Problems Relating to the Fracturing of Deep Wells in the North China Region
- Guo-Cal Li (Inst. of Production Technology) | Zhao-Ming Zhu (Research Inst. of Petroleum Exploration and Development)
- Document ID
- Society of Petroleum Engineers
- SPE Production Engineering
- Publication Date
- November 1988
- Document Type
- Journal Paper
- 455 - 462
- 1988. Society of Petroleum Engineers
- 2.2.2 Perforating, 2.4.3 Sand/Solids Control, 2.5.2 Fracturing Materials (Fluids, Proppant), 3 Production and Well Operations, 4.6 Natural Gas, 1.8 Formation Damage, 5.5.2 Core Analysis, 2.5.1 Fracture design and containment, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 4.1.2 Separation and Treating, 1.10 Drilling Equipment, 5.1.2 Faults and Fracture Characterisation, 4.1.5 Processing Equipment
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Summary. The oil and gas fields of the Tertiary Sand formation in north China are of complicated structure. The permeability of the pay zone ranges from 0.1 to 50 md, and the porosity approaches 13%. During development, hydraulic fracturing is necessary to stimulate well productivity to achieve satisfactory economic benefit. This paper discusses fracturing fluids and solid leakoff additives, proppants and types of propping, fracture height and diverting fractures, and fracturing pressure for the formation in this area.
The major deep wells fractured in north China are those produced from sandstone reservoirs in the Tertiary Shahejie formation. The depths of pay zones lie between 2000 and 5000 m [6,560 and 16,400 ft]. Most field are in structurally faulted zones, in the form of faulted blocks separated by ladder-type normal faults. The reservoirs are characterized by multiple faults, small blocks, and tight reservoir rocks. The average block size in a highly developed faulted zone is 0.92 km2 [0.36 sq mile], while the maximum one in a less developed faulted zone is 9.6 km2 [3.7 sq miles]. The problems to be discussed in this paper are those encountered in fracturing wells of depths ranging from 3500 to 4200 m [11,480 to 13,780 ft]. Eighty fracturing jobs have been conducted in these wells since 1977 in four areas. The production pressure differential of the wells ranged from 24.52 to 34.33 MPa [3556 to 4979 psi]. The effectiveness of jobs in production wells (defined as the postjob cumulative increased production per well under the same production condition that is higher than 907 Mg [1,000 tons] within 6 months) reached 100%, while that in exploratory wells was less than 60%. Where better stimulation responses have been obtained in the Maxi oil field, the techniques used in deep well fracturing are therefore considered to be successful.
The Maxi oil field is a rather-well-defined block-faulted anticline (Fig. 1) with an oil-bearing area of 6.5 km2 [2.5 sq miles] and an original oil in place (OOIP) of 5.6 Mg [6.18 x 106 tons]. The pay zone in this field consists of two groups in the Tertiary Shahejie formation. The physical properties of these two groups are listed in Table 1. These data demonstrate that these two groups are good targets for fracturing. They have the following advantages: (1) adequate pay thicknesses concentrated in a relatively short interval; (2) good barriers, indicated by a natural gamma reading of 2.2 x 10 (-9) to 2.7 x 10 (-9) C/kg.h [8.5 to 10.5 R/hr]; (3) higher formation pressure and ease in unloading after fracturing; and (4) relatively complete structure, with less effect from faulting, which is favorable for the utilization of edgewater drive during production.
Ten wells in this field have been fractured since 1983. With the average daily production 1 month before fracturing as a base, the total incremental production ranges from 38 100 to 44 450 Mg [42,000 to 49,000 tons], which is equivalent to an annual production increase of 0.7% of OOIP (Table 2).
These fractures were mainly small and medium-sized. The proppants used in each job ranged from 10 to 60 m3 [2,642 to 15,850 gal] (18 to 109 Mg [20 to 120 tons]). High-strength bauxite was applied because of the higher closure pressure, 34.33 to 49.04 MPa [4,979 to 7,112 psi]. The incremental oil production for each well averaged 7076 Mg [7,800 tons], and natural gas production was 2665 x 10(3) m3 [94 100 ft3] (Table 3). The effective period of increasing production lasted for 440 days. The problems relating to deep well fracturing this area, such as fracturing fluid and solid leakoff additives, proppants and propping types, fracture height and selective fracturing with diverting materials, and formation fracturing pressure are discussed in this paper.
Fracturing Fluid and Solid Leakoff Additives
The fracturing fluids commonly used are cellulose and its derivatives, DGA, DGC, and DGE.
Rheological properties of the DGE emulsified fracturing fluid at 110 degrees C [230 degrees F] are listed in Table 4. Laboratory study of the rheology of those fluids shows that they evidently exhibit viscoelasticity and thixotropy. The power-law equation is still applied in design, and field practices show that this can meet the requirement of carrying bauxite proppant into the fracture.
Adoption in deep well fracturing of a cooldown procedure allows cellulose and its derivatives to be used at formation temperatures as high as 150 degrees C [302 degrees F]. Fig. 2 shows the measured continuous downhole temperature decline during injection of the fluid. Field practices show that when the pad volume is 20 to 40% of total fluid volume, this fluid can meet medium-size job requirements satisfactorily. This finding is consistent with White and Daniel's proposal.
A continuous mixing procedure generally is used; the fluid is prepared by a delayed crosslinking procedure and is degraded by formation temperature after the job. The viscosity of degraded fluid is 1 to 2 mPa.s [1 to 2 cp], and the residue is a flocculent material.
From in-house fracture conductivity tests, it was demonstrated that the damage to the propped fracture by degraded residue is fairly serious (Fig. 3). The testing equipment is shown in Fig. 4. Distilled water or fresh water passing through a 6- m filter was used in the test. Test procedures were as follows. The degraded solution was prepared at 130 degrees C [266 degrees F] and passed through the propped fracture simulator. The percentage damage of the propped fracture conductivity was calculated; then fresh water was flushed in the reverse direction and the percentage recovery of fracture conductivity was recalculated. The fracture was propped with 0.45- to 0.9-mm [0.018- to 0.35-in.] -diameter bauxite at a concentration of 4.83 kg/m2 [1 lbm/ft2]. The pressure difference used in the test was 0.29 to 1.96 kPa [0.04 to 0.28 psi], and simulated closure pressure is 58.85 MPa [8,535 psi]. Test results show that the damage from the residue decreases with the increase in degrading time (solid line in Fig. 3). This conclusion is consistent with that of Cooke and Almond. The recovery of damaged fracture conductivity increases with the increase in the degrading time of fluid; the maximum value may be as high as 80% (dotted line in Fig. 3).
The propped fracture conductivity, calculated from transient-pressure test data 2 to 5 months after the fracture job, is 30 to 70% of the laboratory result (a minimum value of 10% is observed).
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