Daniel Magyari, Geza Udvardi
KFV Oil & Gas Co.
Nagykanizsa, Hungary
Oil recovery has been significantly increased by creating a CO2 artificial gas cap in the Nagylengyel field, the second largest oil field in Hungary.
Because water entering the formation did not displace the oil from the closed top section of caverns, gas injected into the reservoir displaces the remaining oil from these top sections by gravitational segregation.
The technical aspects of the recovery operation included:
- CO2 production, treatment, and transport
- Well completions
- Fluid production, gathering, and separation
- Re-injection of associated gas
- Corrosion control
- Environment conservation
- Operation control
- Economic issues.
NAGYLENGYEL FIELD
Discovered in 1951, the Nagylengyel field is located in southwest Hungary (Fig. 1).
The overwhelming part of the oil is found in several fractured hydrodynamic units (so called blocks) consisting of Cretaceous limestones and Triassic dolomites at a depth of 1,700-2,000 m (5,577-6,562 ft) subsea.
Produced oil is essentially gas free. The gas/oil ratio (GOR) is a maximum of 5 cu m/cu m (28 scf/bbl) in some blocks. The oil is characterized as paraffin-intermediate, high-viscosity heavy oil (17 API gravity).
The oil zone is thick, 100-350 m (328-1,148 ft). Bottom-water drive is the predominant reservoir driving mechanism. Water influx is unrestricted in most blocks because of the karst lithology.
Reservoir pressure is essentially constant, corresponding to the karst water pressure and is lower than the hydrostatic pressure in the wells. A significant portion of the useful reservoir space exists as karst facies voids and caverns. Permeability is high, several Darcies.
IMPROVED RECOVERY TESTS
Cumulative production from the field is about 19 million tons (125 million bbl) of oil.
After the water cut increased severely, intensive efforts were exerted to select a suitable secondary recovery method that would ensure the highest recovery factor. This work was hindered by the intricate geologic structure and the conflicting ideas about it.
To determine ways to produce additional oil, the first laboratory and pilot tests were aimed at decreasing the surface and interfacial tensions, changing wettability, reducing viscosity, and improving the oil formation volume factor. Several surfactants were tried in pilot tests, but these failed to furnish positive results.
After revising the geological model and determining the role of karst-type pore space, artificial gas-cap recovery tests came into the limelight. The hydrocarbon gas-cap test carried out in the top section of Block 3 in 1978 and 1979 as well as the CO2 gas-cap test conducted in the South Triassic block later (from 1980) unequivocally proved the applicability of these methods.
Gravity segregation is the principle mechanism by which the artificial gas cap forces production from the top oil of the karst caverns, pores, and other irregular voids. The most important factor in the process is the density difference; therefore, any gas can be applied to this recovery operation.
This means that secondary recovery in Nagylengyel field is not a typical enhanced-oil-recovery (EOR) method. The gas forming the artificial gas cap has no enhanced driving effect. Instead, a gas-cap drive exists.
Making use of the favorable circumstance that high-pressure CO2 gas is available in this region, CO2 was selected for the gas-cap recovery operation.
The gas, injected into the top of the respective block, creates a secondary gas cap. The oil pad under the gas cap is pressed in a controlled way nearly to the depth of the original oil-water contact (Fig. 2). After a short balancing period, the gas is withdrawn from the gas cap and the bottom water drive displaces the oil. The withdrawn gas is reused for secondary recovery in another block of the field.
WELL COMPLETIONS
Because of initial gas-free oil production, the old wells were completed for low-load conditions. Primary cement in most wells only reached 150-200 m (492-656 ft) above the reservoir. The general well condition was poor. For example, the wells contained low-pressure-grade casing.
Because of the reservoir characteristics and the poor condition of the old wells, many technical measures were necessary before starting the gas-cap recovery. The measures included:
- Checking the condition of primary cement in all wells.
- Repairing, if necessary, the primary cement job.
- Replacing the old, 150 bar (2,175 psi) wellheads with 210 bar (3,045 psi) dual-seal wellheads.
- Installing new bottom hole equipment. The new permanent packers, and different circulating and setting tools provided versatile manipulation.
- Thorough hydraulic testing of the equipment with water and nitrogen.
Because of the poor condition of the old wells, casing could only be loaded to a maximum pressure of 80 bar (1,160 psi). This pressure was lower than that necessary pressure for the gas cap operation; therefore, new wells were drilled for gas injection. The gassed-out old wells are sealed downhole.
The greatest problem arose while sealing the wells that were drilled during primary recovery and abandoned during drilling. Namely, the reservoir was reached in some wells before running in the production casing, and lost circulation was experienced.
In these wells, the intensive water crossflow, due to the pressure gradient between the oil bearing and the Pannonian (water bearing) formations, resulted in severe wall stability problems. The unstable well bore made it impossible to run production casing.
The lost circulation could not be eliminated with conventional methods. Special, more expensive methods were not used because these wells did not endanger primary recovery.
Before initiating the first stage of the CO2 gas-cap operation, three abandoned wells had to be mended. Many special methods were required during the workover operations on these abandoned wells. For example:
- Continuous directional drilling of the entire length
- Backfilling through directional wells
- Washing over the surface casing string to build in several lengths of casing
- Deepening a drilled well bore
- Checking the success of the cement seal in Well NL-9 with gas injection.
FLUID PRODUCTION
Field characteristics and well structures basically determine the possible production methods. The following design factors had to be taken into consideration:
- Formation pressure is less than hydrostatic pressure.
- Because of high oil viscosity, high-pressure losses are expected in the tubing and flow lines.
- During gas injection, a significant oil volume can be produced (top oil) without any dissolved CO2 gas.
- The casing can endure a maximum pressure of 80 bar while expected wellhead pressures can reach 115 bar.
- Due to high-permeability formations, gas can quickly replace the liquid in the well.
Preliminary investigations showed that a relatively small amount of dissolved gas, 20 cu m/cu m (113 scf/bbl), would be enough to initiate natural flow even in the wells producing with high water cut.
The initial gas-free formation fluid could also be lifted to the surface if the water content did not exceed 10-25%. Experience later showed that the real situation is more favorable than that based on calculations.
Taking these conditions into account, flowing wells are preferred although conditions for natural flow are not very favorable. Using pumping for this type of recovery is dangerous because of the blowout risk. Therefore, pumping is only used in some wells that are far from the gas/liquid contact.
Operating gas-lift is expensive because more compressors would be needed to handle the additional gas and because casing protection such as double casing strings would need to be installed.
Initiating fluid production from a well producing gas-free oil represents a special problem. Because of the oil density and viscosity, natural flow cannot usually be started by simply opening the well, not even in the case of pure oil. Therefore, special well-starting methods have to be used.
When systematic echometric measurements show that the rising oil zone has reached the influx zone in the well, the tubing of the well has to be filled with light oil as deep as about 1,000 m. This creates a wellhead pressure of 15 bar (217 psi) and makes it possible to start the well.
Other well-starting methods can be considered. For example, two possible ways are the injection of air or nitrogen gas.
Until reaching a gas-liquid ratio that ensures overcoming the flow resistance in the flow lines, suitable pressure boost in the vicinity of the wells is required.
Some time was spent in determining the best method to provide this boost. This was because the production conditions of wells changed rapidly from a nearly total gas-free state to fluid production with a very high GOR. Therefore, the surface pumps had to function with high gas and high water content fluid.
The inlet side of the pump had to work with a pressure load of 40-60 bar (580-870 psi). This pressure is necessary because of the possible rapid gas breakthrough.
Several types of pumps were tested and finally the reciprocating pumps proved to be the most suitable. Their inlet side was changed so that the pumps could stand high pressures. The pumps were also equipped with indicating and safety units.
Depending on the gas and water content, fluid production of 20-250 cu m/day (126-1,573 bbl) can be transported with these modified pumps safely.
FACILITIES
Full-scale application of this recovery operation is planned for the whole field in three stages. The first stage of gas injection started in autumn 1988.
Facilities built for the first stage (Fig. 3) included:
- CO2 gas treatment plant
- 35 km (22 miles) Of CO2 transmission pipeline, pressure 160 bar (2,320 psi), diameter 300 mm (11.8 in.)
- Three gathering stations (NLT-3, NLT-5, NLT-6)
- Compressor plant to handle the accompanying gas.
CO2 SUPPLY
CO2 is supplied from the Budafa-deep gas reservoir 35 km from Nagylengyel field. The gas-bearing formations are at a depth of 3,400 m (11,155 ft). Table 1 lists the gas composition of the produced gas.
The gas is dehydrated by a high-pressure glycerol process. Dehydration allows transporting the gas to the Nagylengyel field and injecting the gas into the wells without using compressors.
The maximum working pressure of the gas treatment plant is 160 bar. The plant capacity is 1-1.3 million cu m/day (35-46 MMcfd).
The gas transmission line also has a maximum working pressure of 160 bar. The line's capacity is 2 million cu m/day (70.6 MMcfd).
GATHERING LINES AND SEPARATION
Well streams are gathered through 160 bar, 3-in. flow lines. The characteristic gathering pressures are 20-40 bar (290-580 psi), but in case of emulsion forming or low temperatures, pressures can be as high as 80-100 bar (1,160-1,450 psi).
For chemical injection, feed lines were constructed to the well sites.
Separation pressure is 4-6 bar (58-87 psi). The liquid leaving the separators flows into stock tanks from which the common stream is pumped without treatment to the terminal.
While metering the respective wells, emulsion breaking can be carried out, if necessary, to determine the water content of the produced fluid. Other water-content measurement methods cannot give exact results because of the characteristics of the oil if the water content is high.
Final water separation takes place at the terminal where the free water is separated from the fluid in a continuous operation while emulsion breaking takes place periodically. After utilizing its heat content, the separated formation water is reinjected into the Triassic formations.
GAS COMPRESSION
Pressure boosting the associated gas is carried out by two 3-stage compressors. Capacity of each unit can be regulated between 75 and 3,000 cu m/hr (2.6-106 Mscf/hr).
While putting the compressors into operation, several problems were encountered mostly in the third stage. The original built-in Teflon rider rings swelled and sheared off after 1 or 1 1/2 hr of operation. Broken valves, overheating the stuffing box, and damaged packing rings were also frequent occurrences.
These problems were eliminated by:
- Using special glass-Teflon rider rings
- Increasing the valve plate thickness
- Using the same material for the piston-rod packing rings as for the rider rings
- Improving the cooling of the stuffing box
- Modifying the location of the stuffing-box lubrication
- Applying gas filtration.
CORROSION CONTROL
Properly treated CO2 gas does not cause corrosion in the injection system, and the protection of the production facilities up to the point of oil separation is provided by oil flowing in the system.
Corrosion problems are expected in the accompanied gas system after the separators.
Experiments are currently under way to find the most efficient inhibitors to protect the gas system. Compressor units compressing the associated gas are not from noncorrosive materials (except for the cylinders and pistons); therefore, inhibitor is fed before every stage.
In the second stage of the recovery operation, while withdrawing the gas from the gas cap, inhibitor injection into the formations and inhibitor feed at the well sites is planned for protecting the gas production wells and the flow lines.
In discussing corrosion, mention should be made of the problems connected with the presence of H2S. The partial pressure of the low-concentration hydrogen sulfide (0.3%) is unfortunately high enough in the whole system to result in hydrogen embrittlement.
To eliminate this problem, unalloyed normal carbon steel proved to be the most economical and most efficient method.
That is why J-55 grade tubing is used in both the injection and the production wells. In addition, pipelines are constructed of normal carbon steel.
The downhole equipment below the permanent packer, which provides for shutting in the well, is constructed of high corrosion resistant materials.
ENVIRONMENT CONSERVATION
Closed systems are used to control the unfavorable impact on the environment. Fluid production is regulated in such a way that the produced associated gas should be in compliance with the operating compressor capacity. Therefore, gas can only enter the atmosphere in case of sudden damage.
Breathers on the tanks are connected to one another to minimize the escape of vapor to the atmosphere.
OPERATION CONTROL
Safe operation is supported by computerized monitoring systems in all important locations of the process. This system records and displays the instant and cumulative figures of all the important process parameters and is able to analyze the trend of the particular parameters.
Crucial parameters are remotely monitored through a cable system to the well sites.
Great care was taken to train the operators for the special job. Training provided both theoretical and practical instruction. The experience gained in the field of CO2 recovery, from 1972 on, was also a great help.
ECONOMIC ISSUES
Investment expenditure for the facilities in the first stage of the project was $64 million. Of this sum, $23 million was spent for the wells (including two new CO2 production wells and recompletion of three old CO2 production wells at Bazakerettye).
For surface facilities, $41 million was spent. Of this amount, $17 million will be used for the later stages of the project.
Plans are to inject 2.5 billion cu m (88 bcf) of high CO2 content natural gas. Expected additional oil produced is about 2.1 million tons (13.9 million bbl).
Based on the experience obtained so far, this amount of additional oil is certain because more oil than planned has been produced with less gas injection than planned.
From these favorable results, extension of this recovery operation is planned. That is, this recovery method is planned for an additional three blocks. Additional oil recovery expected from these three blocks is 2.4 million tons (15.9 million bbl).
Gas injection into and gas withdrawal from the reservoir unit under recovery at present is being coordinated with the second recovery stage that will utilize the gas injected from the first stage. This meets the requirements for environmental conservation.
A very interesting technical problem will be the reinjection of the gas withdrawn from the gas cap into other formations without using compressors. This operation is based on the fact that the specific volume of supercritical-state CO2 gas depends, to a great extent, on the temperature.
Copyright 1991 Oil & Gas Journal. All Rights Reserved.
