syncrude, Suncor and Albian. Synacrude is a joint venture owned by Imperial Oil, PetroCanada, Canadian Oil Sands Ltd., Conoco Inc, Nexen Inc, Nippon Mitsubishi Oil Corp., Mocal Energy Ltd and Murphy Oil Corp. and began operation in 1978. Albian is a consortium of Shell Canada Ltd., Chevron Canada Resources Ltd. and Western Oil Sands L.P. Suncor began operations as the Great Canadian Oil Sands in 1967. About two tonnes of ore has to be mined to produce 1 barrel of oil. As of January 2002, Table HOB-3 shows the project development areas:




Development
Project Area
(ha)
Mineable Volume (106m3)
Mineable Reserve (106m3)
Cumulative Production (106m3)





Syncrude
21672
1433
959
250
Suncor
15370
878
604
144
Albian
10096
574
178
0





Total
47138
2885
1741
395

Table HOB-3: Established Mineable Bitumen Projects

In Table HOB-4, the in-situ projects under development as of January 2002 are shown:

Development
OBIP
(106m3)
Recovery
Factor
%
Reserve
(106m3)
Cumulative Production (106m3)





Peace River (Thermal)
21.6
40
8.6
6.4
Athabasca (Primary)
2435
5
122
10.8
Cold Lake (Thermal)
803
25
201
107
Cold Lake (Primary)
4948
5
247
33
Lindbergh (Primary)
1309
5
65
4
Experimental Schemes
95
24
10
6





Total
9613

645
167

Table HOB-4: In-Situ Bitumen Projects

Within the Cretaceous sands, the crude bitumen was evaluated using a 6 weight percent (defined later) minimum saturation and 3 m pay cutoff for mineable areas; and 3 weight percent minimum saturation and 1.5 m pay for in-situ areas. In addition to the accessible oil deposits, there is a carbonate bitumen deposit below the in-situ and mined area which is not yet economical to develop.



As of January 2002, over $17 billion has been spent on oilsands projects, another $86 billion will be spent up to 2012.

So far, only 2% of Alberta’s oilsands have been produced.

Table HOB-5 shows the deposits by formation:



Area and Formation

OBIP
(106m3)

Area
(106ha)

Average
Pay, m
Bitumen


Wt
Sw
Ø
%
%
%







Athabasca






Ø Grand Rapids
8678
689
7
6.3
56
30
Ø Mineable Wabaskaw– McMurray
17998
286
30
9.7
69
30
Ø In-Situ
119234
4329
19
7.9
62
28
Ø Nisku
10330
499
8
5.7
63
21
Ø Grosmont
50500
4167
10
4.7
68
16







Subtotal
206740












Cold Lake






Ø Grand Rapids
17304
1709
5.8
9.5
61
31
Ø Clearwater
11051
589
15
8.9
64
30
Ø Wabaskaw– McMurray
3592
658
5.8
6.3
54
26







Subtotal
31947












Peace River






Ø Bluesky– Gething
9926
1254
8.7
6.4
60
23
Ø Belloy
282
26
8
7.8
64
27
Ø Debolt
7800
328
22.5
5.3
65
19
Ø Shunda
2510
143
14
5.3
52
23







Subtotal
20518












Total
259205






Table HOB-5: In-Place Bitumen by Area/Formation

The cutoffs within the carbonate deposits are a minimum bitumen saturation of 30% and minimum porosity of 5%.

It is interesting to note that Saudi Arabia’s remaining oil reserves are about 42 x 109 m3, while Alberta’s remaining bitumen reserves are about 28 x 109 m3.

It is estimated that there will be about 350,000 m3/d of bitumen produced in 2011, with 65% coming from surface mining and the remainder from in-situ projects.








Current/Proposed Alberta Mining Projects


Existing and proposed Alberta bitumen mining projects are:

· Suncor’s Steepbank expansion plans for Millennium and Voyageur Phases I and II (includes upgrader)

· Syncrude’s expansion at Mildred Lake and Aurora

· Albian Sands Muskeg River project for production startup 2003 (150,000 b/d) and expansion in 2008. The upgrader will be located next to the Shell Scotford refinery in Edmonton

· Canadian Natural Resources Limited (CNRL) Horizon project in Wood Buffalo in northeastern Alberta with startup in 2007

· TrueNorth Energy Fort Hill Oil Sands Project with two phases beginning in 2005 and 2009

· Husky Energy’s Caribou, Kearl Lake (mining and SAGD 100,000 b/d), and Tucker

Currently, about 65% of the bitumen production is from Syncrude, the remainder from Suncor. Production from mined bitumen in 2001 is about 68,000 m3/d which consists of an upgraded product.


Current/Proposed Alberta/Saskatchewan In-situ Projects

In 2001, about 50,000 m3/d bitumen was produced from in-situ projects. Most of the production is not upgraded. The major in-situ projects are:

· Suncor’s Firebag (SAGD and Vapex) with startup in 2005 and 140,000 b/d by 2010

· Imperial Oil Cold Lake Expansion (phases 14, 15 and 16 by 2008), including Mahihkan North and Nabiye using CSS

· Encana’s Foster Creek (100,000 b/d by 2007) and Christina Lake (70,000 b/d) using SAGD, SAGP and Vapex

· PetroCanada’s Mackay River (2002, 30,000 b/d) and Meadow Creek (2006) using SAGD

· JACOS Hangingstone project using SAGD (35,000 b/d by 2007)

· OPTI/Nexen Long Lake Project using SAGD and building upgrader

· Shell’s Peace River using CSS and steam flooding and soak radial

· Conoco-Phillips Surmont project using SAGD (cost $1 billion)

· CNRL’s Primrose and Wolf Lake CSS project; Cold Lake, Beartop, Charlotte, Kirby, Pelican expansion, Burnt Lake

· Devon Canada Corporation’s Jackfish SAGD project and Dover Vapex ($30 million, two well pair, startup 2003)

· Deer Creek Energy Lease 24 (Joslyn Creek), SAGD

· CNRL Cold Lake / Provost / Lindbergh in 2003

Arecord $107 billion worth of major projects are now underway in Alberta, the province’s Economic Development ministry is reporting, and nearly two-thirds of that—or a staggering $69 billion—is focused on oilsands development, mostly in the Fort McMurray area. The Wood Buffalo/Cold Lake area, the inventory shows, is now supporting $64 billion worth of major projects either underway or scheduled to begin within two years. Existing operators are responsible for a major slice of the project pie. Suncor Energy has got about $11.45 billion committed to various Steepbank, Voyageur and Firebag projects, while Syncrude Canada is responsible for $12 billion worth of work, mostly
associated with upgrader expansions and Aurora mine development. Imperial Oil, already a significant oilsands player by virtue of its participation in the Syncrude consortium, has a few projects on the list, including its proposed $5 billion
Kearl Lake mining project, for which regulatory applications are expected this year, and the $650 million Nabiye project, comprising phases 14 through 16 of its ever-expanding Cold Lake heavy oil development. Canadian Natural Resources Ltd.—still an oilsands neophyte—is set to raise its profile dramatically in the next few years, as it spends nearly $11 billion to develop its Horizon mine and upgrader and its Primrose in-situ resources. And Shell Canada and its Albian Sands partners will be kept busy developing plans for a billiondollar expansion of the existing Muskeg
River mine and the $2 billion Jackpine phase one project. OPTI Canada and Nexen Inc. are on the list with their planned $3.5 billion Long Lake SAGD project, as are UTS Energy and new partner Petro-Canada, with their $2 billion
Fort Hills project, destined to become, in 2009, Canada’s fifth oilsands mine, assuming the first phase of Canadian
Natural’s Horizon mine goes into production in 2008. The other major projects related to the oilsands are located near Edmonton, and include BA Energy’s planned $1 billion bitumen upgrader in Strathcona County; ExxonMobil’s proposed $1.4 billion upgrader at a location still to be determined; North West Upgrading’s proposed $1.3 billion bitumen upgrader in Sturgeon County and Petro-Canada’s $1.2 billion Strathcona refinery conversion project.




· Black Rock at Cold Lake, Orion and Hilda Lake (SAGD, 30,000 b/d)

· Murphy Oil Canada Ltd at Lindbergh (SAGD)

· Nexen’s Plover Lake (SAGD and Vapex)

· Conoco-Phillips at Kerrobert (SAGD)

· EnCana at Senlac (SAGD)












Map showing Lloydminster Heavy Oil Pools



Alberta Heavy Oil and Bitumen Marketing

A large portion of Alberta’s bitumen production is upgraded to a synthetic crude oil (SCO). This has low sulphur and heavy metals content and produces very little heavy fuel oil (there is currently no market for heavy fuel oil in Alberta). SCO also contains high levels of aromatics as well. SCO has a similar density and viscosity to West Texas intermediate crude.

There are two basic technologies used to produce SCO:

i) delayed coking (taking out carbon)
ii) hydrocracking (adding hydrogen)

Suncor’s current yield factor is 0.81 using delayed coking, while Syncrude’s is 0.85 using hydrocracking. The Albian group expects a yield factor of 0.90 using hydrocracking.

Non-upgraded bitumen refers to bitumen which has been diluted with condensate such as pentanes plus or naphtha in order to move the bitumen in pipelines. It is usually recycled when sent to Alberta refineries or sent straight through to out-of province refineries.

In 2001, the five Alberta refineries used a total of 27,300 m3/d SCO and 2500 m3/d of non-upgraded bitumen. (The total capacity is 68,000 m3/d). There are an additional four refineries in Western Canada. The total refining capacity in Western Canada is 92,100 m3/d. In Eastern Canada, only the four Sarnia area refineries are able to handle Alberta SCO. The largest export market for Alberta SCO and non-upgraded bitumen is the US Midwest (PADD II) (PADD: Petroleum Administration for Defence District) with a refining capacity of 575,000 m3/d and the US Rocky Mountain Region (PADD IV) with a refining capacity of 85,800 m3/d.


Heavy Oil in Saskatchewan

Heavy oil is located in the southwestern part of the province, particularly in the Lloydminster area. Saskatchewan, after Alberta, is the second largest oil producer in Canada, producing about 20% of Canada’s production. Eighty percent of the land is held by the Crown, the remainder is freehold. Over 60% of the produced oil is sold in the US; being transported by the Enbridge pipeline.

To encourage heavy oil development, the province has a Saskatchewan Petroleum Research Incentive to cover 30% of the eligible costs of research and development of new technologies. In addition, incremental production from enhanced oil recovery (EOR), excluding waterfloods, has a 2.5% royalty rate (tax rate of 0%) on gross revenue prior to project payout; with a maximum royalty of 27.5% (tax rate of 20.5%) of operating revenues after project payout. Royalties are handled by the Saskatchewan Industry and Resources Department.

The major producing formations in the Lloydminster area are the Sparky, Waseca, Colony, Lloydminster, Rex, General Petroleum (GP), McLaren, Cummings, and Dina. Most of the heavy oil wells are completed in the Sparky and Waseca Sands.

Heavy oil is refined in Regina at the Consumer’s Co-Operative Refineries Ltd, which operates an 8000 m3/d (50,000 b/d to be expanded to 80,000 b/d) refinery. In Moose Jaw, the Moose Jaw Asphalt Inc operates a 500 m3/d asphalt plant.

There are two upgraders in Saskatchewan. The first, built in Lloydminster in 1992, is operated by Husky Energy, and upgrades oil from mainly Cold Lake and the Lloydminster area. Current processing is about 11,000 m3/d, including 1000 m3/d of tops from Husky Energy’s asphalt plant. Expansion plans (to 23,800 m3/d) are dependent on the heavy oil price. The second upgrader is called the Newgrade Upgrader, a joint venture between the government of Saskatchewan and the Consumers Coop. It processes about 8740 m3/d.











Oil sands drive Canada's oil production growth (Oil and Gas Journal Review June 7, 2004)


Forecasts show that bitumen production from Canada's oil sands may exceed 1.8 million b/d by 2010 up from an average 920,000 million b/d in 2003. This additional production will come from both surface-mined bitumen and bitumen recovered with such thermal processes as cyclic steam stimulation and steam-assisted gravity drainage (SAGD).
Other technologies under test, such as a solvent-aided process (SAP) and vapor extraction (VAPEX), may further help increase the recovery from this immense resource base that the Alberta Energy and Utilities Board (EUB) estimates has 1.6 trillion bbl of bitumen in place.1


At yearend 2002, EUB estimated Western Canada's remaining established bitumen reserves at 174.4 billion bbl, of which 11.6 billion bbl were in areas under active development (Table 1). Because of the ongoing expansion in the active area, EUB's scheduled mid-2004 reserves update may alter significantly the reserves in the active areas.


Athabasca (near Fort McMurray), Cold Lake (near Lloydminster), and Peace River are the three main areas of Western Canada that contain bitumen resources (Fig. 1). Oil sand deposits are commonly found near surface and are a mixture of sand saturated with water and an almost solid hydrocarbon called bitumen.
To develop these resources requires companies to create a manufacturing process that integrates production, upgrading, transportation, and marketing. Typically the projects are developed in stages to maintain a long production plateau of 20-30 years, instead of the short production peak rates of conventional oil production projects.
In its March 2004 oil sands update, Alberta Economic Development (AED), an Alberta government ministry, listed more than 40 major oil sands projects either under way or planned.2 These include both new projects and planned expansion of existing projects.
Reserves estimates

EUB based its reserves estimate on drilled holes and well logs. For Cretaceous sand bitumen, it used a minimum saturation cutoff of 3% by mass of bitumen and a minimum 1.5-m saturated zone thickness for in situ and primary areas, and 6% by mass and a minimum 3-m saturated zone thickness for surface-mineable areas.
For bitumen in carbonate deposits, EUB used a minimum bitumen saturation of 30% of pore volume and a minimum 5% porosity cutoff.
Within these cutoffs for nonactive areas, EUB selected a recovery factor of 20% for thermal developments and 5% for primary development, factors which are lower than in active projects to account for uncertainty in the recovery processes and for areas with poorer-quality resources.
For the active projects in Peace River and Athabasca, EUB used recovery factors of 40 and 50%, respectively.
EUB identified potential mining areas using economic strip ratio criteria, a minimum saturation cutoff of 7% by mass of bitumen, and a minimum 3-m saturated zone thickness cutoff to obtain an initial volume in-place of 59.1 billion bbl. After applying reduction factors for inaccessible areas, isolated ore bodies, and extraction losses, it estimated an initial mineable bitumen resource of 35.2 billion bbl of which about 25% were under active development.
The mineable bitumen is all in the Wabiskaw-McMurray sands of the Athabasca area and lies at a depth shallower than 250 ft.


EUB estimates that at yearend 2002, remaining established in situ reserves were 141.9 billion bbl of which 3.3 billion bbl were in active development areas (Table 2).
Mines

The current technique for oil sands mining is first to remove the overburden and then to mine the mixture of bitumen, water, and sand from just below the surface using shovels and trucks. This material is mixed with warm water in an extraction plant to separate the crude from the sand.
From there, the extracted crude enters an upgrader for processing into a synthetic crude (SCO) that refineries use as a feedstock. SCO has a density and viscosity similar to conventional light-medium crude oil.
EUB forecasts that SCO production will increase to 1.48 million b/d in 2012 from the 0.44 million b/d in 2002.
Upgraders chemically add hydrogen to bitumen, subtract carbon from it, or both.
The process also removes most sulfur either in elemental form or as a constituent of oil sands coke.
Most companies stockpile oil sands coke, with some burned to generate electricity.
Companies either stockpile elemental sulfur or ship it to facilities that convert it to sulfuric acid, used mainly in the manufacturing of fertilizers.
AED indicated that production from the three active bitumen-mining operations was about 560,000 b/d in 2003.
Suncor Energy Inc., from its mining project, averaged 217,000 b/d in 2003 up from about 206,000 b/d in 2002. The company expects to produce 225,000-230,000 b/d in 2004. The production from this mine started in 1964, and cumulative production in 2004 reached 1 billion bbl.
EUB estimates that the overall liquid yield factor for the current Suncor delayed coking operation is about 0.81.
Suncor currently has finished 45% of the construction of the Millennium vacuum unit, which it says is on schedule and on budget. With completion of the Voyageur project it expects production, including that from its in situ Firebag project, to reach 330,000 b/d in late 2007.
Syncrude Canada Ltd. production averaged about 212,000 b/d in 2003, down from about 230,000 b/d in 2002 as a result of an unscheduled coker turnaround and extended maintenance.
Production in December 2003 was 264,000 b/d.
AED says Syncrude has completed Train 2 at the Aurora Mine and more than 35% of the first Upgrader Expansion 1 (UE1) at Mildred Lake. Both projects are part of Stage 3 of the Syncrude 21 expansion program, which may increase the company's oil sands production by 100,000 b/d.
The completion date for Stage 3 of the Syncrude 21 expansion is now mid-2006 and estimated costs for Stage 3 have increased to $7.8 billion (Can.) from $5.7 billion previously.
Syncrude plans to complete Stage 4, which includes Aurora Train 3, and further upgrader expansion in 2009.
EUB estimates that the current yield for Syncrude fluid coking/hydrocracking upgrader is 0.85.
In the newest producing mining project, Albian Sands Energy Inc.'s Muskeg River mine, about 75 km north of Fort McMurray, averaged 130,000 b/d in the last quarter of 2003, up from 115,000 in the previous quarter.
Production operations began Dec. 29, 2002, from the 155,000 b/d design capacity project.
The Muskeg mine is part of the integrated Athabasca Oil Sands Project (AOSP) that also includes the Scotford Upgrader, near Edmonton, and the Corridor pipeline.
AOSP is a joint venture between Shell Canada Ltd., 60%, Chevron Canada, 20%, and Western Oil Sands LP, 20%.
EUB expects the overall liquid yield factor for the Shell upgrader using a hydrocracking process to be at or more than 0.90.

Shell Canada indicates that the unit costs in 2004 will average more than $22/bbl (Can.), although its target is a $12-14/bbl unit costs at recent natural gas prices (Fig. 2).
Shell says the project contains 1.6 billion bbl of bitumen resources, but that all its leases in the area contain about 9 billion bbl and will support additional projects.
Its plans include an expansion of the existing mine that will increase production by about 70,000 b/d and a second mine called Jackpine that will provide an additional 300,000 b/d in two phases, to be completed in 2010-15.
The Jackpot mine Phase 1 recently received regulatory approval.
Canadian Natural Resources Ltd.'s (CNRL) received regulatory approval for the Horizon project, an $8 billion (Can.) mine and upgrader development with a 270,000 b/d design capacity. CNRL expects construction to commence in 2005 with initial production in 2008 and full production in 2011.
EUB expects the CNRL upgrader with delayed coking will have about a 0.86 liquid yield factor.
Imperial Oil Ltd. announced plans for the Kearl oil sands project, a mine and upgrader project with a 100,000 b/d initial and 200,000 b/d final design capacity.
AED expects Imperial to receive regulatory approval in 2005 with first production starting in 2010.
TrueNorth LP continues to defer construction of the regulatory approved Fort Hills oil sands mine and extraction plant project, 90 km north of Fort McMurray. AED indicates that TrueNorth is investigating options to reduce the initial phase of the project to support a production of 50,000 b/d with an on site upgrader. The original application called for $3.5 billion (Can.) that would support a minimum 190,000 b/d and recover 2.8 billion bbl during a 40-year life.
AED says Synenco Energy Ltd.'s formal disclosure document for its Northern Lights project remains on file.
The project includes an integrated mine, extraction plant, and upgrading facility with a design capacity of 100,000 b/d and an estimated construction cost of $4-5 billion (Can.).
It says that if Synenco receives regulatory approval, the project may start in 2007 with peak production in 2010.
Another project AED noted involves the Fort McKay First Nation that has discussed plans for a 35,000 b/d oil sands mining project near Fort McKay that does not include an upgrader. Two stand-alone upgraders in the oil sands region are the Husky Energy Ltd. Lloydminster and New Grade Energy Ltd. Regina upgraders.
AED says Husky Energy is proceeding with engineering for debottlenecking and increasing on-stream reliability to increase the Lloydminster capacity to handle 82,000 b/d by yearend 2004 from the current 77,000 b/d.
BA Energy Ltd. also plans to construct a standalone upgrader with a bitumen-processing capacity of 50,000 b/d and design capacity of 150,000 b/d in Strathcona County, Alta.
AED expects BA Energy, subject to regulatory approval, to begin operations in the last half of 2006.
SAGD producing projects

After many years of pilot testing, companies have concluded that steam-assisted gravity (SAGD) is commercial. SAGD requires a pair of horizontal wells, one above the other with the laterals spaced about 15 ft apart (Fig. 3).

The process continuously injects steam into the top lateral, forming a steam chamber that grows and heats the surrounding bitumen to allow it to drain by gravity into the lower horizontal lateral.
Steam quality, oil-in-water emulsions, limits on steam-oil-ratio, and effect of the high temperature on artificial lift and tubulars are some of the technological challenges that concern operators in SAGD operations.
Most projects add a diluent such as propane plus (natural gas condensate) to the produced bitumen before transporting it in a pipeline. Other diluent options include naptha, light crude oil, and synthetic oil.
EnCana Corp. says its Foster Creek project was Canada's first large-scale commercial SAGD project, starting up in 1997.
After adding six new well pairs, production from the project has increased to 28,000 b/d.
As in many SAGD projects, cogeneration is an integral part of the project that adds steam-generation capacity and provides electricity sales to the Alberta power grid.
The company has applied for regulatory approval for Phase 2 of the project, which would increase bitumen production by 50,000 b/d. AED expects construction to start in 2004 with bitumen production starting in 2006.
EnCana's other SAGD project is at Christina Lake in northeast Alberta, which produces about 5,300 b/d from four well pairs and has a 10,000 b/d design capacity. At Christina Lake, EnCana also has a solvent-aided process (SAP) under test.
The process adds small amounts of solvent to the injected steam to decrease bitumen viscosity.
EnCana says its SAGD projects have the lowest steam-oil ratio in the industry of 2.5 bbl of water/1 bbl of oil produced and its long-term objective is to reduce this ratio further.
In 2004, it expects a 38,000 b/d production from its SAGD projects, compared to the 27,000 b/d average in 2003.
In September 2002, Petro-Canada started injecting steam in its 100% working interest MacKay River steam-assisted gravity drainage (SAGD) project. The company expects the $290-million (Can.) project to recover bitumen from oil sands lying at about a 300-ft depth (OGJ, Nov. 11, 2002, p. 55).
It estimates that the 11.5 sections in the current development contain 230-300 million bbl of recoverable bitumen reserves, providing enough resources to produce for at least 25 years.
The project consists of well pads and facilities, a central processing plant, and a short lateral pipeline connecting to export facilities.
MacKay River began producing in the fall of 2002 and produced an average 16,000 b/d in 2003. For 2004, Petro-Canada expects to produce an average 25,000 b/d in the facility designed for handling 30,000 b/d.

Steaming in Suncor's Firebag SAGD project (Fig. 4) commence on Sept. 14, 2003, with first oil delivered to the oil sands upgrader on Jan 12, 2004. Firebag is adjacent to Suncor's bitumen mining operation. Suncor says Stage 1 of the project consist of two wells with 10 well pairs on each pad that drain 781 acres.
The company currently is developing Stage 2 of the project that will include an additional two well pads with 10 wells on each, draining 831 acres.
Suncor plans to complete enough wells to maintain a bitumen fill rate to its plant with a design capacity of 35,000 b/d.
It expects the wells to produce for about 10 years, and its plans call for drilling another 40 well pairs during the 30-year life of the plant.
Firebag wells are completed at a depth of about 1,050 ft. The Stage 1 wells have horizontal laterals of about 3,300 ft that run in a north-south orientation, while the horizontal laterals in Stage 2 wells will have lengths of 3,300-3,950 ft. Suncor also has oriented Stage 2 wells in a north-south direction except for 1 pair that has an east-west orientation.
Japan Canada Oil Sands (JACOS) operates a SAGD pilot on the Hangingstone lease and has plans for a commercial SAGD project with a design capacity of 30,000 b/d.
In April 2004, Deer Creek Energy began steam injection in Phase 1 of its SAGD Joslyn oil sands project, designed to produce about 600 b/d. The company expects construction of the $270 million Phase 2 of the project to begin later in 2004. This phase would increase production to 10,000 b/d by 2007.
Deer Creek also is evaluating a third phase that would increase production to 30,000 b/d.
SAGD planned projects

The OPTI Canada Inc. and Nexen Inc. Long Lake project, about 40 km southeast of Fort McMurray, will be the first project to combine SAGD with a field upgrading facility.
The companies plan to commence Phase 1 in 2006 with an upgrader designed to produce 60,000 b/d of 39° gravity synthetic crude from a 72,000 b/d of bitumen inlet stream.
The plans for the project include a second phase that will double production by 2010.
The companies expect to commence SAGD production in 2006 with the upgrader starting in 2007.
OPTI/Nexen says Long Lake Lease 27 covers 20,000 hectares and contains more than 4 billion bbl of bitumen in place.
Phase 1, which covers 6,700 hectares, has more than 1 billion bbl of recoverable bitumen that can sustain a 60,000 b/d production of synthetic crude for more than 40 years, according to the companies.

The project includes the use of partially upgraded bitumen with OPTI's proprietary OrCrude process, followed by conventional hydrocracking and gasification (Fig. 5).
Phase 1 plans include completing 60-70 horizontal well pairs, each 1,000 m long with expected production of 1,000-1,500 b/d of bitumen from each pair. The company plans to drill the wells from centralized well pads with slant rigs and expects to need about 350 additional well pairs during the life of the project to sustain production rates.
OPTI/Nexen notes that a main advantage of the upgrading technology is that the process eliminates the need from purchasing natural gas, a volatile cost component of SAGD operations.
The companies estimate that this gives the project a $5-10/bbl (Can.) cost advantage over other SAGD operations.
Instead of gas, the process uses asphaltene residue to produce most of the fuel gas and hydrogen required for the operation, cogeneration facility, and upgrading components.
The companies explain that the OrCrude process forms a continuous loop that completely processes the bitumen, leaving only source synthetic crude oil and liquid asphaltenes, and does not generate solid coke by-products that require disposal
Another project, ConocoPhillips' Surmont Project, a $1 billion (Can.) SAGD in situ facility with a design production capacity of 100,000 b/d, received regulatory approval in May 2003.
AED expects construction of the first phase to commence in 2004 with initial production in 2006.
Devon Energy Corp. $400 million (Can.) Jackfish SAGD project, near Conklin, Alta., is awaiting regulatory approval and has a design capacity of 35,000 b/d. AED expects production to start in 2007.
Husky Energy Ltd. is also awaiting regulatory approval on its Tucker 30,000 b/d SAGD Tucker thermal project application. The company expects production to start in 2006.
Husky also has a second planed SAGD project, the Sunrise Thermal project.
Phase 1 is designed to produce 50,000 b/d, and the company says expansions will increase production to more than 200,000 b/d during the 40-year life of the project.
It plans for production to commence in 2008.
BlackRock Ventures Ltd. is advancing its application to develop the in situ Orion EOR Project at Hilda Lake. The company expects regulatory approval in 2004 or 2005.
The project may support a production of 20,000 b/d.
BlackRock produces about 8,000 b/d of bitumen from its Seal project that is a cold production facility.
The company expects to increase production to 16,000 b/d by yearend 2004.
Other processes

Shell Canada's Peace River leases currently produce about 9,000 b/d through cyclic thermal in situ recovery processes from wells, some of which have multilateral completions.
The company estimates that its Peace River lease contains about 7 billion bbl of bitumen in place.
By far the largest cyclic steam project is Imperial Oil Ltd.'s Cold Lake project that in 2003 produced an average 129,000 b/d up from 112,000 b/d in 2002.

Production from the pilot projects in the field started in 1964. Imperial notes that production from the area can result in large variations (Fig. 6).
Fig. 7 shows the recent statistics on the operation.

The company has filed an application to construct and operate two additional phases to the Cold Lake Project, the Nabiye and Mahihkan North projects (Phases 14-16), which it expects will add 30,000 b/d by 2007.
Another project in the Cold Lake area, is CNRL's Primrose-Wolf Lake-Burnt Lake oil sands project that includes both cyclic steam injection and SAGD.
Currently the project produces 35,000 b/d, but CNRL has regulatory approval to increase the output to more than 120,000 b/d.
Besides thermal projects, Devon Canada operates the Dover VAPEX pilot project.
The process has a pair of horizontal lateral similar to SAGD but uses solvents instead of steam.
Projections

Onno DeVries, general manager, oil sands and oil markets, Canadian Association of Petroleum Producers, Calgary, presented CAAP's estimates for the growth in Canada's crude oil production and supply at a recent NPRA meeting.3
CAAP says that by 2010 oil sands production will exceed 1.8 million b/d while operating costs will remain in the $8-12 (Can.)/bbl range (Fig. 7).
CAAP estimates the 1996-2002 period saw a $24 billion (Can.) investment in oil sands, with a further $7 billion currently under construction for 2002-2006, and an additional $25 billion in announced project at various stages.

CAAP also believes the bitumen blend sold into the North American market will change as availability of gas condensate for use as a diluent (Dilbit blend) becomes more scarce. It expects synthetic oil (Synbit blend) to replace condensate. From a refining perspective it says the Dilbit blends are predominantly heavy, whereas the Synbit blends result in similar products to medium type, sour crude.





























Hebron Ben Nevis

The Hebron asset is comprised of Hebron, West Ben Nevis, and the Ben Nevis fields. This prospect is located in the southern portion of the Jeanne d’Arc Basin, approximately 350 kilometers from St. John’s, Newfoundland. Significant discovery licenses covering this asset were awarded in the mid 1980’s based on four exploratory wells over an area of approximately 36 square kilometers.

Oil in place potential for the asset including un-drilled fault blocks is estimated to exceed 2 billion barrels. The CNOPB1 states that there are about 400 million barrels of recoverable oil, based on what has been already drilled, making Hebron the second largest field in the Jeanne d’Arc Basin after Hibernia. The upper Ben Nevis horizon encountered significant volumes of crude with gravities in the range of 19 to 21 degree API.








GRAVITY BASE STRUCTURE

Chevron is examining whether to develop the Ben Nevis heavy oil field using a gravity base structure, such as is currently used at the Hibernia field.
In September 1990, HMDC awarded the gravity base structure (GBS) contract design to Newfoundland Offshore Development Constructors (NODECO). The detailed design was subcontracted to Doris Development Canada (DDC).
The Hibernia's novel 450,000 t gravity base structure design consists of a 105.5 m concrete caisson, constructed using high-strength concrete reinforced with steel rods and pre-stressed tendons. The caisson is surrounded by an icewall, which consists of 16 concrete teeth. Structurally, the 1.4 m-thick icewall is supported by a system of X and V walls, which transmit the loads to the interior tiewall. The X and V walls have a thickness varying from 0.7 m to 0.9 m and the tiewall has a thickness of 0.9 m. Put together, these walls form the icebelt. The caisson is closed at the bottom and top by horizontal slabs and the base slab has a diameter of 108 m. The upper top-surface slab is about 5m above sea level.
Inside the gravity structure are storage tanks for 1.3 million bbl of crude oil.
Four shafts run through the GBS from the base slab to support the topsides facilities: namely the utility shaft, the riser shaft and two drill shafts. Each of the shafts are 17 m in diameter and extend to a total height of 111 m.
The utility shaft houses the mechanical outfitting required to operate the GBS system. It includes pipework, heating and air-conditioning, and electrical controls. The two drill shafts each house 32 drill slots to accommodate the wells, which will reach depths of more than 3700m below sea level, down into the oil reservoirs.
ChevronTexaco has been pursuing GBS studies since it commissioned ABB Offshore Systems in Houston to perform a pre-front-end engineering and design study more than two years ago.
According to the study, the manned drilling and production deck alone would weigh nearly 26,000 short tons, with an operating weight of 40,000 short tons.
It also came with a price tag of $743 million to build. The concrete sub-structure would likely cost another $300 million.
The photo on the next page shows the Hibernia GBS.















Venezuelan Deposits

Venezuelan heavy oil, extra heavy and bitumen deposits are found in two areas:

1) north of the Orinoco River (Faja del Orinoco) in eastern Venezuela
2) Lake Maracaibo in western Venezuela

.


The Venezuela heavy oil deposits are the world’s largest, along with Kuwait and Canada. Currently, Venezuela’s production consists of 80% heavy extra heavy oil; the remainder is conventional oil. Exploration and operating costs are very low, ranging from $1.00-$2.00 U.S. per barrel. The national oil company, Petroleos de Venezuela S.A. (PdVsa) has announced joint ventures with multinationals to develop these plays.

The very first heavy oil well (17.8° API) was drilled in 1914 in the Mene Grande field (Lake Maracaibo) which had 707 million barrels recoverable reserves. This discovery led to the development of the eastern coast or Bolivar coast of Maracaibo and a OOIP of over 35 billion barrels of heavy oil (10-13° API).

In the 1930-1940’s, exploration centred in eastern Venezuela’s Orinoco basin. The original discovery here in 1935 was La Canoa I which produced 40 b/d of 7° API oil. This area, however lay dormant until 1978 when the operating affiliates of PdVSa, Maraven, Lagoven and Corpoven developed these fields.





Photo: Lake Maracaibo


There is heavy oil development in the offshore plays of Lake Maracaibo using horizontal wells in this mature basin. Two major pools are the Boscan and Lagunillas plays. These are 10-15° API oils which have now been developed by more exotic EOR techniques such as microbial enhanced recovery. These oils are marketed without upgrading.

Orinoco Reserves

Pdvsa has identified 1.8 trillion barrels (286 x 109 m3) of heavy oil and extra heavy oil that will require $12-13 billion U.S. to develop the 65,000 square kilometres. The Orinoco area is about 700 km long and 45-90 km wide, lying in the states of Monagas, Anzoategui and Guarico. The four big fields here are:

a) Machete
b) Zuata
c) Hamaca
d) Cerro Negro
(now called Carabobo (formerly Cerro Negro), Ayacucho (formerly Hamaca), Junin (formerly Zuata), and Boyacá (formerly Machete)).

North of these Orinoco basins are the pools of

e) El Tigre
f) Morichal
g) Maturin
h) Barcelona
i) Cumana
j) Guiria

while south are

k) Cuidad Bolivar
l) Puerto Ordoz

These areas were discovered in the late 1930’s and have been developed using primary production and thermal methods. The produced oil is shipped north to Jose on the Caribbean Coast for upgrading and tanker shipment. A new method, called Aquaconversion™, allows for wellhead upgrading from 8-10° API oil to an oil of 18°API.
The Zuata region has 2 major projects: Petrozuata and Sincor. Petrozuata will be developed by Conoco and Pdvsa using horizontal wells (the longest horizontal well drilled in Venezuela at 2200 m measured depth) in the fluvial Oficina formation. The 9-10° API is produced on cold production and mixed with Mesa crude and naphtha as diluent to be pipelined to Jose. A total of 530 horizontal wells will be drilled in the 35 year project life to achieve a plateau production of 120,000 b/d.

The Sincor project in Zuata region will consist of Oficina horizontal pad drilling (900 wells) to reach a peak of 204,000 b/d. Investments will amount to $4.3 billion U.S., the consortium consisting of Total, Pdvsa and Statoil. The 8 1/2” horizontals will be equipped with 7 “ slotted liners ESP’s and PCP’s will be set deep in the wellbore (at about 70°). The crude will be diluted with Mesa crude and naphtha and will be shipped to the coast and marketed until the upgrader is built.



Photo: Upgrader at Jose

In Hamaca, the 657 square kilometre area contains over 30 billion barrels of oil, over the 35 year life, about 7% can be produced. Peak production of the 8.5° API oil will be 190,000 b/d. The upgrader at Jose will produce a 26° API oil. The partners are Chevron – Texas Corp, Pdvsa and Philips Petroleum.

The Cerro Negro project will target the 8.5° API oil in the Morichal formation, which is at a depth of 1100 m. The reservoir pressure is at 6900 kPa and the reservoir temperature is at 54°C. About 35 billion barrels are in place over this 34,000 hectare area. At reservoir conditions, the oil has a viscosity of about 2,000-5,000 cp. The area, developed by Pdvsa, Exxon-Mobil and Veba Oil, will consist of pad drilled horizontal wells which are spaced 600 m apart. The wells will have a 13 3/8” surface casing, 9 5/8” production casing with 7” slotted liner in a 8 1/2” horizontal well. Production is through 5” tubing. Peak production from the 350 wells will be 120,000 b/d, costing about $2.5 billion U.S. A subsidiary of Pdvsa, called Bitor (Bitumens Orinoco S.A.) has been operating in the Cerro Negro area by adding 30% water and about 3,000 ppm surfactant to stabilize the produced emulsion (called Orimulsion), which is pipelined to the coast and sold as boiler fuel.



The Lake Maracaibo reservoirs of Bachaquero, Lagunillas, Tia Juana, and Boscan are produced with cyclic steam injection and horizontal wells. The Boscan pool has about 30 billion barrels of 10° API oil.








Heavy Oil in the United Kingdom Continental Shelf (UKCS) &Norway

It is estimated that there is over 10 billion barrels of heavy oil off the coast of the United Kingdom* in the North Sea in the eastern margins of the East Shetland Platform, the Halibut Horst, west Central Graben and in the Fladen Ground Spur. The following Table shows the heavy oil accumulations:

As can be seen, the majority of heavy oil accumulations is in the Lower Tertiary Age consisting of mainly Upper Palaeocene and Eocene formations. The source rock is conjectured to be the Jurassic Kimmeridge clays. Some of these heavy oils have gas caps. These formations have good vertical to horizontal permeabilities (>0.1) so horizontal and multilateral well development is in order. Horizontal wells of 1000 to 6000 feet have been drilled. Wells are completed with large stand off from the oil-water contact. The formation is unconsolidated: pre-packed screens and gravel packing have been used for sand exclusion.


*A. Jayasekera and S. Goodyear “The Development of Heavy Oil Fields in the United Kingdom Continental Shelf: Past, Present and Future”, SPE 54087, 1999.


Field
OOIP
MM bbl
Discovery Date
API
Age
Depth
m
Permeability (Darcy)
Reservoir
Temp ºC
Viscosity
cp









Alba
> 500
1984
20
Mid Eocene
1980
3
74
7
Captain
1000
1977
19
Lower Cretaceous
880
7
31
88
Gryphon
207
1987
21
Eocene
1730
10
60
6
Harding
> 322
1988
19-21
Eocene
1730
10
60
5-10
Gannet E
132
1982
20
Palaeocene
1730
0.9
79
20
Mariner (M)

1981
14
Palaeocene
1460
5
47
65
Mariner (H)

1981
12
Upper Palaeocene
1280
3
38
540
Bressay

1976
11-12
Upper Palaeocene
1060
10
34
1000
Clair

1977
25
Carbonifer-ous
Devonian
1860
0.02-0.05
68
3-8
Table HOB-6: UKCS Heavy Oil Deposits




Photo: Grane Coalescer

At the Grane field the oil/water separation method is very difficult. As a result, the last of the three separation stages must be replaced with an advanced type of separator called an Electrostatic Coalescer. The separation train containing first and second stage separators together with the coalescers, will be the most advanced in the North Sea. The coalescers are internally equipped with a high voltage grid system. The electrified grid makes vibrations in the oil/water mixture, accelerating and improving the separation process. Due to the large volumes being processed and special process conditions, the separators and coalescer are big - 26 metres long and 4.5 metres in diameter – and are made of high alloy stainless steel. The first stage separator is a high-pressure design with thick vessel walls and weighing about 60 tons.


Photo: Norsk Hydro Grane


The main recovery method is waterflooding using seawater. By injecting water into the aquifer at onset of production, full voidage replacement is maintained. The majority of artificial lift is electric submersible pumps, gas lift and hydraulic pumps.

The Harding field has been developed with horizontal wells, completed about 23 m below the gas – oil contact to delay gas coning. Excess gas produced is re-injected to the Harding Central gas cap for future use. Produced water and water from a shallower aquifer are injected to maintain reservoir drive.


The Gryphon field has been developed along the lines of Harding, except there is no gas injection.

The Grane heavy oil field is found offshore Norway in the North Sea Block 25/11, 185 km west of Stavanger. According to Norsk Hydro ASA, this is the largest undeveloped offshore field off the coast of Norway. The partners are Norsk Hydro (at 38%, the operator), Petoro AS (30%), Esso Exploration and production Norway AS (25.6%) and Norske Conoco AS (6.4%).

The 19ºAPI viscous oil is found in a low pressure Tertiary sandstone at a depth of 1700 m. The oil column is 80 m thick and found in a highly permeable (1-12 darcies), poorly consolidated turbidite sandstone with an areal extent of 6,700 acres. The reservoir porosity is 33%. The reservoir pressure and temperature is 2,550 psi and 170 deg F respectively. The estimated reserves are 704 million barrels oil (recovery factor of 55% OOIP).

The offshore platform is shown in the previous page. This platform will sit in 128 m of water. The platform dimensions are 99.5 m total length, 27.5 m maximum width, 45 m topsides height and 150 m jacket height.


Its 10,700 tonne module can handle 214,000 b/d, 19,000 m3/d injected water and 10,000 million m3/d gas injection. The development includes drilling 35 wells of which 27 are oil producers and 2 gas injectors. The wells will be drilled 9 m above the oil-water contact using an ultradeep resistivity tool to measure the distance to this contact while drilling. It also conducts seismic surveys while drilling that allow it to look 300-400 m ahead of the drill bit.

There will be 3 water injectors for reservoir pressure maintenance. The produced water will be reinjected into the oil reservoir and as well into the Utsira formation about 1,000 m below the seabed. Later on (15 years), a water source well is needed from that formation for additional water. Natural gas will also be injected for pressure maintenance from 3 gas injectors (there is limited initial free gas, so gas will be brought in from the Heimdal gas centre through an 18 inch, 50 km pipeline laid in 2002). Sufficient gas will be available later on so importing gas then will not be required. (The initial GOR is 83 scf/bbl). The wells will be operated with gas lift, with gas being injected in the wells 1,600 m below sea level.

The production will plateau in 2004-2010. Grane oil will be exported through a 28 inch, 212 km pipeline to the Sture terminal north of Bergen (constructed in 2002). The oil will arrive at this terminal at 7 ºC, and there it will be heated to 30 ºC prior to being pumped into a 238,000 m3 storage cavern. This terminal at Sture receives oil and condensate from the Oseberg A platform.

The installation has two port capacities that can accommodate oil tankers of up to 300,000 dwt, five crude oil caverns with a capacity of 1 million m3, a 60,000 m3 LPG cavern and a 200,000 m3 ballast water cavern.

This reservoir pressure maintenance scheme replaces the earlier proposed CO2 sequestration plan proposed earlier.


The Alba sands are more than 120 m thick with no gas cap. The horizontal wells are placed close to the top of the reservoir. Water injection is at the base of the reservoir to create a bottom water drive. The produced water is not re-injected.

The Gannet E has a net pay of about 70 m, and is being developed using horizontal wells equipped with ESPs.

The Captain field has higher oil viscosity found in a lower Cretaceous sandstone. A waterflood using a total of 9 water injectors (re-injecting all the produced water as well as make-up water from an underlying aquifer). The horizontal producers will be completed with large standoff and equipped with ESPs. Polymers will be used to augment the waterflood. It is anticipated that the production rate will be about 15,000 b/d oil.

Bressay has the highest oil viscosity; cold production with 1, 2 and 3 legged horizontal wells are planned as part of a waterflood. It has a maximum net pay of 80 m with a small gas cap and large aquifer.

All heavy oil plays in the U.K. are being examined for EOR potential such as steam flooding, polymer flooding and in-situ combustion.



Photo: Captain FPSO Chevron-Texaco



Statoil has found oil, which is heavier than average for the Norne area, with its Linerle exploration well 6608/11-4, drilled 35 km northeast of the Norne Field. It has not given any indication of the potential size. But, it is cheered by the fact that the discovery is 5 km north-northeast of the Falk Field, which was discovered, 17 km northeast of Nore, in 2000 with well 6608/11-2. The oil in Falk is also heavier than Norne oil, and Statoil was hoping to boost reserves of a similar nature. Falk is considered to hold around 60m barrels of oil (NSL 1461/14).
Statoil's exploration manager for the Halten/Nordland cluster, Knut Chr Grinstad, said ""Linerle underpins our strategy to realise a collective development of these parts. The Falk oil has a higher density than average and preliminary analyses indicate that the oil in Linerle is also heavier. An assessment will now be made to see whether a profitable development is feasible. There could be more oil in this sequence of finds in the Norne area."
Statoil has recently submitted a PDO for the development of Svale and Staer, two other discoveries nearer to Norne, with first production via the Norne production vessel in autumn 2005 and peak production of 70,000 b/d (NSL 1460/4). But, it says, there will still be available capacity on the vessel after this development. At one time, Statoil considered that Falk might be in communication with Svale, but it is now thought that they are separate reservoirs.
The Linerle well was spudded with the drillship West Navigator on 30 April and completed on 23 May, 2004. It was drilled to a TD of 2,317 metres and completed in the Triassic. The well has been plugged and abandoned.
Photo: Statoil Norne














Heavy Oil and Bitumen in China

There are about 18 major sedimentary basins in China, but more than 80% of the reserves are found in two basins in Songliao and Bohai in northeastern China. The two major heavy oil fields, Daqing and Shengli are located here and were discovered in 1959 and 1961 respectively. The other heavy oil fields are Karamay, Xinjiang, Henan, Nanang and Liaohe. These fields are on cyclic steam stimulation and steamflooding. Fengcheng is a bitumen deposit near Karamay but is presently unexploited. The largest national oil companies in China are: China National Petroleum Corp (with its holding company, Petrochina) and China National Offshore Oil Corp.

More than 70 heavy oil fields have been discovered in these basins, coming from Cretaceous and tertiary reservoirs. Recent work is focussing on cold production and EOR schemes such as microbial, ASP and miscible gas floods. Current heavy oil production is split 50:50 between cold production and thermal methods.









Madagascar

The major bitumen deposit is at Bemolanga but the deposit is located in an environmentally sensitive area and has not been developed.





Heavy Oil in Turkey

The fractured deep carbonate reservoirs contain heavy oil in a Karst formation. This oil is recovered using primary production and CO2 miscible flooding. (Example: West Kozluca 12.4°API oil in limestone).

Heavy Oil in India

There is only one major heavy oil deposit here at Mehsana in Gujerat state containing about 150 million m3 of 12-17º API oil of viscosity 60-550 cp. The Kalol sand, 10-20 m thick, is located at a depth of 1000 m, has a strong bottom water drive. Two in-situ combustion pilots were performed here. After primary production 8-21% recovery was obtained.
















Heavy Oil and Bitumen in the United States

The estimated OOIP for the heavy oil resource base in the U.S. is 16 x 109 m3 (104 billion barrels), with the majority found in California (73%) and Alaska (19%). Bitumen (OOIP of 3.6 x 109 m3 or 22.4 billion barrels) is found primarily in Utah and Alaska.

The median OOIP for the 119 California heavy oil pools is 77 MMbbls while the non-California median is 6 MMbbls. Heavy oil accounts for about 70% of California’s total oil production, with the majority coming from CSS and steamflooding projects. The remainder is from primary production, waterfloods and in-situ combustion. The major California thermal recovery fields are shown in this table:

Field
Percent California Production
Midway – Sunset
26
Kern River
21
South Belridge
18
Lost Hills
5
Coalinga
5
Cymric
4
San Ardo
2

The average porosity of these pools is about 30%, with a net pay and permeability of 60 m and 1.4 Darcy respectively at a depth of 760 m.

Many of these fields have now been consolidated with the formation of key operators such as Aera Energy and Chevron – Texaco. Another key development has been co-generation facilities (facilities which produce both electricity and steam) from 50 to 300 megawatts.

The majority of heavy oil in Alaska is found in the Kuparuk River and Milne Point fields, west of Prudhoe Bay. It is estimated that there is 3-5 x 109 m3 (21-36 billion bbl) found in the West Sak and Ugnu formations. The combined thickness averages 320 m.



The West Sak fluvial sandstones are at a depth of 610-1370 m, consisting of an Upper and Lower unit. The Upper sand is 7.6-12 m thick, while the Lower sand is about 1.5 m. The reservoir properties are:

Reservoir Temperature, °C
27
Bubble Point Pressure, MPa
11.64
Oil Gravity, °API
14-22
Oil Viscosity at Reservoir Conditions, cp
50-3000
Oil Formation Volume Factor, m3/m3
1.06

Philips is the operator of the West Sak field while BP-Amoco is the operator in the Milne Point extension of the Kuparuk area called Schrader Bluff. The target for recovery is about 22%.

The Schrader Bluff area will be drained with multi-laterals using coiled tubing and “frac and pack” completions (hydraulically fracture the rock, prop it open with gravel and add screens behind it). A typical leg of a multi-lateral cost about $1 million US and produces about 50 m3/d. Extended reach (3 km radius) pad wells also helped reduce drilling cost.

Most wells have produced on ESP’s or electric submersible progressive cavity pumps, but BP-Amoco is looking at switching to jet-pumps. The ESP’s have a 2-3 year life when excessive sand is pumped and require a large rig for pulling them out of the wellbore. Jet pumps are more tolerant to sand and can be run in and out of the well on a slickline, reducing costs from $300 K US every couple of years for ESP replacement to $10 K once a year for jet pump nozzle replacement.

Photo: Kuparuk River Injector





BP's Schrader Bluff










EOR research is also underway for the heavy oil in the North Slope including: miscible gas injection using CO2 and NGL, cold production and pressure-pulse technology.

The US has a total oil sand base of 58 billion barrels. This table shows the distribution of tar sands deposits:

State
Total, Billion barrels
% Resource Base



Utah
19.3
33
Alaska
10.0
17
California
8.3
14
Alabama
6.4
11
Kentucky
5.1
9
Texas
4.8
8
Other
4.3
7

The Utah oil sands are oil wet which makes surface extraction, such as done in Alberta, very difficult. In-situ reverse combustion of this 14° API oil was performed, but it was difficult to control the flame front.

The three major Texas oil sands deposits are the San Miguel D, Hensel sands and Anacacho limestone have been exploited with varying degrees of success. The Anacacho surface outcrop has been mined for road asphalt. The San Miguel D has had the Conoco FAST (Fracture Assisted Steam Technology) process applied. Here, a horizontal fracture is developed between the steam injector and producer to conduct the heat. Unfortunately, the pay is thin (2-12 m) and the production was uneconomic.

The California oil sands have two unique deposits consisting of intermediate to oil-wet diatomaceous earth. A retort and solvent based process were operated at the McKittrick diatomite project in the 1980’s (hot water extraction processes were useless. Diatomaceous facies undergo significant alterations during the oil recovery process).


Photo: Midway Sunset

..
Just a few very large and relatively shallow oil-impregnated sandstone deposits in eastern Utah contain well in excess of 8.0 billion barrels of 8º-14º API oil in place. Despite numerous projects in the past to exploit this heavy oil resource, none were fully successful at then existing oil prices. To this day the resource remains undeveloped and largely ignored by the petroleum industry. The barriers to development have been many and varied: land access and permitting, site accessibility, the market for product, and environmental concerns. However, the principal impediments to development are technical - the very high viscosity of the heavy oil and the heterogeneity of the reservoir sandstones. Both of these factors limit the effectiveness of conventional thermal recovery methods, such as steam soak and steam flood. In other similar heavy oil deposits in Canada, Venezuela and California these technical problems are being overcome by application of new, innovative thermal recovery technologies, such as SAGD, VAPEX™ and toe-to-heel air injection. Also improvements in handling and refining heavy oils are expanding their marketability. Several areas within the large accumulations on the eastern margins of the Uinta Basin are well suited for the initial thermal recovery pilots needed to test the present commercial viability of this important domestic oil resource.





Russia and the Former Soviet Union (FSU) and Ukraine

Russia is estimated to have over one trillion barrels of heavy oil. The Yarega field (19°API, Middle Devonian Sand) in the Timan-Pechora area (6th largest field here) produces about 10,000 b/d of bitumen from surface mining, shaft and tunnel mining and thermal projects since 1932. This design led to the development of the UTF project at Dover. The Timan-Pechora basin stretches from the Urals in the east and to the Barents Sea in the north and there is 9 billion barrels remaining of heavy oil. In Kazakhstan, Caspian sea water is heated up and put into over 350 injection wells. In-situ combustion is also performed in the Kazakhstan oil field of Karazhanbas. The North Buzachi and Kalamkas fields on the Buzachi Peninsula produce heavy oils with 2% sulphur. The Volga-Ural area (Mishkinskoye and Gremihinskoye fields) also has thermal floods. In the west Volga-Ural Province is the Melekes tar belt. Arlan also produces heavy oil. The Orlyanskoye field here has a polymer flood to augment their water flood. Thermal projects are also underway in the Ukraine (Kokhaniv field). The northest portion of the Ural-Povolzhie area is also a heavy oil belt.

There is also heavy oil development in Tatarstan that is being developed with joint venture partners.



Photo: Deminskoye Heavy Oil Field

Photos: Tatarstan Heavy Oil fields


Photos: Tatarstan Heavy Oil







Timan-Pechora Basin

Stratigraphic-pinchout and normal-fault traps were created as early as Ordovician time during the opening of the Uralian Ocean and then again with aulacogen formation or rejuvenation during the Devonian period Some 150 m.y. of subsequent periodic structural inversion continuously created new structural traps, destroyed others, and impacted sedimentation patterns, culminating in the Hercynian and Early Cimmerian orogenies The regionally varying times of hydrocarbon generation (Carboniferous to Jurassic) overlapped the Late Paleozoic to Early Mesozoic tectonic cycle of trap formation and destruction. Dedeev and others (1994) believe that just 2-3% of all generated hydrocarbons remain trapped in the Timan-Pechora Basin. Discovery History
The first commercial Timan-Pechora oil discovery, Chib’yu field, with basal Frasnian (upper Devonian) Pashiy sandstone reservoirs, was in 1930. Two years later, heavy oil (19° API, 16,000 cp) was discovered at nearby shallow Yarega field in Middle Devonian sandstones, which have been exploited by shaft mining and steam injection since 1939. Yarega currently is the 6th largest field in the Timan-Pechora Basin Province with respect to ultimate recoverable reserves (Petroconsultants, 1996). In 1934, 240 km farther northeast near the town of Pechora, Yugid field was discovered with oil in Lower Carboniferous sandstones.










Trinidad and Tobago

Joint venture agreements are in place with Petrotrin (Trinidad’s national oil company) to develop Trinidad’s heavy oil reservoirs of Parrylands and Forest Reserves. Here, the net pay is about 70 m at a depth of 370 m. The reserves are captured using vertical steam injectors and horizontal drain holes drilled between them. The photos show La Brea (Pitch Lake), the world’s largest asphalt lake.



Photos: La Brea Pitch Lake, Trinidad


Crude oil gravities are 16-18° in the Parrylands block, and the heavy oil comes from the Pliocene Forest Formation at a depth of 400 m. The Forest pay is about 60 m with a porosity of 34-36% and permeability greater than 750 md. The water saturation is about 30%. Recoveries are less than 1% and higher (15-25%) with wells cold produced with progressive cavity pumps. New Horizon Exploration in Parrylands is using a six-pac approach for SAGD by drilling six vertical wells for each horizontal well plus steam injection. The horizontal well is 400 m and serves as a drain for the SAGD project. Cyclic steam stimulation is begun after cold production over a 20 acre pattern to cover 3-6 million barrels OOIP. Cyclic steaming creates cavities around the horizontal and vertical wells to create more movement of the oil. Then the vertical wells are converted to steam injectors and the project goes into a continuous steamflood until steam breaks through. This will have a production life of 7-12 years with a 4-5 year plateau of 1,000 b/d. For 96 vertical and 16 horizontal wells, an average of 10,000 b/d is expected. The oil is pipelined through the Petrotrin pipeline to the refinery at Point-a-Pierre.

In the southern basin, the producing reservoirs are (from shallowest to deepest at 100 m to 4000 m): Morne L’Enfer, Forest, Cruse, Deep Cruse, Karamat, Shallow and Deep Herreras. Clays provide the cementation and the sands are unconsolidated. Tars and bitumens (<10 °API) and oils from 14-28°API are found in these sediments. There are also occasional small gas caps underlain by oil or water.


Photo: Drilling 6-pac in Parrylands




Kuwait

The Greater Burgan field, covering a surface area of about 320 square miles, located in southeastern Kuwait, is the largest clastic field in the world. This field produces from the Cretaceous age sandstones of the Zubair, Burgan and Wara formations, as well as the Minigish and Marrat formations found in the Cretaceous and Jurassic carbonates. There are over 1000 wells drilled here producing conventional oil.

This field was found in 1938 and put on production in 1946. It is shown in Figure HOB-10:


Current production is constrained by surface facility capacity (water handling). Heavy oil is not yet produced.

The Burgan formation is heavily faulted and has a strong aquifer. To the west in Kuwait and in southern Iraq, the net pay is about 360 m. The original reservoir pressure at 1220 metres subsea was 14.3 MPa and has declined about 1.5 MPa since production began. The oil is undersaturated and its API gravity changes from 34° at the crestal positions to 10° near the oil-water contact. A discontinuous 3-15 m interval of heavy oil is located above the original oil-water contact. Porosity and permeability range from 25-30% and 2 to 10 Darcy’s.




Saudi Arabia


At Ghawar, the worlds’ largest oil deposit containing more than 75 billion barrels, there is a 82 m heavy oil tarmat found in the carbonate Arab-D formation. At the reservoir temperature of 110°C, oil viscosity is 12,000 cp (oil density 0.976-1.067 g/cm3 @15°C).

Photo: Production deck modules Safaniya

Safaniya is the world’s largest offshore oil field, located in Saudi Arabia, producing Arab heavy oil, producing from the Safaniya and Khafji formations. Horizontal wells are being drilled there to prevent water coning (above). According to our classification in Chapter 1, Arab Heavy oil would be considered a medium gravity oil.

Indonesia

The largest steamflood in the world is at Duri on the island of Sumatra. The project is run by Caltex. As can be seen by the diagram below, there are over 2000 producers and 600 steam injectors.











Ecuador

Drilling for heavy oil at Tarapoa:



Photo: CNPC Tarapoa Heavy Oil Development

Reservoir Temperature: 100°C, Bubble Point 500 psi, Oil Viscosity 7 cp. Depth 10,000 ft., Pumps: ESP’s, waterflood development.



Ecuador Villano Project

The Ecuadorian unit of ARCO recently started up commercial operations in its Villano oil field development project in the Oriente jungle region of eastern Ecuador.


While at first glance a conventional oil field development, Villano in fact represents a new standard in the way oil and gas companies can work in an area with extremely sensitive environmental and indigenous cultural issues.

This is not unprecedented; oil and gas companies have in recent years pushed the envelope on how to effectively explore for, develop, and produce hydrocarbons in South America`s rainforest while preserving environmental and cultural values.

Among the other watersheds of this evolving paradigm are projects operated by Occidental Petroleum Corp. in Ecuador, Royal Dutch/Shell in Peru, and BP Amoco plc in Colombia

What makes Villano the new standard-bearer are two things: 1) the singularly novel way in which the project was literally improvised, essentially on the fly, to accommodate a roadless development in the rainforest; and 2) the way the project is serving as a prism for reflecting the increasingly complex web of environmental, social, economic, and political issues that has grown up around industry operations in the rainforest.

Background
ARCO, as operator with a 60% interest, and its partner Agip Petroleum (Ecuador) Ltd., 40%, in 1988 signed a service contract with the Ecuadorian government covering exploration and development on Block 10 in Pastaza province. In 1992, ARCO disclosed the Villano discovery, estimating reserves at 175-200 million bbl of oil. Under the 20-year production phase of the contract, ARCO and Agip are to recover 125 million bbl in compensation for exploration and development costs, plus a service fee.

The original plan called for production to start up in April 1999, with output expected to reach 30,000-40,000 b/d, depending upon capacity available in the Trans-Ecuadorian Pipeline (SOTE), the 330,000 b/d capacity trunk line that carries crude oil from oil fields in the Oriente to the refinery and export terminal as Esmeraldas. Capacity limitations on SOTE have long been a sore point for Oriente operators, which collectively can produce a great deal more oil-some say perhaps twice as much-as SOTE is currently capable of handling The field started up production in late May and began shipments to SOTE in 1999.
























Australia

Photo: Australian Oil Shale Deposits
























Romania

Romania has had oil production since 1857 and has many IOR/EOR methods tested. Some projects include:

· Sarata Monteoru oil mine in 1925
· Gas injection on the Boldesti (Meotian) in 1936
· Water injection on the Boldesti (Sarmatian) in 1950
· In-situ combustion at Suplacu de Barcau (Pannonian) in 1964
· Steam injection at Moreni (Levantine) in 1964

In the 1990’s, there were 181 commercial IOR (water and gas injection) projects and 36 EOR experiments (CO2 miscible, thermal, chemical, microbial and mining projects) operating. These methods provide 12% of Romania’s oil production. About 30% of the current reserves of Romania can be recovered using water injection.


The Romanian reservoirs range from 100 to 4800 m in depth and a thickness of a few meters to tens of meters. The Romania map is shown here:


The reservoir rocks consist of sandstones or limestones which are continuously layered with oil gravities from 14 to 37°API. Natural water encroachment has been hindered by strong folding and faulting. The major reservoirs are in the Moesic Platform, the Meridional or Eastern Carpathian Depression, the Pannonian Platform and the Continental Shelf of the Black Sea. The reservoirs are of different ages, from the upper Pliocene (Levantine) to the lower Triassic.


Water injection has been applied to heavy oil reservoirs such as Sarmatian-Videle (simultaneous and separate production of two formations), Otesti-Meotian and Independenta-Pliocene with small response.


CO2 injection has been tested on the Bradu Albota reservoir.

Microbial EOR has been performed on the Bragadiru, Caldarau, Baicoi, Tintea, Ileana and Vata reservoirs. The Baicoi and Baciu reservoirs had ASP tried as well.

Mining methods at the Sarata Montereou mine had a total of 73 shafts and over 200 horizontal wells drilled.

In-situ combustion has been applied to the heavy oil reservoirs of:

· Suplau de Barcau (largest in the world)
· East and West Videle
· East and West Balaria
· Sarmatian Moinesti


Steam injection is underway in Suplacu de Barcau, as well in the Otesti and Videle reservoirs.


























Iraq

The southern Rumaila field produces Basrah Heavy (22-24°API, 3.4% sulphur). The East Baghdad field produces about 50,000 b/d of 23 °API oil along with 30 million cubic feet of gas per day. The OOIP in East Baghdad is about 11 billion barrels. Development costs are about $1 US per barrel.


The West Qurna field (near Basrah) contains heavy oil as well, with 2/3rds production from the Mishrif formation. Fifty km north of Basrah is Majnoon, with reserves of 10-30 billion barrels of 28-35°API oil. The largest pipeline is the 1000 km, 40 inch Kirkut-Ceyhan (Turkey) line, which can handle 1.1 million b/d.

There are 3 tanker terminals at Mina-al-Bakr (the largest), Khor al-Amaya and Khor al-Zubair.

About 48% of Iraq’s reserves are heavy oil. As shown on the next page, the heavy oil fields of Quaiyarah,Qasab, Najmah and Jawan produce about 170,000 barrels/day.





Iran


The Soroush and Nowrooz offshore oil fields are located about 75 km west of Iran’s largest terminal port of Kharg Island and contain about 1 billion barrels of heavy oil. Shell purchased the producing rights and plans to bring production on over 200,000 b/d by 2004. In Southern Iran, the Kouh-e-Mond field contains more than 20 billion barrels heavy oil.


Oman


Southern Oman’s heavy oil pools are being developed by Petroleum Development Oman (PDO). Amal has had electromagnetic heating and steam soak, Marmul and Nimr a polymer flood, Qarn Alam thermal methods and the 14-16°API oil of Mukhaizna is being developed with thermal methods and horizontal wells.

Libya


Libya’s heavy oil field, the Haram field, is in the Sirte Basin.

Egypt

The encouraging oil potentiality (proven oil of API gravity ranging from 11.4° to 19° in Miocene and pre-Miocene sandstone) of El Nezzazat, Feiran and Abu Durba blocks will add more oil reserves for the future shallow structure exploration phase. Heavy oil occurs in geologic settings, which are unconventional by accepted standards, yet they are economically interesting prospects in the light of modern methods of production. It is worth mentioning that the two main crude oils in the Abu Durba Recent sediments and the Kareem Formation sandstone, of well GS 277-1 have different nickel/vanadium ratio, indicating derivation from two different possible sources. In the fractured carbonate Ras Aran heavy oil reservoir, CSS is being implemented.





Syria


Syria’s heavy oil pools are in the south west (operated by the Syrian Petroleum Company):

· Suwaidiyah
· Rumailan
· Alian
· Tishreen
· Gbebeh

Oil shales are found in the Yarmouk Valley (close to Jordan).















Cuba




Santa Cruz is a new heavy oil discovery, the crude oil, which Sherritt confirmed to be 18° gravity, was "a higher grade of oil than that producedUon the Canasi and Seboruco fields" due to having less than 5% sulfur.


Nigeria

The tar sands deposit of southwestern Nigeria occur along an east-west belt over 120 km long in Ondo, Ogun (Ijebu Ife), Edo, Lagos and part of the Bendel states of the Dahomey basin. The country has a proven reserve of 42 billion barrels spread along the 120-kilometre ‘bitumen belt’.

The Cretaceous sands consist of two stratigraphic bands, Horizon X and Y, (separated by a thick organic shale) with a combined average thickness of 30 m. The oil gravity varies from 5-20 º API. In Ondo State, there is about 42 billion barrels of heavy oil. The lower bituminous Horizon Y is comprised of fine to medium grained sands interbedded with thin, gray sandy clays and shales. The sands show a high oil saturation of about 30 wt %.

The upper bitumen sand, Horizon Y, consists of fine to medium grained sands with occasional thin beds of sandy clay, clay, shale and occasional loose sand interbeds devoid of bitumen. The thickness is about 15 m, with a mean oil saturation of 12 wt %.

Both sands are water wet, with porosities ranging from 24 to 35%. Quartz is the dominant sand material (over 90%). Kaolinites, illites and smectites are also found in the sands.

The tar sands are being examined for mining purposes.





Nigeria, aside from its over 30 billion barrels of oil reserves, 159 trillion cubic feet of gas and about 458 million metric tons of coal, has an estimated 40 billion barrels reserves of bitumen.

Professor of geology at the Obafemi Awolowo University, Professor Joseph Nwachukwu, who disclosed this last week at the conference organised by Nigerian Association of Petroleum Explorationists (NAPE), said bitumen, which is also noted to have a future potential recovery of 36.540 billion barrels, was located in south Western Nigeria, particularly in Ogun, Ondo and Edo States.

Nwachukwu said Nigeria was rich in natural bitumen commonly identified as tar sand, oil sand, native asphalt or oil impregnated rock, which “is black and easily soluble in organic solvents and is formed by the up-dip migration of crude oil into porous sand near the surface of the earth, where it is altered.”

He explained that some “tar sands are also associated with limestone and clays,” which could be used for road construction material, fuel and petrochemical production as a potential alternative energy source.

Nwachukwu said: “The Nigerian tar sands are currently exploited mainly for road construction works but its prospects, as a potential alternative energy source, remains very high. The bitumen is intended to serve as feedstock for the Kaduna refinery for the manufacture of lube oil and also for the petrochemical industry.”

The expert stated that because of the Federal Government's desire to diversify the nation's economic resource base, the Committee for the Implementation of the Bitumen Project was set up and operated between 1989 and 1993. But recently, the government set up another bitumen committee, Bitumen Project Implementation Committee (BPIC), to oversee the economic exploitation of Nigeria's bitumen reserves.

The terms of reference for BPIC was aimed at serving the overall economic interest of Nigeria and the producer states in particular, which spurred the official flag-off of the commercial exploitation of bitumen deposits in Ondo State.

The research conducted indicated that the geological setting include the outcrop belt of the tar sands that lies within the Benin Basin, which is a marginal pull-apart basin and margin sag basin. The Okitipupa high marked the eastward limit of the basin, which extended westward into Togo and the Volta Delta, Ghana.

Nwachukwu said because of the nature of the bitumen, Enhanced Oil Recovery (EOR) techniques should be employed in its extraction. He disclosed that only five EOR schemes were currently successfully applied to heavy oils. Another bitumen recovery technique utilises the Steam Assisted Gravity Drainage (SAGD) process, made use of horizontal wells, buoyancy and steam to produce the heavy oils.

Most of the world's EOR productions, which include light and heavy crude oils, he said, were based on thermal processes. Over 90 per cent of the thermal processes were based on heavy oils and steam and accounted for over 90 per cent of the production by thermal methods. Steam had been widely used because of its economic method of recovering heavy oils and bitumen.

Nwachukwu said because of the high viscosities and high asphaltics, which pose mobility problems, the bitumen had to be upgraded before transportation to the refineries. Two basic upgrading processes commonly in use include carbon rejection and hydrogen addition. Both processes helped to improve the hydrogen-carbon ratio.

He said: “The upgrading results in pipeline or refinery quality product, which may also serve as a diluents for additional heavy oil or bitumen. Heated pipelines are expensive for transportation. Where gas condensate supply is plentiful, as in Nigeria, the use of diluents may be feasible.”

Heavy Oil in Pakistan

There are only 2 heavy oil fields here on the upper Indus:

1) Joya Mair (16º API)
2) Chak Naunang (12-19º API)


Senegal

The Dome Flore block is located in West Africa, offshore Senegal and Guinea Bissau, in the area administered by the Agence de Gestion et de Cooperation (AGC).
The deal is subject to the final approval of the High Authority of AGC.
The Dome Flore block contains an estimated 800 million barrels of heavy oil in place. Thirteen wells have been drilled into the block, and several have penetrated 10-13 API heavy oil deposits, with thickness of 20-35 metres, in shallow Oligocene reservoirs.
Additionally, two wells have found much smaller deposits of 30-35 API light oil. The discoveries lie in 50 metres of water, 70 km offshore.



Brazil

Petroleo Brasileiro SA (Petrobras) has developed a program called PRAVAP (Programa de Recuperção Avançada de Petróleo ) to improve oil recovery from its oil fields.

The Potiguar basin contains about 300 million m3 of heavy oil (13-16°API) with a viscosity greater than 1,000 cp which is found in shallow reservoirs (289-350m):


This basin was discovered in the 1970’s and developed using cyclic steam stimulation and then later into steam flooding. Poor results were seen under flooding, and the flooding was stopping and CSS was continued in selected areas.

The PRAVAP scope is to review the entire steam injection operation by means of reservoir characterization and determine the benefits of horizontal wells, infill drilling, optimized injection rates and other heavy oil recovery methods.

The main producing formation is the Açu, where two steam flood pilots were implemented in the Fazenda Belem and Estreito fields. The response was good as shown:



Cogeneration plants are being developed for developing commercial steamfloods. Additional reserves of 15 million m3 is expected to be produced from the Estreito and Alto do Rodrigues fields.

Waterflooding is the dominant recovery method for light oil in Brazil. The fields being waterflooded contain more than 11.6 billion barrels OOIP. The largest onshore field is the Sergipe-Alagoas (OOIP of 266 million m3). The offshore Campos has turbidite development using new methods of reservoir characterization which alter the geological interpretation. Albacora heavy oil has an API of 18°. Recently, Shell has made a offshore heavy oil discovery at Bijupira-Salema (Santos Basin).


Horizontal wells have now increased recoveries here by 7%.

High water production, due to water coning and poor sweep efficiency, has led to developments in profile modification. The Potiguar basin has a strong bottom water drive. The solution has been:

a cationic polymer with wettability reversal characteristic
a anionic polyacylamide based on cross-linking

This led to the "Selepol" process. Polymers were developed to be stable at high temperatures and high salinity. Mechanical methods for preventing water coning included selective and simultaneous production from both the aquifer and producing zone. The Selepol process uses cationic and anionic polymers to yield a highly selective affinity towards the water channels. This figure shows the results from one Selepol production profile modification:


About 100 wells have been treated with a $10 million (US) net revenue realized from the additional oil production.

Some reservoirs (in the Reconcavo basin) have poor recovery due to paraffin deposition problems in the tubing and flowlines due to the waxy oil’s overlap of its cloud-point range and reservoir temperature. This figure shows the produced oil’s composition in the Fazenda Bálsamo field:


Thermal treatment removes long chain alkanes and thus paraffin deposition occurs in the reservoir. Two major tectonic uplifts occur in the basin at 1500 and 750 m and were found by analyzing fission tracks in the apatite minerals of the producing Sergi formation. There were dated before the hydrocarbon migration or accumulation. The estimated 30ºC drop in reservoir temperature associated with these uplifts cross validates the paraffin precipitation assumption, suggesting that the oil in place is at an equilibrium cloud-point temperature condition with solid wax deposits co-existing with a liquid oil phase. Based on this, steamflooding appears to be one way for improving oil recovery. The Dom Joao field was selected for a pilot test. The field had more than 113 million m3 OOIP and had produced 15% OOIP over the last 50 years. Incremental oil by steamflooding has now been over 12%.

Asphaltene precipitation was studied in the Marlim field in the Campos basin. The asphaltene deposition envelope is shown here:


The asphaltenes in Marlim crude (containing an average 0.5% asphaltene) is very stable relative to reservoir depletion.
Photo: Petrbras18 at Marlim




Photo: Marlim P-40
Photo: Marlim P-37FPSO
Photo: Petrobras P-36 Semisubmersible Platform sank in 1,350 m water at Roncador



Santos discovery
One of these is a large oil reservoir 200 km southeast of Rio de Janeiro on Block BS-4 in the northern part of the Santos basin off Brazil. The discovery well, 1-SHEL-4-RJS, drilled in February 2001, also by the Stena Tay drilling unit, encountered 68 m of net oil pay in Tertiary deepwater sands. An appraisal well, 3-SHEL-8-RJS, was drilled in 1,557 m of water to a TD of 2,500 m. It reached the reservoir objective in early November 2001, encountering 97 m of net oil pay.

The estimated flow-test was 3,000 b/d, and first projections indicate potential reserves of 300-500 million bbl. Shell operates the Santos basin block and has a 40% interest; Petrobras holds 40%; and ChevronTexaco Corp. 20%.

The company said the Santos crude is heavy, however. At 15° gravity, it is heavier than anything currently produced in Brazil. The heaviest that Petrobras currently handles is 19° gravity in Marlim and 18° gravity in Albacora giant fields. Technical problems associated with heavy oil make it costly to produce, and Shell executives said the company would produce its Bijupira-Salema Campos basin offshore discovery first because that oil is lighter.



Santo State Jubarte and Cachalote 19-20°API oil, 0.5 billion barrels OOIP

One of the most recent discoveries in the Campos basin is the Jubarte oil field off Epirito Santo state in 1000- to 1500-m water depths. Reserves are approximately 95 x 106 m3 of 0.95-g/cm3 oil. Initial tests in a vertical well indicated that the productivity index (PI) was insufficient for commercial oil production. Later tests on a horizontal well recorded a PI 12 times the PI of the vertical well, indicating that it would be possible to produce Jubarte field heavy oil at commercial rates.
Introduction
Jubarte field was discovered in January 2001 77 km off the Espirito Santo state coast in southeastern Brazil. Water depths range from 1000 to 1500 m. The field contains 0.95-g/cm3 oil with a 0.014-Pa•s viscosity at saturation pressure. Dead-oil viscosity at 20oC is approximately 3 Pa•s, making it the most viscous oil at surface conditions ever produced in Brazil from a deepwater field. Field discovery and first-oil production took place within a 22-month period.
Reservoir Geology
Jubarte field reservoirs are trough-confined gravel- and sand-rich turbidites of Maastrichtian age. They are part of a 350-m-thick succession composed of amalgamated turbidite beds and interbedded mudstone with a 73% net-to-gross ratio. Core porosity ranges from 21 to 38%, and permeability averages 340 md.
The oil accumulation is restricted to an elongated northeast-oriented anticline with the eastern portion truncated by an extensional fault (Fig. 1). This fault acted as a conduit for oil migration from underlying early Cretaceous source rocks.
Fig. 1—Jubarte field structure.
The reservoir top is characterized by lower seismic impedance, and the reservoir base is defined by an erosive surface that can be related to decreasing seismic impedance across most of the field.
Extended Well Test (EWT)
EWTs in offshore fields are the best strategy to reduce uncertainties and mitigate risks before making large investments for production systems. Petrobras has a long tradition of operating early production systems (EPSs) and performing EWTs in its deepwater fields. From a reservoir engineering point of view, EPSs not only prove reserves through material balance, but also provide information about reservoir internal characteristics that are critical for waterflood success.
For offshore heavy-oil fields, the main objective of an EWT is not just to understand reservoir behavior but also to determine the whole production process. The information obtained is valuable, and intensive use of value-of-information (VOI) techniques is fundamental to obtaining approval for EWTs.
A good example of an EWT was the one performed in the Captain field in 1993 that set the basis for the economic development of the field discovered 16 years earlier. Many issues related to the production process were investigated, such as vertical permeability, oil/water relative permeability, water coning behavior, production performance of a long horizontal well, artificial lift, and oil processing.
EWT VOI
Even after 3D seismic interpretation, appraisal-well drilling, core analysis, rock characterization, and cased-well test in one vertical and one horizontal well, there were uncertainties related to reservoir performance and the heavy-oil production process. The VOI associated with an investment is defined as the difference between the expected mean value of the project with the information and without the information. The VOI estimation was conservative because if severe problems occurred during heavy-oil production, the development phase would not be feasible. The analysis was restricted to reservoir performance, mainly aquifer strength and effectiveness, which would indicate the necessity of water injection, and internal shale distribution, which controls pressure distribution and water-breakthrough time. Oil and water permeabilities also were considered.
Several production scenarios were simulated by use of 3D three-phase numerical simulations that considered the information to be provided by the EWT. The VOI to be provided by the EWT was estimated at U.S. $58 million, which was greater than the investment required to implement the EWT. This analysis supported preliminary approval of the EWT by the Petrobras board in December 2001 and would be reviewed after drilling and testing the horizontal well.
EWT Planning. Well ESS 110HP was selected for the test. The well had 1076 m of horizontal length completed with 5½-in. tubing with premium screens and an openhole gravel pack. Three external casing packers were installed to allow isolation of watered-out intervals. The well tested in July 2002 had 0.95-g/cm3 oil, 43 m3/m3 gas/oil ratio, 1200-md rock permeability, and no wellbore damage.
Between the preliminary EWT approval and beginning the EWT in October 2002, several activities occurred.
The decision was made to use a floating production, storage, and offloading (FPSO) vessel, and the Seillean, a dynamically positioned vessel operating in the Roncador field, was selected.
A high-power, high-rate electrical submersible pump (ESP) was selected as the artificial-lift mechanism to be installed above the Christmas tree.
The Seillean drillpipe riser was changed to allow ESP connection.
The Seillean oil-processing plant was changed to process the 0.95-g/cm3 oil.
EWT planning was completed.
Because it would take 18 months to get a Christmas tree for deep water with slots for the electrical power cable, the decision was made to install the ESP connected to the drillpipe riser above the Christmas tree.
EWT Operation. After the horizontal well was drilled, completed, and tested and the Seillean positioned, the EWT began in October 2002. The following were monitored.
Downhole pressure and temperature.
Pressure and temperature at the Christmas tree.
Pressure and temperature at the FPSO.
Pressure upstream and downstream of the choke.
Oil, water, and gas rates.
The well test began 24 October and was interrupted 10 December when the field was declared commercial. This period was followed by almost 1 year of production as the pilot phase of the Jubarte field development plan.
The well began production in the EWT by natural flow at 2622 m3/d. Two months later, the ESP was turned on, and the well rate limited by limitations in the processing plant was set to 3178 m3/d. In April 2003, adjustments were made to the processing plant, and the oil rate was set to 3496 m3/d. Petrobras intends to produce the project under the pilot-phase plan until December 2004. Information gathered during the EWT and the pilot phase is extremely useful for the design and optimization of Phase 1 and 2 of the field-development plan.
Well Engineering. The drilling and openhole gravel-pack completion of the long horizontal section was successful. No sand production occurred. From the 1076-m net pay, approximately 850 m contributed to flow. The stabilized well PI decreased slightly during the test.
Artificial Lift. The ESP performed well with no failures, but the full 3975-m3/d capacity was never reached because of limitations in the production plant. The temperature loss between the Christmas tree and the production header was much lower than predicted, which had a favorable effect on the heavy oil. During static periods, the oil did not solidify.
Oil Separation, Treatment, and Storage. Severe foaming, which limited processing capacity, was observed in the separators. Several antifoaming products were tested as well as polymer injection at the Christmas tree. The foaming was controlled, and the processing capacity was increased. Several changes in the export pumps and offloading hose were implemented.
Reservoir Properties. Continuous acquisition of downhole pressure and temperature allowed a reservoir history match with a 3D three-phase reservoir simulator. A special feature that allows automated and gradual change in selected reservoir properties was useful in guaranteeing an excellent match of the bottomhole pressure (Fig. 2) and its derivative. It was concluded that the internal mudstone beds may cause some restriction to vertical flow, but do not comprise widespread vertical-permeability barriers. The occurrence of a tar mat near the oil/water contact reduced the action of the bottom aquifer. The main fault in the central part of the field (Fig. 1) does not seal. The water-cut and pressure match were obtained by use of relative permeabilities measured at reservoir conditions.
Fig. 2—Pressure history match during the EWT.
Commercial Declaration. The interruption of the EWT and the commercial declaration of the Jubarte field were based on the following.
High rates maintained during the EWT.
PI almost constant during the EWT.
Good pressure and production match.
ESP concept proved.
Separation and treatment conditions tested.
Storage and offloading under control.
The log information supplied by two appraisal wells helped reduce uncertainties.
Conclusions
The Jubarte field development was conducted gradually so the main uncertainties could be known and controlled. The main uncertainties were related to the production of the heavy oil from a poorly consolidated deepwater reservoir with a large bottom aquifer. Other unknowns were the characteristics of the reservoir faults and internal heterogeneities as well as the distribution and sealing effect of a tar-mat layer just above the oil/water contact.
The VOI approach allowed approval of the drilling, completion, and testing of a long horizontal-well section. The same concept was used to approve an EWT that has been extremely successful. On the basis of the data gathered from the EWT during the appraisal phase, it was possible to declare the field commercial.
The development plan was divided into the production pilot comprising the horizontal well producing to the Seillean FPSO, Phase 1 with four wells producing to a larger FPSO, and Phase 2, which is being designed.
The Jubarte oil is one of the most viscous oils at surface conditions ever produced from a deepwater field. The careful approach to building a development plan has provided the basis for Petrobras to meet this unique challenge for the oil industry.

Espirito Santo heavy oil project a deep-water testbed for the next generation of Petrobras floating production solutions, opening up billions of barrels of reserves
Many Petrobras insiders believe the Brazilian giant's most significant recent achievement is its success in producing heavy oil in deep waters, where increasingly large deposits are being found.
The development project for Jubarte, a deep-water field in the Espirito Santo basin, is being carried forward with a spirit of inquiry and rational risk-taking that is yielding rewards for Petrobras and insights for the whole industry.
The company has carried out a successful pilot production project on Jubarte, where proven reserves are listed at 600 million barrels, forming part of a wider heavy oil complex estimated at 2.5 billion barrels.
It is now preparing to install a 60,000 barrel-per-day floating production, storage and offloading vessel whose varying well configurations are intended to facilitate the decision-making process for a much bigger "definitive" floating production unit.
The Jubarte field was discovered in January 2001, and an appraisal programme showed that the crude of 17 degrees API was much heavier than first thought. Water depths range from 1000 to 1500 metres.
Hungry for new reserves, Petrobras decided to investigate the potential of Jubarte despite the uncertainties relating to the production of heavy viscous oil from a deep-water reservoir with a large bottom aquifer.
It shot additional 3D seismic data in 2001 and drilled and tested a 1076 metre-long horizontal well, the ESS-110HP.
That well recorded a PI 12 times higher than the vertical discovery well, quickly proving it would be possible to produce the Jubarte heavy oil at commercial flow rates.
Faced with continued uncertainties relating to reservoir performance and the production process, Petrobras began an extended well test.
The Jubarte project employed an adapted dynamically-positioned FPSO, the Seillean, to test the commercial viability of producing the heaviest and most viscous oil ever attempted through a wet completion system in the Campos basin.
The Seillean had been operating on the Roncador field and needed some upgrades to facilitate the processing of heavier oil, including the installation of an additional conductor to mitigate temperature loss.
Among the elements tested were a 900HP electrical submersible pump (ESP), connected to the pipe riser above the X-mas tree.
The extended well test began in October 2002 and vastly exceeded expectations with a natural flow rate of up to 16,500 barrels per day, leading to a declaration of commerciality and the launch of a pilot production project a few weeks later.
The ESP was turned on two months later and, by April 2003, when some adjustments were made in the plant, the well was set to 22,000 bpd and stayed almost constant to November when the pilot was concluded.
The information gathered during the EWT and pilot phases helped Petrobas build up a reliable flow model and reservoir characterisation.
Petrobras opted for a first-phase production system producing 60,000 bpd from just four horizontal wells, including the ESS-110HP.
The unit chosen for the first phase, the FPSO P-34, is currently undergoing upgrade work on the dockside of Vitoria, the state capital, and is slated to enter production next year.
The aim is to continue accruing and incorporating information to shape the final project for the larger "definitive" unit that will replace the P-34 in late 2009 or early 2010, and will be used for the second phase of production.
"The Seillean has clearly proven that Jubarte's heavy oil is commercially viable but the focus for the first-phase of development now switches to optimisation of the project ready for the second phase," says Jubarte-Cachalote production asset manager Bento Daher.
Despite the positive performance of the ESP system on the Seillean test, the critical role of the pump configuration means that this remains a key area of continued development.
"The four wells will test different artificial lifting methods, using different configurations of submersible centrifugal pumps and the back-up gas lift system," adds Daher.
The electrical pumping system will enjoy the central role in the lifting process and will employ 1200HP units.
Petrobras intended to use ESPs rated at 1500HP but such power is only currently available in prototype form at a price considered unsuitable for a concept still in the testing phase, acknowledges Wagner Trindade, co-ordinator of the heavy oil production programme at Cenpes, the research arm of Petrobras.
The company also intends to explore cost-saving mechanisms by testing an ESP installed on the seabed, permitting installation and intervention work to be carried out by a service vessel rather than a rig.
"Intervening when the ESP is in the pipe riser can cost as much as $3 million due to rig costs. With its two-year lifespan, the ESP could actually become less competitive than a large gas compression system using expanded valves," Trindade argues.
Another important element to be tested and developed on the P-34 project is the efficiency of the separation process.
The gigantic liquid processing on the larger units that will follow the P-34, and the slower separation rate for heavier oil, have led Petrobras' research arm to strike co-operation agreements with several suppliers of compact separation technology.
The P-34 project will include scaled-down testing of acceleratted separation technologies, such as centrifugal or hydrocyclone techniques.
Although Petrobras has yet to conclude and approve its conceptual studies, the project that is emerging outlines plans for a unit, dubbed the P-57, with liquids processing capability of 300,000 bpd, of which 100,000 bpd will be water.
"Just handling so much water implies a major innovation for us. We are analysing the implications of installing much bigger separation systems," says Daher, stressing that the P-34 project will also include tests of newer, more compact separation systems.
The P-57 project is likely to include between 15 and 19 producer wells and up to seven water injectors.
The narrower contrast in the density of heavy oil and water also means the separation processing plant tends to be more sensitive to the movements of the floating production unit.
This, and the fact that purpose-built units can offer more deck space for plant, is persuading Petrobras that it is time to test a new concept.
A number of well-placed Petrobras sources confirm the P-57 is almost certain to be the latest version of the FPSO BR, designed by the Cenpes research centre, representing a major new departure for the company.








































Mexico

































Albania




The Patos-Marinza field is one of the largest onshore heavy oil fields in Europe located in southern Albania. It has an Original-Oil-In-Place (OOIP) of 2,000 MMbbl. The field was originally discovered back in 1932 and has over 2500 wells. Cumulative recovery to date is les than 7%. There are two primary production horizons, the Driza (7-18 API) and Marinza (13-35 API) at depths of around 1650 m and net pays in excess of 100m. Wells have been historically produced utilizing conventional pump jacks with some of the lighter Marinza zones having a partial water flood scheme. The average production of existing wells is less than 5 boepd.

In 1994, Premier Oil signed a license Agreement with the Albanian State Oil Company (Albpetrol) and has subsequently farmed out equity to Preussag Energie and the International Finance Corporation (IFC). These parties (Albpetrol, Premier Oil, Preussag Energie, and IFC) have since formed a joint venture company called Anglo-Albanian Petroleum (AAP). AAP is the Operator of the Patos-Marinza oilfield.After several years of studies and pilot tests, including thermal “huff and puff”, a technique called “CHOP” (Cold Heavy Oil Production) using progressive cavity (PCP) screw pumps has been tested to produce the cold ”foamy-oil” at well rates of 100 – 200 bopd. The current development to remove uncertainties with production, reservoir, and cost involves drilling 20 wells from two-pad location and re-activating 8 wells.

To date AAP has drilled 14 wells and place one pad on production as well as 6 re-activations. Much of the technology and equipment for this project has been sourced from Alberta. The success to date has been accomplished in less than ten months from approval. Drilling is expected to be completed in mid-April with peak production of 3500 boepd expected by September 2003.
A Plan of Development is also in place to produce 30,000 boepd including the drilling of over 200+ wells and construction of treating, pipeline and export facilities. New wells are required due to the condition and casing damage of existing wells.

The Plan of Development is envisaged to commence in 2004 once the current phase has been evaluated.

Columbia

The Colombian unit of U.S. oil company Omimex Resources, Omimex de Colombia, reported that the proven reserves of heavy oil in the middle basin of the Colombian Magdalena River are 200 million barrels, Omimex general director for Colombia, Segundo Antonio Gonzalez, said. Colombian oil company Ecopetrol and Omimex de Colombia will invest $50 mln in extracting the oil below the Magdalena River, it was reported on January 9, 2004. Ecopetrol and Omimex will exploit the reserves in the oilfield Under River in the Magdalena River basin between the municipalities of Nare and Puerto Boyaca, central Colombia.
The Bajo Rio reserves total 47 million barrels. The oilfield will be exploited in two phases. The first phase will attract a $28 mln (22 mln euro) investment for the extraction of 25 million barrels.
Twelve multinational contracts for oil exploitation in Colombia were signed in 2003. The oil exploitation projects in Colombia are expected to rise as of 2004, because of the newly established rules for oil exploitation introduced by the Government of Colombia.






Algeria
The Hassi R’Mel heavy Oil Rim, located 500 km south of Algiers, is exploited using horizontal wells since 1991. Net pay is 3-12 m with permeability of 500 md. The heavy oil is sandwiched between a gas cap and bottom water. It is operated by the state oil company, Sonatrach (Societe Nationale pour la Recherche, la Production, le Transport, la Transformation et la Commercialisation des Hydrocarbons). Algeria belongs to OPEC.

Chapter Review

World Deposits


For heavy oils with the same density, why are Canadian heavy oils more viscous than Venezuelan heavy oils?

The reservoir temperature in Venezuela is higher than that in Canada. Recall that heavy oil viscosity is strongly dependant on temperature, as given by Walther’s equation. As well, Venezuelan deposits are deeper than Canadian deposits. Thus, well productivity from Venezuelan cold producing wells is expected to be higher than Canadian production.

Rank the following states in order of size of heavy oil deposits (largest to smallest):
a) California
b) Louisiana
c) Texas
d) Utah

Ranked from largest to smallest, heavy oil deposits are largest in this order:
a) California
b) Texas
c) Louisiana
d) Utah


















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