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Emerging applications in cryogenics--Nitrogen injection for reservoir Enhanced Oil Recovery.

INTRODUCTION

While the petroleum demand is continuously increasing day by day, petroleum production worldwide is in a steady state. Due to various emerging technological developments, it can be expected that substantial portion of otherwise neglected oil can be recovered. The life of an oil well goes through three distinct phases (primary, secondary and tertiary recovery) where various techniques are employed to maintain crude oil production at maximum levels. Techniques employed at the third phase are commonly known as Enhanced Oil Recovery (EOR) and they can substantially improve extraction efficiency. In the recovery of oil from reservoirs, it is usually possible to recover only minor portions of the original oil by the primary recovery methods which utilize the natural forces present in the reservoir and the major parts, nearly 2.0 x [10.sup.12] barrels of conventional oil and 5.0 x [10.sup.12] barrels of heavy oils remain in reservoirs worldwide after conventional recovery methods have been exhausted (Thomas 2008).

Much of these oils would be recovered by various EOR methods which involve the injection of a fluid, or series of fluids, into the reservoir through an injection system. Over the years, interest in EOR has been growing due to the increase in oil reserves. Although large volumes of oil remain in the mature reservoirs, the oil production in large quantities by EOR processes will not be possible unless these processes can compete economically with the cost of oil production from conventional sources. So it is important to find economically suitable EOR methods for oil production from the reservoir. Thermal, Chemical and Gas injection are three major EOR methods developed during the last years (Moritis 2004). Natural gas (lean or rich) has been used successfully for many years as a primary choice of the operators for gas injection (miscible or immiscible). The limited availability and increasing value of natural gas has made its use for conventional cycling economically unattractive, especially in offshore environments where initial capital investment is large. Therefore, the use of less expensive substitutes, such as inert nitrogen, has been suggested (Donohoe and Buchanan 1981). Nitrogen was selected as a substitute makeup gas on the primary basis of pioneer work reported by Koch and Hutchinson on miscible displacement of reservoir oil using flue gas (Koch and Hutchinson 1958). They correctly concluded that flue gas (88% [N.sub.2]) could be substituted for hydrocarbon gas without sacrificing miscibility. Moreover, nitrogen provides a higher reservoir displacement volume per standard volume of nitrogen than any other gas injectant; that is, it provides the lowest volume requirement for pressure maintenance. In addition, nitrogen is also non corrosive. Therefore, no special metallurgy is required for the injection equipment. A cryogenic (air liquefaction and distillation) process can produce 99.999% pure nitrogen. Non-cryogenic processes employ membranes or adsorbents (PSA/VPSA) to remove the unwanted components of air. They produce nitrogen which is typically 95 to 99.5% oxygen-free (pure). Non-cryogenic plants are less energy efficient than cryogenic plants (for comparable product purity) but may cost less to build, in particular when the required production rate is relatively small. Non-cryogenic plants are relatively quick and easy to start up, which is useful when product is not needed full time. At high production rates, cryogenic processes are the most cost-effective choice. Cryogenic processes can produce very pure end products; and must be used to produce liquid nitrogen, oxygen and argon. Using either process, nitrogen can be generated at almost any location. Specific guideline on the required purity of [N.sub.2] for injection in the reservoir is unavailable in literature.

Depending upon the pressure, quantities, and location, nitrogen may cost one-quarter to one-half the price of natural gas (Clancy et al. 1980). Here, this cost range of nitrogen mentioned above is the nitrogen generation cost (Cryogenic air separation or inert gas generation) compared to the natural gas price depending on pressure, quantities, and location. Because of the increasing cost of natural gas, nitrogen injection is becoming more popular and attractive. For example, in 1983, over 500 million cubic feet per day of nitrogen was being injected into thirty oil or gas reservoirs (Clancy et al. 1985). In 1985, this number becomes 600 million cubic feet per day (Clancy et al. 1985) and by 1990 this number grew to 800 million cubic feet per day in over forty oil and gas reservoirs. Produced cryogenically from air with an established and proven technology, nitrogen can be made available for continuous trouble free injection in vast quantities at any location. Bath et al. (1980) first highlighted the scope for EOR in the North Sea. One of the more promising processes identified was nitrogen injection, which could be considered as either a secondary process to replace the water flood in certain parts of the fields or as a tertiary process to recover water flood residual oil. The drawbacks of nitrogen injection are that the produced hydrocarbons sooner or later become contaminated with nitrogen, which then require additional separation facilities. This technical problem can be solved easily with some extra cost. Then, the plants should have the additional separation facilities in order to separate the hydrocarbons contaminated with nitrogen. So, the investors have to pay extra cost for this additional separator in the plant and this cost will depend on the available technology, existing separator and plant size.

In fact, Nitrogen injection into subsurface reservoirs does not present any major problems. It is being applied successfully in an increasing number of EOR projects (Ahmed et al. 1983, Peterson 1978, Koch and Hutchinson 1958). Also the condensate gas displacement by nitrogen in the reservoir is a simple process that has proved to be very efficient (Moses and Wilson 1981). Hence the feasibility of nitrogen injection as a substitute for gas cycling is mainly an economic problem.

EOR METHODS

Many EOR methods have been used in the past, with varying degrees of success, for the recovery of light and heavy oils. Figure 1 shows the classification of these methods (Sarma 1999). As it is shown, EOR is divided into two major types: thermal and non-thermal. Thermal methods supply heat to the reservoir, and vaporize some of the oil. The major mechanisms involve a large reduction in viscosity, and hence mobility ratio. They are best suited for heavy oils and tar sands. Non-thermal methods (Selby et al. 1989) are best suited for light oils. In few cases, they are applicable to moderately viscous oils, which are not suitable for thermal methods. Lowering the interfacial tension and improving the mobility ratio are two major objectives in non-thermal methods. In non-thermal EOR, there are two types of gas injection, miscible gas injection and immiscible gas injection. In miscible gas injection, the gas is injected at or above minimum miscibility pressure (MMP). Various gases (i.e.[CO.sub.2] gas) and inert gas (i.e.[N.sup.2] gas) are commonly employed to establish oil displacement by conditional miscibility. For example, M.D. Rushing et al. (1977) describes a miscible oil displacement process involving the injection of high pressure nitrogen. They stated that pure nitrogen is injected into the reservoir and functions to initially strip relatively low molecular weight hydrocarbons from the reservoir oil. As the light hydrocarbons are absorbed, a two-phase equilibrium point is established between the reservoir oil and nitrogen at a location near the injection well. The liquid phase is composed initially of significant quantities of light and heavy residual hydrocarbons, whereas the gas phase is comprised primarily of nitrogen and light hydrocarbons. Since the gas phase has a higher mobility within the reservoir, it moves ahead of the liquid phase to contact additional reservoir. As nitrogen injection continues, the liquid phase is contacted with additional nitrogen with an attendant decrease in the concentration of light hydrocarbons in the liquid phase until ultimately the liquid phase is reduced to the heavy residual hydrocarbons. On the other hand, in immiscible gas injection, flooding by the gas is injected below MMP. This low pressure injection of gas is used to maintain reservoir pressure to prevent production cut-off and thereby increase the rate for production oil.

[FIGURE 1 OMITTED]

In the past, most of the EOR projects were active in the USA and the bulk of the production came from that country. Figure 2 shows the EOR production trends over the last 20 years (Thomas 2008) in USA. The total EOR production in USA is declining (Moritis 2006). In the figure it is shown that the majority of the EOR production was done by thermal method which is also on decline. Production from EOR method using gas injection is increasing. Production from the Chemical methods is non-existent at present. So, Gas injection plays a significant role on EOR at present and will continue to have an important place in oil production in future.

[FIGURE 2 OMITTED]

Nitrogen as Gas Injectant

Nitrogen has been used successfully for more than 20 years in pressure maintenance and has now gained prominence over the last decades as the injectant choice for enhanced oil recovery. Nitrogen is using as a driving force for costly and limited carbon dioxide, and in some cases for miscible displacement. Nitrogen can be produced at any reservoir using proven cryogenic, non-cryogenic technology and various energy sources. Nitrogen provides the lowest volume requirement for pressure maintenance. The injected nitrogen does not react with the reservoir fluids to produce undesirable by-products and precipitates. It should be mention here that carbon dioxide gas used as injectant breaks through in the oil and appears in the associated gas and thus increase the volume of the produced gas that must be treated to remove the [CO.sub.2] prior to sales. Nitrogen gas generated from compressed air is readily available, extremely dry, non corrosive and environmentally safe. It is an inert gas and therefore, does not combine with hydrocarbons to form sludge or emulsions down hole. Nitrogen injection has proven its effectiveness in reducing the natural decline of aging reservoirs, thus maintain production capacity for both oil and natural gas. Nitrogen is a non reactive and nonflammable gas, which makes up more than 78 percent of the air. The costs and limitations of the natural gas and [CO.sub.2] have made nitrogen an economic alternative for reservoir oil recovery by miscible gas displacement. The production of nitrogen by the cryogenic separation of the components of air has been in use since the early part of this century and is the most economical method of producing pure nitrogen (Peterson 1978).

COMPARISON OF NITROGEN WITH OTHER GAS INJECTANTS

Natural gas, [CO.sub.2] and [N.sub.2] are three candidate injectants considered for comparison. Disregarding economics and availability, hydrocarbon gas is the best choice for most gas injection plants for EOR. In practical case, miscibility can be attained by gas injection (rich or LPG) to establish the miscible bank. High recoveries have been noticed for pressure maintenance, immiscible displacement and miscible displacement projects where hydrocarbon gas has injected. The produced gas would require less treatment than the other gases ([CO.sub.2] and [N.sub.2]). A corrosion problem is minimal for projects using natural gas injection. The long term dedicated supply of natural gas (long term reliability) may be questionable and in addition, supplemental gas supply requires pipelining from field to the project for EOR. The increasing natural gas price is one of the major factors that limit its use in EOR.

Large reserves of naturally occurring [CO.sub.2], fossil-fueled power plants, coal-fired power plants etc. are the potential sources of [CO.sub.2]. Except for on-site generated [CO.sub.2] gas, dedicated pipelines are needed to transport the gas from source to the oil field. The major factors limiting [CO.sub.2] injection as an oil recovery process are the availability of [CO.sub.2] and the cost to build pipelines to carry [CO.sub.2] into oil producing regions. Advantages of carbon dioxide flooding are: Miscibility can be attained at low pressures; displacement efficiency is high in miscible cases, useful over a wider range of crude oils than hydrocarbon injection methods and miscibility can be regenerated if lost. Disadvantages of using [CO.sub.2] are: availability of carbon dioxide resources, transportation costs, under certain conditions poor sweep and gravity segregation and corrosion.

Among the three candidate gases under consideration, nitrogen is the most available and cheapest universal gas as it is produced from air. Since cryogenic air separation plants are constructed at or near the field, no pipelines are required. Nitrogen from air separation is inert and so no incremental costs are required for corrosion control. Also, the minimum miscibility pressure of carbon dioxide is lower than nitrogen. For this reason, reservoirs with light oils at elevated pressures are recommended for miscible displacement by nitrogen. Because of the inert and non-corrosive nature of nitrogen, on-stream availability for these plants range from 98 to 99 percent including down time for scheduled preventative maintenance. This makes nitrogen a very reliable source as a pressure maintenance injection gas.

CASE HISTORIES OF NITROGEN APPLICATION

Table 1 presents a list of the oil fields by (Clancy et al. 1985) using nitrogen for the Enhanced Oil Recovery projects at its earlier stage. It shows that many oil fields are interested in using nitrogen for the Enhanced Oil Recovery. With only a few exceptions (i.e. attic oil recovery projects), these projects are field wide. From Table 1 the following conclusion using nitrogen for the EOR projects can be noted as:
Table 1. Fields Receiving Nitrogen for Enhanced Oil Recovery (Clancy et
al. 1985)

Field                 Operator  Start  Injection  Pressure  [N.sub.2] *
                                Year   (MMscf/D)    (psi)     Source

Block 31                ARCO    1966       54      4,250      inert **

Ventura                 Mobil   1973       17      5,500      inert **

Calliou Island         Texaco   1974   1 [double   4,000     [N.sub.2]
                                        dagger]   [double
                                                  dagger]

Yates                 Marathon  1976       20       700       Inert/
                                                             [N.sub.2]

East Binger           Phillips  1977       24      4,500      inert **

Fordoche                Sun     1977       10      8,300     [N.sub.2]

Hawkins                Exxon    1977      120      1,700      inert **

Iberia                 Texaco   1977   2 [double   4,000      inert **
                                        dagger]   [double
                                                  dagger]

Bay St. Elaine         Texaco   1977   4 [double   4,000      inert **
                                        dagger]   [double
                                                  dagger]

Venice                  Getty   1978   4 [double   4,000     [N.sub.2]
                                        dagger]   [double
                                                  dagger]

Levelland [dagger]      Amoco   1979       12      3,000     [N.sub.2]

Lake Barre             Texaco   1979   4 [double   4,000     [N.sub.2]
                                        dagger]   [double
                                                  dagger]

Hackberry East          Amoco   1979   4 [double   4,000      inert **
                                        dagger]   [double
                                                  dagger]

Lake Pelto             Texaco   1979   4 [double   4,000     [N.sub.2]
                                        dagger]   [double
                                                  dagger]

West Hackberry          Amoco   1979   2 [double   4,000      inert **
                                        dagger]   [double
                                                  dagger]

Leeville               Texaco   1979   4 [double   4,000     [N.sub.2]
                                        dagger]   [double
                                                  dagger]

Painter               Chevron   1980       94      4,800     [N.sub.2]

East Vealmoor           Getty   1981        3      3,500     [N.sub.2]

Williisden Green        Dome    1981       30      4,300     [N.sub.2]

Paradis                Texaco   1981        4      4,000     [N.sub.2]

Two Freds               HNG     1981        6      1,900      inert **

Stone Bluff             Gulf    1981        1       100      [N.sub.2]

Ryckman Creek           Amoco   1981       12      3,000     [N.sub.2]

North Headlee           Mobil   1982        3      5,000     [N.sub.2]

Blackjack Creek         Exxon   1982        7      7,600     [N.sub.2]

Jay                     Exxon   1982       65      7,600     [N.sub.2]

Anschutz                Amoco   1982       50      6,200     [N.sub.2]

Andector-Ellenberger  Phillips  1982        2      2,000     [N.sub.2]

Lisbon                  Union   1982        6      3,000     [N.sub.2]

E. Painter            Chevron   1984       15       5000     [N.sub.2]

Chunchulla              Union   1984       18       5000     [N.sub.2]

Sho-Vel-Tum              Q.     1984        2       2000     [N.sub.2]
                       Little

Fanny Church            Exxon   1985        4       4000     [N.sub.2]

Field                 Operator  Start  Classification
                                Year

Block 31                ARCO    1966   [CO.sub.2]-LPG
                                          miscible

Ventura                 Mobil   1973     Immiscible

Calliou Island         Texaco   1974       Gravity

Yates                 Marathon  1976      Pressure
                                         maintenance

East Binger           Phillips  1977      Miscible
                                        displacement

Fordoche                Sun     1977   [CO.sub.2]-LPG
                                          miscible

Hawkins                 Exxon   1977       Gravity

Iberia                 Texaco   1977       Gravity

Bay St. Elaine         Texaco   1977       Gravity

Venice                  Getty   1978       Gravity

Levelland [dagger]      Amoco   1979   [CO.sub.2]-LPG
                                          miscible

Lake Barre             Texaco   1979       Gravity

Hackberry East          Amoco   1979       Gravity

Lake Pelto             Texaco   1979       Gravity

West Hackberry          Amoco   1979       Gravity

Leeville               Texaco   1979       Gravity

Painter               Chevron   1980      Miscible
                                        displacement

East Vealmoor           Getty   1981      Miscible
                                        displacement

Williisden Green        Dome    1981   [CO.sub.2]-LPG
                                          miscible

Paradis                Texaco   1981   [CO.sub.2]-LPG
                                          miscible

Two Freds               HNG     1981   [CO.sub.2]-LPG
                                          miscible

Stone Bluff             Gulf    1981     Immiscible

Ryckman Creek           Amoco   1981     Immiscible

North Headlee           Mobil   1982      Miscible
                                        displacement

Blackjack Creek         Exxon   1982      Miscible
                                        displacement

Jay                     Exxon   1982      Miscible
                                        displacement

Anschutz                Amoco   1982      Pressure
                                         maintenance

Andector-Ellenberger  Phillips  1982     Immiscible

Lisbon                  Union   1982     Immiscible

E. Painter            Chevron   1984      Pressure
                                         maintenance

Chunchulla              Union   1984      Pressure
                                         maintenance

Sho-Vel-Tum              Q.     1984     Immiscible
                       Little

Fanny Church            Exxon   1985      Miscible
                                        displacement

* N2 = Air separator (cryogenic separation) N2.

** Insert = N2 from inert gas generator (non-cryogenic).

[dagger] The plant located at Levelland provides nitrogen to Slaughter
Estate Unit and Levelland field.

[double dagger] Estimated.


1. Nitrogen application for the EOR was first introduced in the 1970's.

2. From 1970-1977, almost all of the nitrogen for the EOR projects was taken from onsite inert gas plants.

3. After 1980, nitrogen for the most of the EOR projects was supplied by on-site air separation plants.

4. Pressure for the nitrogen injection ranges from 100 psi [690 kPa] to 8300 psi [57227 kPa].

5. Nearly 600 million cu ft [14x[10.sup.6]] of nitrogen were injected daily into the oil fields.

Clancy et al. (1985) have done detail analysis of Nitrogen injection projects to develop screening guides and offshore design criteria. For the most part, EOR was limited to onshore fields. As the EOR processes develops and as our offshore fields mature, operators are trying to use the EOR processes offshore. In offshore, platform space and supply cost of injectant gas is an important factor to the operator to select EOR options. For example, natural gas or [CO.sub.2] gas injections are not economically viable due to huge cost for pipe lining from the source to the oil field. Also, on-site generated gas is not technically proven. A report (Cobb et al.1982) indicates that many of the potential [CO.sub.2] miscible projects would be in areas far distant from the major [CO.sub.2] sources. Nitrogen injection, however, may not be technically and economically constrained as other EOR options.

Nitrogen has been used for Enhanced Oil Recovery (EOR) in the offshore Cantarell Oilfield in the Gulf of Mexico since 2000. Cantarell Field is the largest oil field in Mexico and one of the largest in the world. It is the PEMEX's heavy oilfield, located in the Bay of Campeche and has had high productivity due to the presence of a gigantic natural gas cap. The gas cap pressure has fallen due to the extraction of the hydrocarbon from the field, and since year 2000 nitrogen has been injected to maintain reservoir pressure and for Enhanced Oil Recovery. The nitrogen injection increased the production rate from 1 million barrel/d (160,000 [m.sup.3]/d) to 1.6 million barrel/d (250,000 [m.sup.3]/d) in 2000, to 1.9 million barrel/d (300,000 [m.sup.3]/d) in 2002 and to 2.1 million barrel/d (330,000 [m.sup.3]/d) of output in 2003, which ranks Cantarell the second fastest producing oil field in the world behind Ghawar Field in Saudi Arabia (Tom 2006). The nitrogen injection to the reservoir has led to breakthroughs in the associated gas production and increased nitrogen content in sales gas.

FACTORS AFFECTING THE COST OF NITROGEN

Donohoe et al. (1981) investigated the factors affecting the cost of nitrogen for cycling projects, as well as factors affecting cost of nitrogen rejection. He found that the factor which has the greatest effect on the cost of nitrogen is the cost of energy necessary to produce and compress the nitrogen. The air compressors for generating nitrogen can be operated with motors, gas turbines, or gas or diesel engines. So the costs are associated with these parts. The various cost components of nitrogen used in the evaluation is shown in Figure 3. The three main operational costs of the plants are the nitrogen cost (purchasing of nitrogen at low pressure from an onsite plant owned by a manufacturer of cryogenic air separation plant), supplying electricity to the nitrogen plant, and compressing the nitrogen to the 5000-psig pressure required for injection. Figure 3 presents the breakdown of the 49 cents/Mcf cost of nitrogen at the outlet of the 5000-psig pressure maintenance compressors. The operator can either purchase nitrogen equipment for his plant or purchase nitrogen directly from a supplier. Historically, it has been more economical to purchase since this has required no initial investment cost. In this figure nitrogen was purchased from a supplier. In addition, he focused the importance of plant size in determining nitrogen costs. Figure 4 shows approximate costs for nitrogen at low pressure and at 5000 psig (injection) pressure for an all-electric plant, where the cost of electrical power is not included, so must be added to evaluate the total cost of the plant. It is clear from the figure that the nitrogen cost for the low pressure nitrogen generation is moderately decreasing with the increase of plant size (nitrogen volume) while the nitrogen cost for the high pressure (5000 psig injection pressure) sharply decreases with the increase of plant size. So the operator must consider the importance of plant size in evaluating nitrogen cost. Clancy et al. (1980) have also discussed about the air separation technology for producing nitrogen, separation and compression equipment, major equipment and the associated cost. The recent development of small nitrogen producing plants utilizing membranes has allowed the use of nitrogen to be considered for many new opportunities. Membrane produced nitrogen can be used in plants where natural gas is unavailable. Membrane systems, like cryogenic air separation plants, are now available where a "third-party" operates the system on a supply contract. Evision et al. (1992) have discussed about the nitrogen producing membranes, the basic components of onsite membrane air separation system as well as related cost. The advantages of a membrane plant are compactness, simplicity and reliability, resulting in low capital cost especially at smaller capacities and moderate purities. However recent improvements in membrane properties and process arrangements have extended the utility of membrane plants to purities as high as 99.5%. So, at present the big challenge to cryogenic industry is to develop more economic nitrogen producing plants in order to make a competitive Enhanced Oil Recovery technique.
Figure 3 Typical cost components of nitrogen (adapted from Donohoe
et al. 1981).

ELECTRIC POWER  @2cents/KWH 25cents/MCF
COMPRESSION          7.5cents/MCF
NITROGEN            16.5cents/MCF

Note: Table made from pie chart.


[FIGURE 4 OMITTED]

CONCLUDING REMARKS

Recent advances in technology and the current economic climate have resulted an increased interest in EOR, especially [N.sub.2] gas injection in the petroleum reservoirs for improved recovery. While the use of Thermal and Chemical EOR methods are decreasing, Gas injection method in EOR is increasing. Because cryogenic air separation plants can be constructed at or near the field and no pipelines are required, nitrogen gas injection is rapidly increasing both in onshore and offshore application for reservoir enhanced oil recovery. The inert and non-corrosive nature makes it a preferred choice over other gases (i.e. [CO.sub.2], Natural gas etc.). The long term supply security of nitrogen also makes preferable and reliable than other unsecured gases. Nitrogen injection is believed to yield high recovery of the lightest hydrocarbon components. Nitrogen use in the oil field continues to grow as new opportunities are recognized, the demand being mainly satisfied with large scale cryogenic nitrogen plants. Perhaps the greatest task of the cryogenic industry is to develop more cost effective nitrogen producing plants and means for its effective injection to the reservoirs. In the mean time the Petroleum Industry needs to study the long term effect of Nitrogen on the reservoirs, including determining any side effects the nitrogen injection may have on the sustainability of the enhanced recovery. One important factor may be the study of the effect of nitrogen purity, as well as consideration for injection of a mixture of gases vs. pure nitrogen.

REFERENCES

Ahmed, T., D. Menzie and H. Crichlow. 1983. T Preliminary Experimental Results of High-Pressure Nitrogen Injection for EOR Systems. SPEJ April: 339-48.

Bath, P.H.G., J. Van der Burgh and J.G.M. Ypma. 1980. Enhanced Oil Recovery in the North Sea. Paper presented at the World Petroleum Congress, London.

Clancy, J. P., R.E. Gilchrist, L.H.K. Cheng and D.R. Bywater. 1985. Analysis of Nitrogen-Injection Projects to Develop Screening Guides and Offshore Design Criteria, Journal of Petroleum Technology, June: 1097-1104.

Clancy, J. P., R.E. Gilchrist, D.E. Kroll and A. M. Gregor. 1985. Improved Oil and Gas Recovery using Nitrogen Laboratory Analysis, Cases and Economics. Proceedings of the Third European Symposium on Improved Oil Recovery, Rome, pp. 255-64.

Clancy, J. P., R.E. Gilchrist and D.E. Kroll. 1980. Nitrogen for the Enhanced Recovery of Oil and Gas. Paper SPE 9912 presented at the 1980 California Regional Meeting, Bakersfield, March 25-26.

Cobb, B. LaVerne and M. Raymond. 1982. Target Reservoirs for [CO.sub.2] Miscible flooding. U.S. Department of Energy (DOE/MC/08341-35), January.

Donohoe, C.W. and R.D. Jr. Buchanan. 1981. Economic Evaluation of Cycling Gas-Condensate Reservoirs with Nitrogen. Journal of Petroleum Technology. pp. 263-70.

Evison, B., R.E. Gilchrist. 1992. New Developments in Nitrogen in the Oil Industry. Paper SPE 24313, Presented at the 1992 SPE-Mid-Continent Gas Symposium, Amarillo, Texas 13-14, April, 1992. pp 171-78.

Eckles Jr. W.W., C. Prihoda and W.W. Holden. 1981. Unique Enhanced Oil and Gas Recovery for Very High-Pressure Wilcox Sands Uses Cryogenic Nitrogen and Methane Mixture. Journal of Petroleum Engineering, June 1981, pp. 971-84.

Koch, H.A. Jr. and C.A. Jr. Hutchinson. 1958. Miscible Displacement of Reservoir Oil Using Flue Gas. Trans., AIME (1958) 213, pp. 7-10.

Moritis G. 2006. Special Report-EOR/Heavy Oil Survey. Oil & Gas Journal, pp.37-55.

Moritis, G. 2004. EOR Continues to Unlock the Oil Resources, Oil & Gas Journal, April 12, pp. 45-52.

Moses, P.L. and K. Wilson. 1981. Phase Equilibrium Considerations in Utilizing Nitrogen for Improved Recovery from Retrograde Condensate Reservoirs. Journal of Petroleum Technology, Feb. 1981. pp. 256-62.

Peterson, A.V. 1978. Optimal Recovery Experiments with [N.sub.2] and [CO.sub.2]. Petroleum Engineer Intl. Nov. 1978, pp. 40-50.

Rushing M.D. et al. 1977. Miscible Displacement with Nitrogen. Petroleum Engineer Intl, November 1977, pp. 26-30.

Sarma, H.K. 1999. Gas Processes: Principles and Field Application. Japan national Oil Corporation, Chiba-Shi, Japan.

Selby, R., A.A. Alikhan and S.M. Farouk Ali. 1989. Potential of Non-Thermal Methods for Heavy Oil Recovery. Journal of Can. Petrol. Technology. 28(4): 45-59.

Thomas, S. 2008. Enhanced Oil Recovery--An Overview. Oil & Gas Science Technology 63(1):9-19.

Tom Standing. 2006. Mexico's Cantarell field: how long will it last? Energy Bulletin, October 9, 2006.

Md. Didarul Islam, PhD

Mohamed Alshehhi

Student Member ASHRAE

Michael Ohadi, PhD

Fellow ASHRAE

Md. Didarul Islam is a research associate in the Department of Mechanical Engineering, Petroleum Institute, Abu Dhabi, UAE. Mohamed Alshehhi is a PhD candidate in the Department of Mechanical Engineering, University of Maryland at College Park, MD. Michael Ohadi is a professor of Mechanical Engineering and Provost at the Petroleum Institute in Abu Dhabi, UAE.
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Date:Jul 1, 2009
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