Steam Injection

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Overview

Steam injection is the most widely used EOR method today. In 2008 global EOR oil production climbed to 2 million barrels per day of which 1.2 million was attributable to steam injection. This process is therefore the most advanced EOR method as far as field experience is concerned. It has been highly successful in Canada, USA, Venezuela, Trinidad, Indonesia and other countries.

Reservoir Mechanics

The principal recovery mechanisms by which oil is recovered by steam injection are: viscosity reduction, steam distillation, gas stripping, thermal expansion, relative permeability and capillary pressure alteration, steam drive, gravity drainage, solution gas drive, oil-phase miscible (in situ solvent) drive, and emulsion drive. Successful steam injection projects are generally aided by a combination of these mechanisms.

Viscosity

 Firgure 1 Steam Injection Oil ViscosityThe most obvious effect of heating a reservoir is viscosity reduction. Figure 1 shows the viscosity of four oils at various temperatures. Two points are evident from this figure:

  1. The rate of viscosity reduction is highest at the initial temperature increases. Little viscosity benefit is gained after reaching a certain temperature.

  2. Greater viscosity reductions are experienced in the more viscous low gravity crudes than in higher API gravity crudes.

A lack of understanding of the process dynamics and poor reservoir characterization are largely to blame.

Steam Distillation and Solvent Drive

Figure 2 Steam Injection Relative Permeability

In the displacement of volatile oils by steam, lighter fractions of the oil may be vaporized. These fractions condense when contacting the colder formation, forming a solvent or miscible bank ahead of the steam zone. Very low residual oil saturations can result because of this distillation and miscible displacement.

Relative Permeability Alteration

Steam at high pressure and temperature can significantly affect relative permeabilities to oil, water and gas. Figure 2 shows oil / water relative permeability data for Boise Sandstone at two different temperatures (Weinbrandt and Ramey, 1972).

Generally, with an increase in temperature, relative permeability to oil increases, while that to water decreases. This is partly due to an increase in the irreducible water saturation and a reduction in the residual oil saturation.

Note:

  1. Reducing oil viscosity improves the mobility ratio and this enhances sweep efficiency.
  2. Several of the recovery mechanisms including steam distillation, solvent drive, and relative permeability alteration serve to reduce residual oil saturation and therefore  improve displacement efficiency.
  3. Depending on the oil composition, oil may swell by 10% to 20% during steam injection, and this supplies additional energyto expel the reservoir fluids.

Properties of Steam

Water has the highest specific heat and latent heat of vaporization of any common fluid. As such, it can carry a very large amount of heat per unit mass.

Figure 3 shows the variation of heat content of boiling water and dry saturated steam. The difference between the two curves represents the latent heat of vaporization. Latent heat is large at lower pressures and decreases to zero at the critical point of 705 oF and 3206 psia.

In the 100 to 1500 psia pressure range, where most thermal projects operate, steam carries considerably more heat than hot water.

The relation between steam temperature and latent heat of vaporization versus pressure results in several basic observations directly related to steam injection applicability:

  • The temperature at which water boils (steam temperature) increases with increase in pressure.
    • Since heat loss increases with temperature, steam injection applications at lower pressures will generally have lower heat losses (refer to section on Formation Heating Efficiency). This means that low permeability reservoirs and deeper higher pressured reservoirs, 
      both of which require higher injection pressures, will experience higher heat losses.
  • Latent heat of vaporization decreases with increase in pressure.
    • In heating the formation, steam first gives up its latent heat at a constant temperature before becoming 100% water and losing temperature. Therefore the higher the latent heat, the longer steam can remain at high temperature and heat the reservoir rock and fluids as it moves through the reservoir. Steam injection has been much more successful at low pressures partly because of the larger latent heat content.

Formation Heat Efficiency

The efficiency of formation heating by steam injection depends on the amount of heat lost from the surface equipment, the injection wellbore, and to adjacent formations as the steam is transported from the generator out into the reservoir.

These heat losses are a function of steam injection temperature, reservoir characteristics, and the equipment used. Surface and wellbore heat losses can be partially controlled but reservoir conditions cannot, and they are the most critical in determining project feasibility.

Surface Heat Losses

Surface heat loss starts at the generator, mostly due to flue gas, which typically leaves the stack at 400 oF (204 oC). This loss is about 20% of the net heat generated.

Heat losses from generator to injector depend on line type and length. Therefore generators should be close to injection wells. Line losses may be further minimized by insulation or burying. Typically, 3% to 5% of the heat may be lost in a well-designed steam line (IOCC, 1993).
 
Wellbore Heat Losses

Figure 4 Steam InjectionWellbore heat loss is a serious concern, particularly in deep wells or wells with low steam injection rates. Steam at the surface can easily be hot water when it reaches the sandface.

Figure 4 shows the effect of injection rate on downhole pressure, heat loss, and steam quality. At lower steam flow rates, the fraction of heat lost from the steam increases, resulting in higher liquid fractions (lower steam qualities) and consequently higher (hydrostatic related) pressures in the well.

It is useful to note that the rate at which a wellbore loses heat

  • decreases with  time (initially the rate is inversely proportional to the square root of time – Butler, 2004) as the ground around the well becomes heated, and
  • is less for a smaller diameter well than a larger one because of the smaller circumferential area for heat loss.

In addition to depth and injection rate, wellbore heat losses depend on the type of well completion, including size and type of casing. The casing-tubing annulus can be used as an insulator to maintain low casing temperatures by the use of thermal packers. In this case, the annulus may be vented to the atmosphere or filled with high pressure gas.

Formation Heat losses

Figure 5 Steam InjectionLittle control can be exerted over the largest source of heat loss, the producing formation itself, where heat is lost by conduction to the overlying and underlying rock.

This rate of heat loss

  • depends on the area present for heat flow and therefore increases with the growth of the steam zone in the reservoir
  • decreases with time at any fixed point from the injection well, as the surrounding formations become heated.

Figure 5 shows reservoir heat loss calculations. In these calculations, steam injection rate was held constant at 1,000 bbl/d (cold water equivalent, CWE), and only reservoir thickness was varied.

The percentage of injected heat lost to the surrounding rock

  • increases (directly) with time, i.e. becomes larger as the steam zone volume increases, and
  • varies inversely with (the square of) formation thickness. Steam injection into thin zones is likely to be uneconomical.

Steam Injection Process

Cyclic Steam Injection

Figure 7 Steam Injiection

Cyclic steam injection (or cyclic steam stimulation, CSS) is primarily a stimulation technique that, through viscosity reduction and wellbore cleanup effects, assists the reservoir energy in expelling oil. Oil recoveries are lower than that for continuous steam injection processes, typically 10% to 25%. It is usually implemented to preheat or condition the reservoir for a follow-up drive process.

Cyclic steam injection is a single-well process (employing either vertical or horizontal wells) that consists of injection of a predetermined steam volume, followed by a soak period to distribute the injected heat, and then a production period (refer to Figure 6).

Response to cyclic steam injection varies considerably with reservoir type. For thick steeply-dipping structures, gravity drainage is dominant and many cycles are possible as heated, less viscous oil continues to flow to the producer. Cases in excess of 20 cycles have been reported (Herbeck et al., 1978). For horizontal reservoirs, where the producing mechanism is solution gas drive, reservoir energy is quickly depleted, limiting the number of cycles.

Steam Injiection

A relatively recent improvement in CSS using horizontal wells is Shell Canada's "J-Well" (Brissenden, 2005), shown in Figure 7. This "J-well" design acts as a vertical separator that helps distribute steam to the end of the wellbore, prevents steam condensate from inhibiting injection, and should retain gas and steam better in the reservoir during the production cycle. The initial performance of the first J-wells at Shell's Peace River operations has reportedly been encouraging with higher oil-steam ratios than regular CSS wells and with more effective heat distribution observed on time-lapse seismic.

Continuous Steam Injection

Steam Injiection

Steam Flooding Steamflooding (or steam drive) is implemented on a pattern basis, similar to waterflooding. The steam moves out into the reservoir until it condenses, thereby heating the reservoir rock and fluids to steam temperature (see Figure 8).

The principle oil recovery mechanism is gas drive of the highly mobilized oil by the steam vapour. Downhole steam vapour volumes are large since one barrel of water generates 100 barrels of steam vapour at 200 psig and 75% quality. The oil viscosity is lowered by a factor of 1000 or more. Furthermore, condensing steam has a much higher effective viscosity than steam or hot water alone.

Typical steamflood recovery is 50% to 60% of the oil in place.

Steam-Assisted Gravity Drainage (SAGD) Figure 9 Steam Injiection

SAGD was developed to overcome the difficulties experienced with steamflooding bitumen reservoirs. Because bitumen (defined as being heavier than 10oAPI) is nearly immobile at reservoir temperature, steam cannot be injected at significant rates without fracturing the reservoir.

SAGD involves either (a) a pair of horizontal wells with one used as a steam injector overlying the other used as a producer (see Figure 9), or (b) vertical injection wells overlying a horizontal producer. In either case, heated oil drains from around growing steam chambers, driven by gravity to lower horizontal wells.

SAGD is best suited to bitumen and oils with low mobility, which is essential to the formation of a steam chamber. Target reservoirs also have to be sufficiently thick and have high vertical permeability for oil to drain to the producing well at economic rates. Optimal performance of SAGD requires that the steam chamber be kept well drained so that liquid does not accumulate over the producer, without producing steam vapour.

Special mention is given here to an innovative application of gravity drainage using steam to exploit Tangleflags, a problem reservoir.

Figure 10 Steam Injection

This reservoir (see Figure 10) is a 13m-thick sandstone located on the Alberta-Saskatchewan border. It contains viscous heavy oil, a gas cap and bottom water. Primary recovery was less than 1% due to severe water coning.

Vertical steam injectors completed near the gas cap were used to mobilize and drain oil down to horizontal producers completed near the bottom of the reservoir (Jespersen and Fontaine, 1993). A positive downward pressure gradient was effectively used to mitigate water coning.

Application

The following characteristics are beneficial to the application of steam injection:
  • Viscous oils of gravities between 10o and 20o API are most susceptible to viscosity reduction by heat. Note: In instances where steam distillation and solvent extraction can be important recovery mechanisms, volatile high gravity crudes may be considered for steam flooding.
  • Reservoir depth of less than 3000 ft minimizes heat losses. Also, latent heat is highest at low pressures; therefore more heat can be transported per barrel of steam injected into the shallow, low pressure reservoirs than into the deeper zones at high pressure.
  • Permeability of 500 md or more assists flow of viscous oils.
  • Oil content around 1200 bbl/acre-ft increases the chance of economic success.
  • Sand thicknesses of at least 30 ft to 50 ft are necessary to limit formation heat losses in continuous steam injection projects. Processes that rely on gravity drainage be implemented in at least 40 ft of continuous pay.

Apart from greater heating efficiency, low pressure (temperature) operation has other advantages (Das, 2005):

  • There is reduced silica dissolution and production in the water phase. This will reduce the load on the water treatment to meet boiler feed water quality.
  • H2S production goes down significantly with temperature. This has important implications regarding the design of the surface facilities for compliance with environmental regulations.

It is important to be aware, however, that lower reservoir pressures increase the challenges of lifting the oil to the surface. Oil production rates would also be lower because of the lower steam temperatures which lessen viscosity reduction.

Process Variations and Optimization

Steamflood Followed by Waterflood

As steamflood matures oil production rate declines, and the steam-oil ratio (SOR) eventually becomes uneconomically high. The high SOR generally indicates that a large amount of heat is retained in the reservoir and that some of this heat is cycled through the reservoir without affecting oil recovery.

The recent trend has been to convert a maturing steamflood to waterflood (Ault et al. 1985; Hong, 1987), which redistributes the heat in the reservoir, producing additional oil from zones that have been bypassed by the injected steam.

Water-Alternating-Steam

Water-Alternating-Steam injection has been used to delay or eliminate premature steam breakthrough and to improve sweep and recovery efficiencies.

The Russians used this method successfully in their heavy oil fields to improve oil production by 25%-30% annually from 1981-1984 (Hong, 1999). In several California applications water-alternating-steam eliminated steam breakthrough and improved recovery efficiencies.

Steam Injection Followed by Air Injection

Air injection as a follow-up process has the potential to recover significant additional oil after steam injection. BP Canada’s Wolf Lake “Pressure-Up Blowdown Combustion” process (Hallam and Donnelly, 1988) tested wet oxygen combustion after CSS in the Cold Lake bitumen reservoir. Total oil recovery factor was approximately double that of CSS alone and the steam-oil ratio was reduced from 6.1 m3/m3 to an equivalent of 2.3 m3/m3.

Hybrid Steam Processes

The use of co-injectants with steam, such natural gas, carbon dioxide, flue gas, solvents, etc. has received attention in the laboratory and several field trials. Depending on the choice of co-injectant, oil recovery may be improved through one or more of the following: enhanced viscosity reduction, a lowering of residual oil saturation, improved gas drive, reduced heat losses. Note that solvent-based processes alone for heavy oil recovery are generally slower than thermal processes.

These co-injectants have the potential to reduce the steam requirement, and increase oil production rates and recovery factor. Lower steam requirements (or steam-oil ratios) translates into lower capital investment, CO2 emission, and water and natural gas usage per barrel of oil recovered.

Expanding Solvent SAGD (ES-SAGD) is a variation of SAGD that involves injecting a combination of a low concentration light hydrocarbon and steam. This process takes advantage of the benefits from the heat provided by steam injection and the viscosity reduction through dilution offered by the solvent (Orr, 2009). This process has already been tested in the field, resulting in significant improvements in oil rate and steam-oil ratio. Long-term solvent returns on average are approximately 70%.

Imperial Oil’s LASER process employs steam-solvent cyclic steam stimulation (Leaute and Carey, 2005), using 6% volume fraction of C5+ condensate. Data from a field test at Cold Lake shows an incremental oil recovery of 10 m3 over regular CSS for every 1 m3 of unrecovered solvent.

Zhu et al. (2001) reported on a field test of simultaneous flue gas injection with steam in the Liaohe oil field in China. Following injection of the mixture the well was shut-in for 4 days to allow the gases to fully diffuse and penetrate the reservoir, and then turned around. The results indicate the following improvements over steam injection alone:

  • Higher downhole steam quality during injection
  • An overall reduction in steam-oil ratio of 30%.

Fracturing with Steam

Finally, there is substantial field data to show that cyclic steam stimulation can be used to commercially exploit bitumen reservoirs with no or very little injectivity to steam below fracture pressure. Provided there sufficient cap rock, no overlying gas cap or underlying aquifer, steam may be injected above reservoir fracture pressure to mobilize the bitumen around the well.

This process has other desirable features. In fresh-water sensitive formations, the fracture-heated pathways will extend some distance from the well, whereas otherwise swelling clays would inhibit well injectivity and productivity. The fracture-heated pathways may also make accessible geologically areally isolated pay volumes. In vertically heterogeneous reservoirs, vertically oriented fractures may provide more uniform heating through the pay.

Challenges

The challenges of steam injection EOR are economics and environmental.

Steam injection is usually applied in large fields where economics of scale apply. The upfront capital costs are considerable, involving expensive steam generation and production facilities and insulated flow lines.

Availability and cost of fuel for heating water or generating steam are important. For environmental reasons most steam generators are fired with natural gas which, historically, has represented a significant fraction of total operating costs.  Another economic issue relates to the discounted oil price (relative to West Texas Intermediate) received for heavy oil.

Environmental concerns present a considerable obstacle to steam injection operations. Some or all of the water will be supplied by municipalities, competing with quantities for human consumption. Clean air can be an issue with the combustion products of the steam generators.

Articles

References

Ault, J.W., Johnson, W.M., and, Kamilos, G.N.: “Conversion of Steamfloods to Low-Quality Steam and/or Hot-Water Injection Projects”, paper SPE 13604, presented at the SPE California Regional Meeting, Bakersfield, California, March 27-29, 1985. 

Brissenden, S. J.: “Steaming Uphill: Using J-Wells for CSS at Peace River”, Canadian International Petroleum Conference, Calgary, Alberta, Jun 7 - 9, 2005. 

Butler, R.M., Thermal Recovery of Oil and Bitumen, 4th Printing by GravDrain Inc, Calgary, Alberta, 2004.

Das, S.: “Improving the Performance of SAGD”, presented at the SPE/PS-CIM/CHOA International Thermal Operations and Heavy Oil Symposium, Calgary, Alberta, Canada Nov. 1-3, 2005.

Hallam, R.J. and Donnelly, J.K.: “Pressure-Up Blowdown Combustion: A Channelled Reservoir Recovery process”, presented at the 63rd Annual Technical Conference and Exhibition of the SPE, Houston, TX, Oct. 2-5, 1988.

Herbeck, E.F., Heintz, R.C. and Hastings, J.R.: “Fundamentals of Tertiary Oil Recovery: Part 8 - Thermal Recovery by Hot Fluid Injection”, Petroleum Engineer, August 1978, pp. 24-34.

Hong, K.C.:” Guidelines for Converting Steamflood to Waterflood”, SPE Reservoir Engineering, February, 1987, pp. 67-76.

Hong, K.C.: “Recent Advances in Steamflood Technology”, Paper 54078-MS presented at the International Thermal Operations/Heavy Oil Symposium, Bakersfield, California, March 17-19, 1999.

Improved Oil recovery, Interstate Oil Compact Commission, Oklahoma City, OK, 1993.

Jespersen, P.J. and Fontaine, T.J.C.: Tangleflags North Pilot: A Horizontal Well Steamflood”, J. Can. Petrol. Technol. (1993) Vol. 32, No. 5, pp. 52-57.

Leaute, R.P. and Carey, B.S.: “Liquid Addition to Steam for Enhancing Recovery (LASER) of Bitumen with CSS: Results from the First Pilot Cycle”, paper 2005-161 presented at the Petroleum Society’s 6th Canadian International Petroleum Conference (56th Annual Technical Meeting), Calgary, Alberta, June 7-9, 2005.

Orr, B.: “ES-SAGD; Past, Present and Future”, paper SPE-129518-STU, presented at the SPE International Student Papers Contest, SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, Oct. 4-7, 2009.

Thomas, S.: “Enhanced Oil Recovery – An Overview”, Oil and Gas Science and Technology (2008) Vol. 63, pp. 9-19.

Weinbrandt, R.M. and Ramey, H.J., Jr.: “The Effect of Temperature on Relative permeability of Consolidated Rocks”, SPE 4142, Annual Meeting, San Antonio, Oct. 8-11, 1972.

Zhu, C., Zhang, F., and Zhou, J.Z.Q.: “An EOR Application @ Liaohe Oil Field in China – Tests of Pumping Flue Gas into Oil Wells”, presented at the First National Conference on Carbon Sequestration, Washington D.C., May 15-17, 2001.