TECHNOLOGY Economics, new technology improve Danish offshore oil recovery

Aksel Mortensgaard
Danish Energy Agency
Copenhagen

Cost-efficient development concepts and technologies, such as horizontal wells and water injection, have almost tripled the expected ultimate oil recovery from Danish offshore fields.

All currently produced Danish oil and gas is from chalk reservoirs.

The Danish Energy Agency's strategies for research and development of improved recovery techniques is related to classifying Danish chalk fields into three different reservoir types according to flow characteristics and initial oil saturation.

Danish fields

In 1966, oil was discovered on the Danish continental shelf in the North Sea. First oil production was from the Dan field in 1972.

Production constitutes 126% of the total Danish oil and gas consumption. At the current production level, the Danish Energy Agency expects Danish oil reserves to last 20-25 years and gas reserves, 30-35 years.

The economic value of increased oil and gas recovery is immense. An additional 1% recovery of the oil-in-place in Danish chalk fields has a gross value of up to $2 billion, and corresponds to 1-2 years of production at the current oil consumption rate.

Oil production

All Danish oil and gas fields are in the North Sea about 200 km (125 miles) west of the Danish coast.

Dansk Undergrunds Consortium, DUC, is the licensee for all these fields and Maersk Oil & Gas AS is the operator.

The Danish fields (Fig. 1a)[18000 bytes] are grouped around three processing centers: Dan, Gorm, and Tyra. Nine oil fields and two gas field are producing. Eight of these fields are satellite developments.

The fields produce from domal chalk structures in the southern part of the Central Graben. The chalk is mainly built up from planktonic haptophycean algae debris known as coccolithophorids. The most common reservoir chalk constituents are coccolith fragments or aggregates of coccolith platelets.

All production is from chalk sediments buried to a depth of 2,000-3,000 m, with medium-to-high, 20-45%, porosity and low, less than 10 md, formation matrix permeability. Overpressures, coupled with oil migration and reworking of the chalk have resulted in porosities much higher than expected in normal pelagic chalk sediment buried at such depths.

Initial oil saturation is often almost 100%. Some fields however, or parts of a field, have less than 50-60% initial oil saturation.

Fractures are an important part of the chalk fields, providing significantly higher permeabilities than the indicated matrix permeability. Knowledge of fracture density, fracture orientation, and fracture permeability is important for recovering oil and gas.

Most formations have preferentially stronger capillary affinity to water than to oil.

The Danish oil accumulations are classified according to the ease of recovering the oil-in-place. The decisive parameters are the ability for oil to flow through the chalk formation (permeability) and the initial oil saturation.

Of the three reservoir classifications (Fig. 1b)[18000 bytes], Type 1 is relatively easy to develop with today's technology. In Type 2, production is difficult with available technology and in Type 3, development of production is extremely difficult.

(Fig. 1c)[18000 bytes] shows the Danish Energy Agency's estimate of the oil-in-place and the expected recovery factor within each reservoir type.

Producing Type 1 oil fields are the less naturally fractured Dan, the moderately fractured Gorm, and the heavily fractured Skjold and Rolf fields. These fields contain 35% of Denmark's estimated oil-in-place and the expected recovery factors are high, an average 31%.

About 82% of Denmark's current production comes from Type 1 fields.

Type 2 reservoirs often have the same flow characteristics as Type 1; however, initial oil saturations are typically much lower. Producing Type 2 reservoirs are the less naturally fractured Kraka, and the very fractured Dagmar and Regnar fields. These fields have recovery factors of less than 10%. The Tyra oil zone (Fig. 1b)[18000 bytes], is a thin oil zone below a major gas accumulation.

Currently, Type 2 reservoirs produce only about 16% of Denmark's oil.

Type 3 reservoirs contain almost 45% of the total estimated oil in Danish chalk. But these reservoirs have extremely low formation permeability.

The Valdemar field is a producing Type 3 reservoir. Expected recovery factors are low, in the order of only a few percent.

Type 3 reservoirs produce only about 2% of Denmark's oil.

Type 1 reservoirs

Type 1 reservoirs have good production characteristics such as good flow properties and a high oil saturation.

Reservoirs are characterized by initial oil saturations generally from 50-60% to 100%, and a matrix permeability between 0.5 and 5 md. The natural fracture permeability is from 3 md in the less fractured reservoirs, the fields on the left in (Fig. 1b)[18000 bytes], progressing up to 10,000 md for the heavily fractured reservoirs, the fields on the right in (Fig. 1b)[18000 bytes].

The reservoir rock consists of chalk, mostly of lower Paleocene Danien and upper Cretaceous Maastrichtian age. Generally the chalk is relatively clean except for some argillaceous streaks and lamina predominantly in the lowest part of the Danien.

Recovery factors

For the past 10 years, the estimated oil-in-place in producing Type 1 reservoirs has remained about the same. But Figs. 2a and b[12000 bytes] indicate that both the expected recovery factor and producing rate from Type 1 reservoirs have had pronounced increases (a factor of three) over the last 10-15 years.

Expected ultimate recovery is now 30%, up from about 10%, and the 140,000 b/d oil production rate is up from 40,000 bo/d.

Significant reasons for an increased recovery factor are:

• Improved knowledge of chalk geology and rock properties

• Improved oil recovery methods in chalk

• Simultaneous oil production with water injection (because the reservoir chalk is water wet)

• Development of horizontal well technology and improved completion techniques

• Evolution to more economical field development solutions with regards to the processing and transportation of oil

• Greater efficiency in operating costs.

Water injection

Field development and production experience, together with research, has led to a better understanding of chalk geology and knowledge of rock properties. From this, the petrophysical properties of reservoir rocks as well as the fluid flow and displacement mechanisms in chalk have been more accurately characterized.

Also the structural development as well as the mechanical properties of the rocks are now better understood.

An improved knowledge of oil recovery mechanisms has resulted in changing production from natural depletion drive to simultaneous water injection.

In the water-wet reservoir chalk the expected recovery factor is now estimated to be above the 15-20% traditionally expected from natural depletion drive. The more naturally fractured the reservoir is, the more important it is for the chalk to be water wet to improve recovery.

All fields, until 1986, were naturally depleted except for Gorm where natural gas was reinjected for conservation purposes.

In 1986, the first water injection pilot test started. At that time, it was not clear whether the injected water would increase oil recovery. The fear was that the water would just flow through the reservoir fractures without displacing the oil in the matrix.

Production experience and wettability tests on cored chalk have proven that the chalk in Type 1 reservoirs is strongly water wet and the oil is efficiently displaced by water.

In the last 2-3 years, drilling into water flooded reservoir sections showed residual oil saturation as low as 20-30%.

Now, about 10 years after the start of injection, production is approaching 100% reservoir voidage (Fig. 2c)[12000 bytes]. The fields are expected to reach a watercut of up to 85% by 2010.

Horizontal wells

Maersk, in cooperation with relevant service companies, has instituted horizontal well technology and stimulation techniques.

Maersk had evaluated draining chalk reservoirs with horizontal wells as early as 1978. However, horizontal drilling was only found to be promising after 1985 when fracturing a horizontal drain hole at regular intervals along the well bore became possible.

Production shows that hydraulic fractures had to be sand propped to prevent closure. Further, to improve the productivity at low cost the 7-in. PSI (perforate, stimulate, and isolate) system was developed. This system allows operational flexibility at low cost. Perforated intervals could be opened and closed individually.

Several drainage points along a horizontal lateral, with each drainhole controlled individually, has increased oil production rates and improved oil recovery. The lower the permeability, the greater the improvement in production and recovery.

(Fig. 2b)[12000 bytes] shows the production from vertical and horizontal wells in Type 1 reservoirs. Today, production from a lesser number of horizontal wells far exceeds the production from vertical wells.

Cost and oil production per well are shown, respectively, in Figs 3a [8000] and 4a [12000]. Each point shown is an average for the wells drilled and completed in each year. It is evident from these figures that the average costs per well for horizontal wells rose relatively less than the average oil production per well.

Still further development of horizontal drilling and well technology continues to lower well costs and improve production. Fixed prices, 1995 level, are shown. Not included are costs of surface equipment such as well slots.

Production during the first 1-3 years of a well is used to predict cumulative oil production over a period of about 10-20 years. Because it takes at least 1 year of production to choose a meaningful plateau rate for a well, only data to the end of 1994 are used.

Fig. 4b [12000] shows the average drilling rate for each year based on measured depth divided by the days to drill. The average drilling rate for the first horizontal wells was half that of vertical wells.

The rate was low because of difficulties in maintaining a horizontal trajectory through the chalk layers of the reservoir. But today, well technology allows the horizontal sections to be drilled just as quickly as the vertical sections. Both measurement while drilling and paleontology guide the bit to the target zone.

It is evident from Fig. 3b [8000] that while the vertical wells typically are completed over a single zone, the latest horizontal wells are individually completed over several zones, up to 18 in number.

Inflow of oil into the individual completion or perforated interval (Fig. 3b) [8000] in horizontal wells is half of that of vertical wells. The number of completions per well typically lead, however, to a greater total production from a horizontal well.

The price index (Fig. 3d) [8000] shows that the development of horizontal drilling, completion, and stimulation techniques has reduced the price per produced barrel of oil. Costs in the index include well drilling and completion but not the cost of surface installations such as well slots.

Costs of a horizontal well in 1995 have been reduced to about 20% of the costs for a vertical well in 1972. In the future, new technology is also expected to continue to reduce drilling and completing costs for both vertical and horizontal wells.

Future development of horizontal well technology for improving oil recovery will be more significant for reservoirs with poorer oil flow characteristics.

Costs

Fig. 5a shows the capital (Capex) and operating (Opex) cost trends. Capex includes all fixed installations and pipelines between the fields. Investments are in terms of 1995 prices.

Since the early 1980s, Opex has remained at the same level despite a pronounced increase in oil production and the number of producing wells.

Fig. 5b [10000] shows that in the Dan field, Capex per unit of produced oil is now about one-third of that of the late 1980s. This is mainly due to horizontal wells.

Fig. 5b [10000] also shows that investment per produced unit of oil has remained at the same level from the initial field developments of the naturally fractured reservoirs of Gorm, Skjold, and Rolf fields.

The production during the first 1-3 years is used to project the cumulative oil production over a period of 10-20 years from a field development or a field extension.

Total Capex per produced unit of oil is the same for all fields with Type 1 reservoirs. Today, it is not the reservoir parameters that are considered decisive to the economics of these fields.

Horizontal wells, existing installations for processing and transportation, and more cost-efficient field development have resulted in the reservoirs being considered equally economically attractive for oil recovery despite dissimilar reservoirs.

Type 2 reservoirs

Type 2 reservoirs have a limited production and field development experience. These reservoirs pose more difficult and riskier conditions for oil production. The flow properties are often the same as in Type 1 reservoirs but initial oil saturations do not exceed 50-60%.

Type 2 reservoirs, in addition to the three producing fields Kraka, Dagmar, and Regnar, exist also as inter-field accumulations, transition zones of Type 1 producing fields, and as thin oil zones located under gas fields such as the Tyra oil zone.

Low oil saturations may have occurred because of limited oil migration into the reservoir, leakage from the reservoir through the cap rock, or displacement of part of the oil by water flowing from the aquifer. Poor porosity development will also cause poor oil saturation.

The chalk in Type 2 reservoirs sometimes reacts as weakly water wet to oil wet.

This means that imbibition occurs at best very poorly and the relative permeability for oil is poor relative to water.

Oil production from non-naturally fractured reservoirs is often accompanied almost from the start by a high watercut. Oil is initially produced from the naturally fractured reservoirs with relatively high oil rates and no watercut. The watercut drastically increases after the oil in the fractures has been produced.

Expected recovery for these naturally fractured reservoirs is very low, in the range of a few per cent of oil-in-place.

Field development within Type 2 reservoirs has only started in the last 5-10 years. Generally during this period, the expected recovery factor has remained constant at about 5-10% (Fig. 6) [12000].

Until now, all recovery from these fields has been with natural reservoir energy without gas or water injection.

The same technological development as mentioned for Type 1 reservoirs is the main reason that production has been initiated.

Horizontal wells with many separate completions over large lateral distances have typically been required to obtain commercial production in less naturally fractured reservoirs. Horizontal wells have also been drilled in thin oil zones, such as under a gas cap, and for tapping oil on the flanks, such as in the transition zones of the structures.

Reducing economic risk with satellite field development to an established platform center has been a condition for exploiting Type 2 reservoirs.

More cost-efficient development concepts have further been a basis for expansion of production from these reservoirs. The development of the Danish Star-A platform concept has significantly reduced field development costs and thus the economic risks. Multiphase flow pipelines have also contributed to reduced costs.

Phased field development has minimized economic risk.

Type 3 reservoirs

Hydrocarbons have been encountered in several wells drilled in the Sola and Tuxen formation of Albian/Aptian and Barremian age, and the potential for recovery of the hydrocarbons in these sedimentary units is immense by Danish standards.

Oil saturation is generally moderate except in some cases with almost 100% oil saturation. The reservoirs consist of very tight chalk, 0.1-0.5 md, that makes oil recovery very difficult.

The formations consist of limestone interbedded with clay and with porosities of up to 35% in the cleaner sections.

In some areas, natural fractures improve productivity.

Discoveries of this type of reservoir have been made in other countries, but the Danish Valdemar field is the first where commercial production of oil has been developed.

Production started in 1993 from an unmanned platform that is a satellite to Tyra.

First production was encouraging. In 1994, total oil and condensate production was 300,000 cu m (1.9 million bbl). The field has three horizontal producing wells; however, the expected recovery factor from the Valdemar field is a low 4%.

Future strategy

Research and development in improved oil recovery has been initiated and funded by the state; however, it is not possible to quantify the benefit of these activities with respect to increased recovery of oil. This research is considered to be necessary to supplement the research and development by the oil companies.

During the past 15 years, the most significant research programs with Danish state participation have been the state-financed Energy Research Program "EFP" (Energi Forsknings Programme), governmental funds of $2-3 million/year, and the joint Norwegian-Danish chalk research co-operation "Joint Chalk Research (JCR), Phase 1-4," with an annual budget of $1 million.

The EFP research plans to obtain long-term results or to achieve results within areas where oil companies do not find research very attractive.

An association of various oil companies finances the JCR. The authorities in Norway and Denmark have initiated the JCR and the ongoing function of the authorities is to arrange cooperation between the participating companies.

Based on each company's needs, the research program has been a success, and sharing information has shown to be inexpensive compared to research by an individual company.

Past research has focused on increased oil recovery from fields within Type 1 reservoirs.

The principle future strategy is to channel research funds into increasing recovery from Types 2 and 3 reservoirs, which oil companies today look on as economically less attractive.

In the near future, the Danish Energy Agency hopes to launch a new research program focused on increasing the recovery factor from accumulations within Type 3 reservoirs. The Danish Energy Agency intends that this research program should progress by cooperation between relevant research institutes and the operator of the Valdemar field, Maersk.

The Danish Energy Agency plans that future research and development directed towards Type 1 and 2 reservoirs should have the target of recovering oil down to a 20-30% residual oil saturation.

The future plans for Type 3 reservoirs are merely to further develop commercial production from extremely low-permeability chalk.

To achieve the target set for Type 1 reservoirs, a primary requirement is the further development of commercial methods that allow the greatest portion of the reservoirs to be subjected to flooding. Also, better methods to evaluate the effectiveness of water displacement have to be developed.

For Type 2 reservoirs, the methods under development are intended to allow for easier release of oil from the formation, together with reducing water production.

For Type 3 reservoirs, the goal is to develop methods to release the oil more easily from the tight chalk, together with methods to improve oil flow in the reservoirs.

Finally, research should also develop ways to improve well productivity.

In addition, the role of the Danish Energy Agency is to arrange cooperation among research institutes, oil companies, service companies, consultants, and energy authorities. Scientific knowledge, engineering, and improved oil recovery technology has to be optimized and disseminated.

The industry will probably continue to develop and optimize horizontal drilling and completion techniques. More cost-efficient development concepts probably also will be developed. But in addition to this, it is still important that all parties involved with oil production continue to develop better geological models of chalk and obtain better ways to determine rock properties of chalk.

Acknowledgment

The author is grateful for the contributions and technical review provided by Rolf Kalles and Henrik Bendixen in the Danish Energy Agency. The author also thanks Thamer H. Al-Ansary for assisting in processing the well and production data.

Bibliography

1. Gregory, A.T., "DTI's Improved Oil Recovery Strategy," Trans IChemE, Vol. 72, Part A, March 1994.

2. The Norwegian Petroleum Directorate, "Improved Oil Recovery-Norwegian Continental Shelf," November 1993.

The Author