Siegfried K. SchuelerMobil Erdgas-Erdol GmbH Celle, Germany
A five-fold increase in production resulted from one of the world's deepest horizontal gas wells drilled in the sour Zechstein formation in Germany.
The Siedenburg Z-17, Germany's first deep horizontal gas well, currently produces 17,000 cu m/hr (15 MMcfd) at a wellhead flowing pressure of 48 bar (700 psi); this rate is substantially greater than that of comparable vertical wells in the area.
Operator Mobil Erdgas-Erdl GmbH and its partner BEB Erdgas and Erdl GmbH (Duetsche Shell AG/Esso AG) drilled the difficult horizontal well to 3,415 m (11,200 ft) through largely depleted gas horizons an salt sections and into a low pressure, fractured sour gas formation. The drilling program encountered critical problems such as pressure sticking and lost circulation. The hostile environment required high standards for completing and producing the well at the highest rate possible.1
FIELD PERFORMANCE
Sour gas was discovered in northern Germany in the Siedenburg area in the late 1950s. Fig. 1 shows the structure map of the large Siedenburg/Staffhorst gas accumulation. The Zechstein (Permian) main dolomite reservoir is at an average depth of 3,400 m and originally contained 40 billion cu m (1.5 tcf) of gas. The eastern Siedenburg area is operated by Mobil.
Fig. 2 shows the total field production since first production started in 1966. In the mid-1970s the production reached a maximum of 150 million cu m/month (200 MMcfd) from five wells. The best of these wells produced up to 53 million cu m/month. However, a steep decline soon followed together with a significant rise in the water/gas ratio.
In 1990, the well capacity was about 20 million cu m/month from six wells at an average wellhead flowing pressure of 30 bar. The wells produced at an average water/gas ratio of 70 cu m/mil- lion cu m (12 bbl/MMcf.
A well capacity plot shows the late stage of depletion prior to the drilling of the well Siedenburg Z-17 (Fig. 3). With the exception of wells Z-11 and Z-15, all the wells are approaching the economic limit considering the high operating expense for sour gas wells.
Well Z-11 is considered a "natural" horizontal well-it was accidentally placed where the reservoir dips steeply because of faulting (Fig. 4). The well penetrates the formation along its main axis with a productive section of 410 m. The Z-11 provides 50% of the vertical wells' capacity and still produces with its original water/gas ratio.
With respect to the performance of vertical Siedenburg wells (excepting well Z-11) gas deliverability suffers from the relatively small volumes of produced water.
The produced water is a result of channeling along fractures with high pressure differentials at the wells. Unfavorable drainage conditions exist in the massive dolomite, which has a gross thickness of about 150 m. These wells produce gas with the help of compressors. Chemical injection is required to combat corrosion and sulfur plugging problems. A strong decline in well capacities pointed to a less than optimal recovery, around 70% to date.
HORIZONTAL WELL SELECTION
Mobil concentrated on the best areas of the reservoir because a more favorable drainage is possible when the horizontal well is placed in the most productive interval just below the top of the reservoir. There, the porosity and permeability have the highest values. This also led to the expectation of a more favorable development using fracture permeability resulting in fewer water problems, higher capacity, and increased recovery.
Because of no prior experience with horizontal drilling under these extreme drilling conditions, a multidisciplinary team was established; good preparation and forethought kept drilling and producing difficulties to a minimum. The interdisciplinary team handled all aspects of the project, including well design, drilling, completion, and formation evaluation.
The reservoir management efforts began with a screening of existing wells as potential candidates. The mission of the team was to investigate the technical feasibility in light of the considerable cost and risk involved and to prove the economic viability of the horizontal well project.
Initially, a sidetrack of well Siedenburg Z-2 was considered for the horizontal section. This well had been partially plugged because of a casing collapse in its lower section. The facies are of best quality in this structurally high central region of the reservoir. The upper part of the pay zone is matrix dominated, and severe natural fracturing is limited to the lower portion of the reservoir, which is a rather tight mudstone. Additionally, the contour lines are almost level in this area.
The net thickness of vertical well Z-2 is 102 m with an average porosity of 9%. There are no vertical flow barriers, average horizontal permeability based on test data is around 5 md, and the vertical permeability was estimated at 0.5 md. Based on log and core profiles of well Z-2, the target section was chosen as the top of the reservoir which has some 40 m of well-developed oolithic grainstone.
Initially, a sidetrack of Well Z-2 to the north was chosen; however, a special analysis based on seismic stratigraphy detected a northwest-southeast trending fault zone north of Z-2. The direction of the horizontal hole was changed to the west.
However, the sidetrack for Well Z-2 was aborted when it became clear that the condition of the casing was too poor and would have required a very risky milling job. The team determined that a new well was the best solution, despite the $8 million drilling cost.
WELL DESIGN
The drilling was in a geologically difficult environment with tight target tolerances. The entry point was planned to be as close as possible to the old Z-2 well for better control of geologic uncertainties in the main dolomite.
The main dolomite was depleted to a reservoir pressure of about 115 bar. Therefore, it was required to drill horizontally with a hydrostatic overbalance as high as 240 bar. This overbalance required appropriate mud properties and bottom hole assembly design to avoid differential sticking and to maintain safe operating conditions in a hostile H2S (7%) environment.
The completion design planned for high gas rates close to the maximum allowed by gas velocity limits. An injection of sulfur solvent and corrosion inhibitor was required. The horizontal section had to be cased to allow free access to the hole for at least 12 years of production. Finally, the possibility of recompleting the well was required.
Based on these objectives, the following design was chosen: A single completion mode with a chemical injection line attached to the 4-1/2-in. tubing.
Above the injection sub, C-75 tubing was used. Below this point at 2,800 m and through the curved and horizontal sections, the well equipment was made of corrosion-resistant alloy.
A liner packer was placed at the top of the slotted liner to protect the 7-in. liner from the hostile medium (Fig. 5). The design resulted in a medium curvature hole with a horizontal length of 400 m cased with a 4-1/2-in. slotted liner and tubing that provided an initial capacity of at least 15,000 cu m/hr.
Following the design work, the team concluded that the project was both technically feasible and economically sound. Also based on the Odeh-Babu prediction method, at least a five-fold increase in production was probable, resulting in expected rates of 15,000-25,000 cu m/hr . 2
DRILLING OPERATIONS
The well was drilled in about 5 months and reached total depth at 3,919 m. The Z-17 has a total horizontal displacement of 709 m, of which 415 m are productive in the permeable grainstone layer.
The well was kicked off at 2,925 m measured depth below the 9-5/8-in. casing shoe at 2,890 m. The 7-in. liner was set at 3,480 m. Restrictions in the surface location and target limitations along the well path first required a buildup of approximately 4/30 m followed by a tangent segment in the 8-7/8-in. hole. The 5-7/8-in. hole was drilled with the second kickoff point just below the 7-in. casing shoe and a final buildup of about 13.5/30 m in a sour gas environment.
The horizontal section was drilled with steerable motors, and a measurement-while-drilling tool was run for orientation and surveying throughout the 5-7/8-in. build and horizontal section. Because of the small 5-7/8-in. hole size, the horizontal section could not be drilled with a logging tool to provide formation parameters. Careful analysis of cuttings and proper directional control kept the well bore within the specified target windows.
Risky situations occurred when the drilling assembly stuck twice because of differential pressure sticking: first when the initial part of the horizontal hole was cut and again during the open hole logging operation. On both occasions, the drillstring was freed with an innovative method using nitrogen to reduce the pressure on the stuck tool. Another problem was caused by lost circulation when the well penetrated a fractured zone very close to the end of the horizontal hole.
The well was finally completed with a 4-1/2-in. slotted liner from 3,462 m to 3,913 M.
PRODUCTION RESULTS
Cost and time spent to drill and complete the well were within expectations. Based on logs, the penetrated reservoir is of highest quality with an average porosity of 16%, and log readings indicate up to 30% porosity. The initial test was of limited duration because of regulations for flaring sour gas, yet it showed a rate better than expected. The test obtained a maximum flow rate of 13,500 cu m/hr (12 MMcfd) at a surprisingly high tubing flowing pressure of 55 bar (800 psi).
After the well was equipped with facilities and connected to the pipeline system, the well was allowed a cleanup period of 6 weeks. The rates were increased slowly from 12,800 cu m/hr at a flowing pressure of 68 bar to 18,900 cu m/hr at a flowing pressure of 46 bar with no significant change in fluid production observed. Fig. 6 shows the average water/gas ratio was only 30 cu m/million cu m (5 bbl/MMcf).
In the middle of 1991 a two-rate test was run. Based on a drawdown analysis using the Odeh-Babu method, a reservoir permeability of 3.7 md was calculated.3 The results of the drawdown test indicate that the flow is apparently restricted by partial penetration and some well damage. Using a layered reservoir description, a simulation model was able to match the test results and to verify partial penetration (Fig. 7).
The simulation showed that the entire horizontal length of the well is probably not open to flow. This was derived by using a skin damage of + 20 in the initial simulation model and assuming that the total horizontal length contributed to flow. A poor match was obtained. Using a skin of + 6 from the drawdown analysis and assuming a partial horizontal length of 96 m, a good pressure match was obtained.
Current plans to improve the well include the possibility of acidizing the formation using coiled tubing, nitrogen support, and approximately 600 bbl of foamed acid to remove the restrictions. Even though the current rate of 17,000 cu m/hr is very economical, Mobil feels that if the apparent rate restrictions are removed by an acid treatment, an even higher production rate will be obtained.
Mobil is also considering other possible sidetracks in the Siedenburg field to further develop the reservoir and enhance recovery for maximum present net worth. The good results from the Z-17 have encouraged plans for more projects of this kind in other Zechstein main dolomite and deeper Rotliegendes gas fields in Germany.
ACKNOWLEDGMENT
The author would like to thank Mobil Erdgas-Erdl GmbH and its partner BEB Erdgas and Erdl GmbH for permission to publish this article, and the team members for their important contributions to the project.
REFERENCES
1. Niggemann, L., and Ehlers, R., "Horizontal Drilling in a Depleted Sour Gas Reservoir: A New Application," IADC/SPE 21987,
2. Odeh, A.S., and Babu, D.K., "Productivity of a Horizontal Well, SPE Reservoir Engineering, pp. 417-421, November 1989.
3. Odeh, A.S., and Babu, D.K., "Transient Flow Behavior of Horizontal Wells, Pressure Drawdown and Buildup Analysis," SPE Formation Evaluation, pp. 7-15, March 1990.
Copyright 1992 Oil & Gas Journal. All Rights Reserved.
