Keijin Gu, Yiqun Ye
Nan Hai East Oil Corp.
Guangzhou, Peoples Republic of China
For the Liuhua 11-1 oil field development, extended drill stem tests showed that horizontal wells were more suitable than either vertical or high-angle deviated wells.
Advantages of horizontal wells included three to four times increased productivity over the vertical well, slower water coning from the aquifer, and greater ultimate recovery from a single well.
LIUHUA 11-1 FIELD
The Liuhua 11-1 oil field is in the western part of the South China sea contract area 29/04, about 121 miles southeast of Hong Kong (Fig. 1). Water depths range from 997 to 1,089 ft.
Amoco Eastern Petroleum Co.'s exploratory well Liuhua 11 1 1A discovered the field in February 1987.
Geological studies, logs, and cores verify that the field contains considerable oil in place.
Liuhua 11-1 field is believed to be the largest organic reef-bank oil field in China.
The field has shallow, complicated, massive, bottom water-drive reservoirs, and viscous (16-23 API) crude.
To determine the field's development scheme, successively over about 1 year, extended drill stem tests were conducted on a conventional vertical, a high-angle deviated, and a horizontal well.
GEOLOGY
The Liuhua 11-1 is a simple, complete, and large structure. A few small normal faults parallel to the long structural axis are on the flanks. Fault displacements are less than 115 ft.
Oil is contained in a set of organic reef reservoirs interbedded with organic banks. The reef facies contains coral algae as well as coral-coral algal reef microfacies, dominated by algal reef. The bank facies is of foraminifer-algal fragment and foraminifer.
Denudation of the reef body is the main form of diagenesis. The porosity is dominated primarily by intergranular and intragranular dissolution pores, nonselective dissolution pores, dissolution vugs, and microfissures.
The reservoirs are in contact with a large permeable aquifer that provides producing wells with some bottom water drive energy. Reservoir parameters are listed in Table 1.
PRODUCTION RESULTS
The extended tests lasted 296 days. During the 222 days on production, cumulative recovery was 1.4 million bbl of oil and 440,000 bbl of water from the three different types of wells (Fig. 2a and Table 2).
VERTICAL WELL
The production test of the conventional vertical well Liuhua 11-1-3 was interrupted because of a failure of the packer isolating water and oil zones. Resetting the packer restored normal production. Initially, production was 5,600 bo/d and 1,400 bw/d. Water cut was as high as 20%. Initially, the water was believed to be well control fluid lost during the completion.
After 5 days of production, the oil rate declined by 37% to 3,549 b/d. Water production increased rapidly over the same period.
The test was halted after another 9 days of production. At that time, the well was producing 3,400 bo/d with a 50% water cut.
After replugging the lower water-producing zone, the well was put back on production. No water was observed during the first 6 hr. Seven days later, water cut increased to 50%, while the oil rate decreased by 20.3%, from 3,500 to 2,788 b/d.
Twenty-four days later, the well flowed 2,460 bo/d with a 70.3% water cut.
HIGH-ANGLE WELL
The Liuhua 11-1-5 was a high-angle deviated well with an average deviation angle of 78 (81 maximum) and maximum horizontal displacement of 6,438 ft.
Initial production was 7,841 bo/d. No water production was observed for the first 6 days, but during the following 2 days water increased rapidly.
After 1.7 months of production, the oil rate declined by 29.9%, from 7,841 to 5,497 bo/d, and water cut increased to 50.6%.
The test was terminated because of mechanical failure and unfavorable weather conditions.
HORIZONTAL WELL
Horizontal well Liuhua 11-1-6 was drilled with a buildup curve of 4.7-8.8/100 ft. Maximum deviation was 92.5. The well penetrated the oil-bearing formation at 1,967 ft with a 1,798-ft long horizontal section. The hole was completed with a 1,886-ft, 7-in. liner (not cemented), followed by an acid treatment.
The extended drill stem test began Jan. 6, 1989. Initial oil rate was 9,620 b/d. Five days later, the well was shut in for pressure measurement and acidizing.
After being reopened on Feb. 1, the maximum oil rate was 12,141 b/d. In the successive 110 days of production, water cut varied and a 24.7% water cut was measured at the end of the test.
Over the entire test period, the oil rate decreased by 47.5% from 12,141 b/d to 6,379 b/d.
OIL RATE
The oil rate for the horizontal well was three to four times greater than from the conventional vertical well. The production rate was also greater than from the high-angle deviated well.
Table 3 shows that the production index before water breakthrough was four times that of the vertical well.
The better performance is because the horizontal well and the high-angle deviated well penetrated more of the reservoir than the vertical well. Compared to the vertical well, the horizontal well contacted 13 times more reservoir and the high-angle well 5 times more. The additional contact area between the well bore and the reservoir reduced the resistivity to fluid flow.
The relatively small ratio of production rate increase was partially affected by the permeability variation in different parts of the reef body corresponding to the different well locations.
The reservoir permeability ranged from 500 to 1,000 md in the horizontal well and was 6,314 md in the vertical well.
Because of the weakness and delay of reservoir pressure, the production rate of the horizontal well decreased despite the continually increasing pressure drawdown.
WATER CUT
The water cut increase in the three kinds of wells was varied (Fig. 2b and Table 4). The water cut increased slower in the horizontal well than in both the high-angle deviated and vertical wells.
The daily increase of water cut in the vertical, deviated, and horizontal wells was 0.73-2.2%, 0.7-1.4%, and 0.21-0.25%, respectively.
The.total oil recovered at 1% water cut was 18 times more in the horizontal well than in the vertical well. In terms of water produced, to yield the same amount of oil, reservoir energy depletion in the vertical well was six and four times that of the horizontal and the deviated well.
Hence, it can be inferred that the horizontal well and the high-angle deviated well will recover more oil than the vertical well.
The pattern of bottom water coning near the well bore of the horizontal and the deviated well is a "water ridge" that is evenly distributed and provides higher areal sweep efficiency. As a result, oil production is greater while bottom water coning is slower. In the vertical well a conical bottom water movement is expected (Fig. 3).
The difference of the viscosity ratio of oil to water was varied. This ratio was 236 for the vertical well or 1.4 and 2.5 times greater than that for the deviated and horizontal wells, respectively. Because of the high viscosity ratio of oil to water in this field, nonpiston displacement will usually cause water breakthrough that will result in lower efficiency of water displacement.
The well performance was also affected by the distance between the bottom perforations and the water/oil contact. This distance was 187 ft for the horizontal well, 34 ft for the deviated well, and only 2.6 ft for the vertical well. Moreover, the discontinuity of areal distribution of the tight stringers also contributed to well performance.
The tight stringers within the reservoir cannot prevent coning of the aquifer effectively, because the stringers are not distributed continuously over the entire reservoir. Water from the aquifer can break through and flow along the microfissures to the well bore.
The horizontal wells can slow down the coning process of the bottom water because of the tight stringers lying in the middle section of the reservoir (Geologic Unit C, Fig. 4).
RESERVES
A semilog coordinate plot was used to estimate the potential ultimate recovery of the wells. An approximate straight-line section was formed when cumulative oil and water production were plotted. These curves were used to estimate water drive controlled recovery.
For the horizontal well, water-drive-controlled reserves were estimated to be 4.2 times more than the deviated well and 7.4 times the vertical well.
Producing with a water cut, the recoveries of the horizontal well and the deviated well differed slightly. The horizontal well enhanced the recovery by 8.6% (Fig. 5).
AQUIFER PRESSURE
The tests confirmed the existence of bottom water drive energy. The pressure recorded in the vertical well after a short period of initial flow (due to packer failure) showed a liquid production rate ranging from 3,836 to 8,993 b/d and essentially a constant pressure (Fig. 6a).
Judging from the production profile, only small fluctuations in the bottom hole pressure occurred at the first stage of the test when the fluid rate was 5,000-6,415 b/d (Fig. 6b).
Pressure data acquired from the aquifer (Fig. 6c) changed slightly. Pressure declined by 4 psi, from 1,871 psig before initial flow to 1,867 psig immediately before shut in, and then increased to 1,870 psig after shut-in. Therefore, good communication existed between the oil zone and the aquifer. This phenomenon also appeared in the deviated well.
Although the initial high production rate declined gradually while the pressure drawdown increased before stabilizing (Figs. 6d and 7), the extended drill stem test on the horizontal well indicated a high productivity with an average rate of 7,648 bo/d.
For example, at the second stage of the test, production rate during the initial flow decreased by 27%, from 12,371 to 9,031 b/d, while the production drawdown increased from 998 to 1,225 psi.
During the third stage of the test, the average production rate was 10,132 b/d for the first 4.8 days, and the average production drawdown was 1,126 psi. As time went by, higher production drawdown, 1,144-1,208 psi, was maintained but the production rate declined gradually from 8,868 to 8,069 b/d.
The decline is believed to be caused by insufficient natural energy.
The aquifer could provide single-well production with certain bottom water drive energy, and could meet the need for a relatively low recovery rate. However, if the oil field is put on production with horizontal wells at a recovery rate greater than 10% (calculated from recoverable reserve), the aquifer energy will be unable to satisfy the energy requirement. Therefore, additional energy supply needs to be included in the development program.
DEVELOPMENT COST
Drilling cost of the deviated well was the highest at $985/ft. This was followed by the horizontal well at $623/ft.
The cost of the horizontal well was 1.9 times that of the vertical well, but 44.8% lower than that of the deviated well.
For production, the large discharge capacity electric submersible pumps will have to be protected from corrosion because of the high hydrogen sulfide content, 5,000-6,000 ppm after separation.
Copyright 1992 Oil & Gas Journal. All Rights Reserved.
