J. Moritz, A. Baumgartner
OMV Aktiengesellschaft
Vienna
Specialized equipment and procedures were needed for carrying out a successful flow test of the deepest reservoir, to date, in Europe. The reservoir, located at 20,712 ft, had a pressure gradient of 18.3 ppg mud.
DRILLING OBJECTIVES
Because the shallow formations in the Austrian basins had been relatively well explored (first commercial oil in 1934), it was necessary to change the exploration strategy and drill deeper.
So far (5MV Aktiengesselschaft has drilled nine wells deeper than 16,985 ft (6,000 m). One is deeper than 22,966 ft and was lost by a kick at a depth of 24,747 ft. Another has reached a TD of 28,061 ft and is now the deepest well outside the U.S. in exploration for hydrocarbons. This well discovered a noncommercial gas reservoir.
The well "Maustrenk UT la" is located about 30 miles north-northeast of Vienna and less than 10 miles west of the Czechoslovakian border. The target was to reach the autochthonian mesozoicum at a TD of 21,325 ft.
Elevated pore pressure was expected in the deeper formations and fluid-loss zones above them. Therefore, an intermediate liner was foreseen to prevent possible fluid loss.
(5MV decided to order a casing tie-back string only after reservoir data became available. This caused an interruption of more than 1 year before completing and testing the well in a proper way. The production test was started at the end of 1986.
WELL COMPLETION
The well was drilled with an Ideco H 2500 rig. After running the conductor pipe and the 18%-in. and 13%-in. casing, a problem was encountered while cementing the 10-in. casing.
The string was run with the OMV casing jacking system because the 400 ton weight greatly exceeded the rig capacity. In addition, some spare capacity was required.
The two-stage cement job Gould not be performed as planned because the firststage cement was lost unexpectedly in a fluid-loss zone.
The well was originally drilled with an oil-base mud of 12.6 ppg (1.52 kg/l.). For the second stage, circulation was not possible because the zone had been fractured. The only way to cement the casing was to close the sleeve and bullhead with a large cement volume of 868 bbl (138 cu m) of 12 ppg (1.44 kg/l.) cement.
During the following drilling operation, an on-line data unit was used for data collection.
At a depth of 20,620 ft (6,285 m), a new critical zone appeared. It was approximately 66 ft above the productive formation.
Because influx was observed, the mud weight had to be increased from 17.5 to 18.2 ppg. A period of fluctuating losses and influx followed. More than 1 month was needed to overcome the unbalanced situation. The use of highly viscous fluid and heavy mud pills with up to 22.5 ppg enabled running a minimum logging program across the 4,593 ft open section.
Afterwards, a heavy, 22.5 ppg, mud pill with a volume of 190 bbl was circulated to TD. This helped avoid gas penetration into the well bore.
The well was successfully cemented and plugged back to 19,554 ft, side tracked at 19,783 ft, and drilled to 20,472 ft.
A 7 5/8-in. intermediate liner was set from 20,472 ft to 15,249 ft and cemented.
The replacement of the oil-base mud to water-base mud was necessary to diminish gas solubility and to achieve a better mud-volume control. Mud weight had to be increased to 18.8-19 ppg. No problems were encountered while drilling through the formation.
A 5-in. liner was set at 21,319 ft and cemented. After perforating the interval of 20,682 - 20,712 ft, a 13 bbl drill stem kick test proved the existence of gas with a reservoir pressure of 20,000 psi (1,380 bar).
The gas analysis by volume was CO2-1.97%, C1-77.21%, C2-12.55%, C3-4.87%, and C4,-3.40%.
Mud contaminated with high-pressure gas led to considerable difficulties in pulling the test unit because clearance on the 5-in. liner was poor. However, it was finally possible to continuously circulate 20 ppg mud through the circulating valve of the test unit. This procedure lasted two weeks.
Afterwards, two cement plugs were set in the 10-in. casing at a depth of 14,370 - 14,862 ft and 14,233 - 13,675 ft for safety reasons.
The test result was encouraging, and a tie-back string was ordered that consisted of 4,265 ft of 6 5/8-in. buttress dual seal (BDS) casing with a wall thickness of 0.63 in., grade P-110 and 11,483 ft of MW-95-SS casing, with a wall thickness of 0.843-in. It was designed according to OMV specifications with strict standards including sulfide stress cracking resistance. An abstract is shown in Table 1.
The tubing string with a slightly less rigorous design was originally designed for a different project and consisted of: 2,700 m 3 1/2-in. tubing double seal (TDS-S), C-95, 0.752 in. wall; 2,800 m 2 7/8-in. TDS-S, P-110, 0.440 in. wall; and 1,700 m 2 3/8-in. TDS-S, M-1 25, 0.336 in. wall.
At the bottom a few joints of AF 22-130 (austenite/ferrite stainless steel) were used (Fig. 1).
To meet these high standards, the most important aspect was quality assurance. The number of probes was increased above the API requirement.
The standard of the continuous ultrasonic test units, as well as the extended end area inspection, was verified by an experienced independent company. The tests themselves were observed by a different inspection company.
In addition, special selected samples were tested by a university laboratory. This procedure led to several rejections. The accepted material was documented by a certificate for each joint that contained the chemical analysis of the composition for pipe and coupling, and data concerning hardness, heat treatment, physical tests, coupling torque, MPI tests, etc.
This expensive and rather complicated procedure was necessary to handle the high-pressure gas and avoid any problems and risks.
The well was completed open ended which offered the advantages of safe unloading and circulation, the possibility of inhibition and killing, and the elimination of the danger from tubing leaks.
The completion exposed the casing string to the full reservoir pressure of 20,000 psi.
PRODUCTION TEST
More than 1 year later, after construction of the necessary facilities, the well was conditioned for running the tie-back string. This was preceded by the necessary steps of drilling out the cement plugs, pulling the protective packers, and polishing the liner receptacle.
An H900 rig was used with a special substructure to fit the casing jacking system and the 30,000 psi Christmas tree.
The 6 5/8 and 7-in. tieback string was totally cemented and landed in the casing head. After the cement had been drilled out, the tubing string was run.
Following this, the unloading procedure was performed in four steps, beginning with 18.8 ppg chrome lignite mud. The intermediate step consisted of circulating mud with weights of 15, 10, and 8.33 ppg as well as diesel oil and carrier oil.
Spacers prevented interaction between the mud and water as well as between water and the carrier.
After this liquid exchange, a volume of 25 bbl of diesel was injected into the formation to check injectivity. Then 126 bbl of acid was circulated to the perforations and injected for skin removal.
During the whole unloading procedure, which was scheduled to last 19 hr without interruption, it was necessary to prevent any influx from the formation as well as any fluid loss. Furthermore, the frac gradient needed to be taken into account.
Other limitations were given by the performance data of the equipment and the pressure rating of the tubing and casing. Borehole temperatures corresponding to different stages of treatment and production are shown in Fig. 2.
Extensive precalculations using experimental data in a multiple-fluid model made it possible to establish the required choke and pumping pressures at selected flow rates. The unloading pump schedule is shown in Fig. 3. During the job the bottom hole pressure was kept 870-1,460 psi above the reservoir pressure.
For increased safety, the equipment shown in Fig. 5, representing a total of 2,238 kw (3,000 hydraulic hp) was placed on the well site.
Pressure intensifiers had been tested successfully in advance by pumping water at 27,000 psi for 4 hr. The average lifetime of the lubricator packings was estimated based on experience to be about 20 hr.
Pumping and choke pressures were recorded continuously in the remote control cabin. Five chokes, which were also operated from this cabin, allowed for immediate response. Both the pumping rate and backflow were continuously recorded.
INHIBITOR
To prevent corrosion, continuous inhibitor circulation into the annulus was chosen. Prior to this, three potential inhibitor carrier systems were used as part of screening tests at 25,000 psi and 227 C. (440 F.) to determine the phase behavior of these materials with a gas corresponding to the expected gas composition.
Tailor-made carrier products were developed by OMV to ensure that at downhole conditions a sufficient amount of liquid phase would be present to dissolve the inhibitor. In this case, to minimize flow resistance, transport requirements called for an acceptable viscosity-vs.temperature performance.
In addition to this thermostability, compatibility to borehole liquids, pumpability, and emulsion tendency were evaluated. Accelerated corrosion tests were necessary to prove that the exposed materials would not be affected by corrosion.
WELLHEAD
A schematic drawing of the 30,000 psi wellhead and the Christmas tree arrangement, which was already ordered earlier for a different deepwell project, is shown in Fig. 4.
The tubing spool is 13 5/8 in., 20,000 psi x 7 1/16 in., 30,000 psi with 1 13/16 in., 30,000 psi outlets. The valves on the tubing spool are 1 13/16 in., 30,000 psi bodies with 2 9/16 in., 30,000 psi flanges in order to permit an additional seal inside of the BX-153 sealing ring.
The 7 1/16-in. mandrel-type casing hanger is made of Inconel 718.
The bottom of the tubing spool has two metal seals, with one metal clad P-seal above and one below for testing purposes. The main run is of 2 9/16 in. and the wings are of 1 13/16-in. nominal size, with all parts rated for 30,000 psi working pressure.
Although the API 6AB and the 15th edition of API specification 6A, issued in 1986, were not available at the time of the order, the quality assurance plan agreed upon meets or exceeds the requirements of the above-mentioned standards as well as those of product specification level PSL 4.
Because several parts and preparation procedures were of a new design, a comprehensive prototype test program was carried out under the surveillance of third-party inspectors. This program focused on the casing hanger, tubing hanger, various seals and stem packings, and included cycle tests at ambient temperature and 180 C.
A proprietary alloy containing 2 1/4 Cr 1 Mo was used for the block master valve. Because of the wall thickness of 14.6 in. it was difficult to carry out the through wall heat treatment.
The production wing of the Christmas tree was connected to a 20,000 psi choke arrangement followed by a 15,000 psi choke manifold containing drilling chokes equipped with production internals.
The annulus could also be opened to the choke manifold. For methanol injection, autoclave pipes and fittings were used. The check valves had metal-to-metal seals for poppet and seat. A four-way cross allowed for recording the production fluid temperature.
For the installation of the back pressure valve in the tubing hanger, a setting and removing tool assembly was on site, including a lubricator designed for 30,000 psi to accommodate a 22 ft polished rod.
Two master valves and one valve on each wing were equipped with hydraulic operators. The operators as well as the chokes of the manifold were controlled by means of a control panel located at a safe distance from the well.
Each valve actuator could be controlled individually or in a certain mode providing opening, closing, or emergency shutdown sequences during production.
The kill lines for tubing and annulus were connected to the standby high-pressure pumping equipment.
TEST FACILITIES
For designing the test units, reservoir pressure and temperature were available. The gas sample from the kick test was contaminated by mud and therefore not representative. However, the sample indicated a high content of liquid.
Criteria for the layout included the evaluation of the reservoir characteristics as well as obtaining representative gas and liquid samples for fluid characterization.
The test production was fed into a nearby distribution gas line. Therefore, conditioning to sales gas quality was required, with due consideration to a possible change in the gas properties.
The combustibility estimated according to Weaver was out of range at three of the six factors (Wobbe index, primary air suction, CO-buildup tendency). This problem was solved by adding up to 10% nitrogen to the dehydrated gas.
A schematic drawing of the test layout is shown in Fig. 6. For liquid removal after the unloading procedure, a degasser connected directly to the choke manifold was used.
Before switching to the sales gas line, extensive testing was carried out in the field laboratory while flaring the gas over a large-scale flare. During this period, large volumes of inhibitor fluid were injected into the annulus to prevent any corrosion from attacking the casing. This was accomplished by means of two electrically driven high-pressure pumps designed for a maximum pumping pressure of 20,000 psi.
Heated inhibitor storage tanks ensured adequate viscosity values and pumpability.
After start-up, the flowing wellhead pressure was reduced by the chokes of the manifold to about 6,090 psi. The plant pressure was established by another choke after preheating the fluid in the primary coil of a three-phase separator.
For sampling purposes, the drained liquid phase was accumulated in the volumeters. The liquid hydrocarbons were flushed once more before flowing to the storage tanks.
To meet acceptable water and hydrocarbon dew points, gas from the separator was dehydrated by valve expansion refrigeration in a low-temperature extraction (LTX) system. The combustion behavior was adjusted by adding nitrogen generated by a vaporizer into a mixing chamber.
Turbine meters were used as flow measurement.
TEST PERFORMANCE
When the well was cleaned up, a maximum shut-in pressure of 14,649 psi developed at the wellhead. The bottom hole survey indicated a bottom hole pressure of 20,000 psi at a temperature of 160 C.
The production rate stabilized at about 2.6 MMcfd gas at a wellhead flowing pressure of 8,702 psi. The gas/liquid ratio was about 2,953 scf/bbl (500 MI/M3).
The final fluid analysis is shown in Table 2.
When the injection pumps were stopped, the pressure in the open annulus stabilized. No loss of inhibitor fluid was observed as long as the flowing bottom hole pressure equaled the weight of the column.
ACKNOWLEDGMENTS
The authors wish to express their appreciation to OMV, Austria, for permission to publish this article.
BIBLIOGRAPHY
- Riedl, L., "Die technische Auslegung von ubertiefen Bohrungen unter Berucksichtigung von Produktionsversuchen."
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