• Subscribe
  • Magazine
  • Past Issues
  • Surveys
  • Industry Statistics
  • About Us
  • Members Only
  • Podcasts
    1. Exploration & Development

    Optimized drill-in fluids prevent multiscale formation damage

    May 3, 2021
    Formation structural illustrations show how multiscale damage pathways affect gas production (Fig. 1).
    Formation structural illustrations show how multiscale damage pathways affect gas production (Fig. 1).

    Dujie Zhang
    Sinopec Research Institute of Petroleum Engineering
    Beijing

    Lei Yang
    Chengdu Kangpushen Petroleum Technology Development Co. Ltd.
    Chengdu, China

    Junbin Jin
    Sinopec Research Insititute of Petroleum Engineering
    Beijing

    Yili Kang
    Southwest Petroleum University
    Chengdu, China

    Tight gas reservoirs are characterized by narrow pores and throats, abundant clay minerals, and developed fractures. These lead to severe formation damage during drilling, negatively affecting production and ultimate recovery.1-3

    Formation damage in tight gas reservoirs comes from rock-fluid incompatibly, solids invasion, water phase trapping, and stress sensitivity.4-10 Advanced drilling techniques, such as managed-pressure and underbalanced drilling, can minimize formation damage during reservoir drill-in with oil-based, solids-free, noninvasive, surfactant, or temporary shielding drill-in fluids (DIF). 11-16

    Multiscale seepage in tight sandstone gas reservoirs occurs through pores, microfractures, hydraulic fractures, and the wellbore. Each has different damage mechanisms (Fig. 1). Damage is exacerbated in deep and ultradeep tight sandstones, high-pressure high-temperature (HPHT) reservoirs, tight matrices (from strong compaction effect), and well-developed fractures (from violent tectonic movements). A systematic approach for damage control is proposed based on the multiscale formation damage mechanisms.

    Geological setting

    Cretaceous Bashijiqike is an ultradeep tight sandstone in the north part of Tarim basin and is the main pay zone of K gas field. It is the major reservoir exploration target.17 Depth of the main pay zone is 6,500–8,500 m and maximum effective thickness is 150 m.18 Matrix porosity ranges from 2% to 7%, with 3.11% average. Matrix permeability ranges from 0.001 md to 0.0500 md, with 0.014 md average. Natural fractures in the reservoir are developed from three phases of tectonic evolution and special in situ stresses. Based on well-logging data, linear density of natural fractures ranges from 0.7 fractures/m to 1.47 fractures/m. Pressure coefficient is 1.75-1.80. The geothermal gradient ranges from 2.19° C./100 m to 2.30° C./100 m. Formation temperature reaches up to 160° C. Total formation water salinity is as much as 200,000 mg/l.

    Based on 2011-15 PetroChina exploration results, proved geologic reserves are 548.5 billion cu m maximum. Although slightly overbalanced DIFs and anti-formation damage agents have been used, 10 production wells have low productivity due to poor formation damage control.

    Fluids

    HPHT conditions required oil-based and organic salt DIFs for this gas reservoir. Field applications showed that both fluid types could meet drilling requirements. Wells drilled with organic salt DIF, however, had lower yields compared to wells drilled with oil-based DIF, and oil-based fluids gradually became the DIF of choice. Basic properties of the oil-based fluids are shown in Table 1.19

    210503 Ogj027 T01

    Even with oil-based fluids, lost circulation occurred frequently during drill-in. Lost circulation data of 10 completed wells show DIF loss ranging from 4.0 cu m to 916.7 cu m in the reservoir section. Although some formation damage control methods, such as slightly overbalanced DIFs, have been adopted in this reservoir, high lost circulation still caused severe formation damage. Well-test results for four wells show positive skin coefficients (Table 2). Skins in lost circulation wells were high even after acid fracturing, indicating that fracturing cannot completely mitigate formation damage induced by lost circulation. Preventing formation damage rather than eliminating induced formation damage is the main aim for formation damage control in these types of reservoirs.

    210503 Ogj027 T02

    Seepage channel features

    Scanning electron microscopy (SEM) images and casting thin sections of pore throats display intercrystalline pores, intragranular dissolved pores, and feldspar dissolved pores as main pore types (Fig. 2). X-ray diffraction analysis shows that main clay minerals are illite-smectite interstratified clay minerals (15.86%), chlorite (24.72%), and illite (59.42%). The figure shows many dense vertical fibers of illite between rock grains and microfractures, which divides seepage space into much smaller seepage channels. The developed clay minerals make the pore structure more complex. Comprehensive analysis of core observation, micro-resistivity image logging, casting thin sections, and scanning electron microscope suggest that multiple-scale fractures develop in ultradeep tight gas reservoirs (Fig. 3).

    A photomicrograph from an ultradeep tight sandstone gas reservoir rock shows pore throat structures with dense vertical fibers of illite between the rock grains and microfractures (Fig. 2).
    A photomicrograph from an ultradeep tight sandstone gas reservoir rock shows pore throat structures with dense vertical fibers of illite between the rock grains and microfractures (Fig. 2).
    Micro-resistivity image logging, core observation, casting thin sections, and scanning electron microscope analysis (from left to right, respectively) show multiple-scale fractures in the reservoir (Fig. 3).
    Micro-resistivity image logging, core observation, casting thin sections, and scanning electron microscope analysis (from left to right, respectively) show multiple-scale fractures in the reservoir (Fig. 3).

    Natural fractures can be categorized into four levels. Level I fracture apertures are bigger than 1 cm and cut through the sand group. Width of Level II fractures ranges from 100 μm to 5 mm, connecting simple sand bodies. Width of Level III fractures, the microfractures through rock grains ranges from 5 μm to 100 μm. They connect pores and throats by cutting grains. Width of Level IV grain-edged fractures, which connect inter-grain pores and smaller throats, ranges from 100 nm to 5 μm. These multiscale natural fractures link pore throats to the wellbore and provide seepage channels for gas and drill-in fluid filtrate invasion of the matrix.

    Multiscale seepage channels

    High-pressure mercury injection shows that pore-throat radii range from 0.09 μm to 0.66 μm, with 0.324 μm average (Fig. 4a). Pore size distribution (PSD) calculated by nitrogen adsorption (Fig. 4b) shows that PSD is characterized by a single peak, and the radius of the main pore ranges from 2 nm to 10 nm.20 Zhang, et al. quantified natural fracture’s apertures using a variety of methods and found that they typically range from 3 μm to 2,000 μm (Fig. 4c). Combining these results, multiple seepage channels were identified in ultradeep tight sandstone gas reservoirs (Fig. 4d).

    210503 Og Jxdz Z04

    There was an obvious discontinuous zone between pore-throat and natural fractures, and the size of discontinuous zones ranged from 0.3 μm to 3 μm. Therefore, seepage channels can be divided into two scales: matrix and fracture. The main formation damage mechanisms for matrix and fracture are different due to different apertures.

    Matrix damage

    DIF optimization is based on degree of fluid sensitivity, including salt and alkali damage. In this gas reservoir, fluid sensitivity was evaluated with the improved test method of Zhang, et al. which considers the influence of high formation temperatures. Permeability damage rate (DR) indicates degree of damage per Equation 1.

    210503 Ogj029 E01

    Table 3 shows fluid damage in the matrix. Result indicates that salt damage ranges from DR = 0.72 to DR = 0.73 and alkali damage ranges from DR = 0.73 to DR = 0.92. Matrix permeability reduces significantly once working fluid salinity either drops below 75% of formation-water salinity (175,000 mg/l.) or the pH of the working fluid exceeds 7.5.

    210503 Ogj028 T03

    Liquid-phase trapping damage measurement occurred according to the phase trapping coefficient method of You, et al. Diesel oil was also evaluated as a working fluid. Damage from phase trapping induced by formation water is DR = 0.73-0.76, and damage from phase trapping induced by diesel oil is DR = 0.31-0.63 (Table 4).

    210503 Ogj028 T04

    Natural fracture damage

    Fractured sample-fluid damage tests were the same as matrix tests. The Brazilian test method was used to create artificial fractures. Salt damage in natural fractures is DR = 0.67-0.69, and alkali sensitivity damage is DR = 0.78-0.88 (Table 5). Permeability varied greatly during the experiment due to particle migration within the fracture. There is no exact critical value for salt-sensitivity damage and alkali-sensitivity damage.

    210503 Ogj028 T05

    Phase trapping damage

    Phase trapping test methods for fractured samples were the same as for matrix tests, and experimental result are shown in Table 6. Damage from phase trapping induced by formation water is DR = 0.67-0.72, and phase trapping damage induced by diesel oil is DR = 0.62-0.64.

    210503 Ogj029 T06

    DIF damage

    Dynamic damage evaluates comprehensive formation damage by fluids, phase trapping, and solid particle invasion. Test methods are like static damage tests but with shear across the test-sample face as DIF is pumped across the sample.

    Due to narrow pores and throats, it is almost impossible for DIF solid particles to invade the matrix. Tests only evaluate dynamic damage of fractured samples using artificially fractured cores. Experiments were conducted according to detailed steps described by Kang, et al., and results are shown in Table 7. Results show that dynamic damage-rate induced by oil-based DIF relative to initial permeability ranges from 0.47 to 0.71, with 0.60 average. Damage increases as fracture aperture increases.

    210503 Ogj031 07

    DIF loading capacity is key to lost circulation. Poor loading capacity allows more DIF to invade the fracture, and fracture width will increase under positive DIF pressure. Loading capacity experiments were based on experimental procedures described by Zhang, et al. To ensure experimental consistency, steel samples were used in the experiments. DIFs were oil-based and obtained from a gas wellsite.

    Oil-based DIFs only plug fractures with widths less than 50 μm and less than 10 megaPascal (MPa) positive pressure. Maximum positive pressure was only 5 MPa and 3.5 MPa when fracture width was 100 μm and 150 μm, respectively. Once fracture width exceeded 100 μm, oil-based DIFs were unable to plug the fracture completely if pressure exceeded 7 MPa. Table 2 shows that there are many natural fractures with widths greater than 100 μm. To ensure safe drilling, positive pressure is generally 5 MPa-10 MPa. Lost circulation is almost unavoidable using oil-based drill-in fluids in this reservoir, consistent with field data.

    Multiscale damage control

    A multiscale approach for formation damage control uses oil-based DIFs to inhibit fluid-and phase-trapping damage of micro-nano pore throats and natural fractures with apertures less than 100 μm. Unlike oil-based DIFs, organic salt drill-in fluids have difficulty meeting salinity and pH requirements due to special geological conditions and drilling techniques. High oil-water ratios (up to 7.33 for oil-based DIFs) efficiently minimize fluid-sensitivity damage. Oil-based DIF fluids also minimize phase-trapping damage as observed in diesel fluid tests.

    Optimizing the PSD of drill-in fluid minimizes dynamic damage of natural fractures (aperture ≤ 100 μm). To minimize particle and filtrate invasion, adding extra particles of superfine calcium carbonate (22-50 mesh count) reduces exposure time to natural fractures and improves filter-cake quality.

    Acid soluble temporary plugging materials prevent lost circulation while drilling. Natural fractures with apertures greater than 100 μm should be plugged immediately with these materials. The maximum diameter of plugging materials should reach 2,000 μm based on comprehensive geological characteristics and simulation results of dynamic fracture-width prediction.21 Calcite particles with different grain diameters (material names KGD-1, -2, and -3) were selected based on field practices. Material shape and PSD obtained by screening are shown in Fig. 5.

    210503 Og Jxdz Z05

    Field case study

    Well UD1107 is in K gas field, and the target formation is the Cretaceous Bashijiqike tight sandstone. Top depth of the reservoir section is 7,485.6 m, and well design depth is 7,635 m. Based on laboratory experiments, formulation of optimized oil-based DIF included 1% superfine calcium carbonate (22-50 mesh count), 5% KGD-2, and 3% KGD-3. Field experiments show that rheological properties of the optimized DIF meet design requirements. PSD with and without KGD is shown in Fig. 6. With addition of KGD particles, average (D50) particle size increased from 16.40 μm to 37.92 μm, and 90th percentile (D90) particle size increased from 28.64 μm to 60.27 μm. Table 8 shows that dynamic damage caused by the optimized DIF is DR = 18.07%-31.64%, with 22.87% average. This performance meets design requirements.

    210503 Og Jxdz Z06
    210503 Ogj032 T08

    Flowback pressures after dynamic damage experiments are shown in Fig. 7. The shape of the curves shows that the smallest dynamic damage rate during flowback occurred with less than 1 MPa flowback pressure.

    210503 Og Jxdz Z07

    Optimized oil-based DIFs with KGD can plug fractures with widths less than 500 μm under 10 MPa positive pressure. The optimized oil-based drill-in fluid has better anti-loss circulation than the base fluid. During the field test, oil-based DIFs were optimized before drilling the reservoir section. During drilling, temporary plugging materials were added and final test results shows that UD1107 drilling trip was successful without serious drilling accidents, and the drilling rate was almost three times that of control wells drilled with standard fluids (Table 9). Flow tests produced 94.87 × 104 cu m/d, significantly higher than control wells.

    210503 Ogj032 T09

    References

    1. Bennion, D. B. and Thomas, F. B., “Formation damage issues impacting the productivity of low permeability, low initial water saturation gas producing formations,” Journal of Energy Resources Technology - ASME Journal, Vol. 127, No. 3, pp. 240-247, 2005.
    2. Selvadurai, A.P.S., Zhang, D., and Kang, Y., “Permeability evolution in natural fractures and their potential influence on loss of productivity in ultra-deep gas reservoirs of the Tarim Basin, China,” Journal of Natural Gas Science and Engineering, Vol. 58, pp. 162-177, 2018.
    3. Zhang, D., Kang, Y., You, L., and Li, J., “Investigation of formation damage induced during drill-in process of ultra-deep fractured tight sandstone gas reservoirs,” Journal of Energy Resources Technology - ASME Journal, Vol. 141, No. 7, 2019.
    4. Bennion, D. B., Thomas, F. B., and Ma, T., “Formation damage processes reducing productivity of low permeability gas reservoirs,” SPE-60325-MS, SPE Rocky Mountain Regional/Low-Permeability Reservoirs Symposium and Exhibition, Denver, Colo., Mar. 12-15, 2000.
    5. Bennion, D. B., “An overview of formation damage mechanisms causing a reduction in the productivity and injectivity of oil and gas producing formations,” Journal of Canadian Petroleum Technology, Vol. 41, No. 11, pp. 29-36, 2002.
    6. Civan, F., “Temperature effect on power for particle detachment from pore wall described by an Arrhenius-type equation,” Transport in Porous Media, Vol. 67, No. 2, pp. 329-334, 2007.
    7. Bahrami, H., Rezaee, R., and Clennell, B., “Water blocking damage in hydraulically fractured tight sand gas reservoirs: An example from Perth Basin, Western Australia,” Journal of Petroleum Science and Engineering, Vol. 88, pp. 100-106, 2012.
    8. Shivhare, S. and Kuru, E., “A study of the pore-blocking ability and formation damage characteristics of oil-based colloidal gas aphron drill-in fluids,” Journal of Petroleum Science and Engineering, Vol. 122, pp. 257-265, 2014.
    9. Zhao, X., Qiu, Z., Sun, B., Liu, S., Xing, X., and Wang, M., “Formation damage mechanisms associated with drilling and completion fluids for deepwater reservoirs,” Journal of Petroleum Science and Engineering, Vol. 173, pp. 112-121, 2019.
    10. Kang, Y., Xu, C., You, L., Yu, H., and Zhang, B., “Comprehensive evaluation of formation damage induced by working fluid loss in fractured tight gas reservoir,” Journal of Natural Gas Science and Engineering, Vol. 18, pp. 353-359, 2014.
    11. Qutob, H., “Underbalanced drilling; remedy for formation damage, lost circulation, & other related conventional drilling problems,” SPE Abu Dhabi International Conference and Exhibition, Abu Dhabi, Oct 10-13, 2004.
    12. Finley, D., Shayegi, S., Ansah, J., Gil, I., and Lovorn, R., “Reservoir knowledge and drilling-benefits comparison for underbalanced and managed pressure drilling operations,” Indonesian Petroleum Association 31st Annual Convention and Exhibition, Jakarta, May 14-16, 2007.
    13. Lai, J., Wang, G., Cao, J., Xiao, C., Wang, S., Pang, X., Dai, Q., He, Z., Fan, X., Yang, L., and Qin, Z., “Investigation of pore structure and petrophysical property in tight sandstones,” Marine and Petroleum Geology, Vol. 91, pp. 179-189, 2018.
    14. You, L., Kang, Y., Li, X., and Zhou, G., “Mitigating borehole instability and formation damage with temporary shielding drill-in fluids in low permeability fractured reservoirs,” SPE European Formation Damage Conference & Exhibition, Noordwijk, June 5-7, 2013.
    15. Kang, Y., Zhang, D., You, L., Li, X., Li, J., and Huang, C., “New drill-in fluids minimize damage in Tarim basin,” Oil and Gas Journal, Vol. 115, No. 9, pp. 64-69, 2017.
    16. Xu, C., Kang, Y., You, L., and You, Z., “Lost-circulation control for formation-damage prevention in naturally fractured reservoir: mathematical model and experimental study,” SPE Journal, Vol. 22, No. 5, pp. 1654-1670, 2017.
    17. Sun, L., Zou, C., Zhu, R., Zhang, Y., Zhang, S., Zhang, B., Zhu, G., and Gao, Z., “Formation, distribution and potential of deep hydrocarbon resources in China,” Petroleum Exploration and Development, Vol. 40, No. 6, pp. 687-695, 2013.
    18. Yang, X., Xu, J., Zhang, Y., Wang, H., Li, W., Wang, L., and Fan, W., “Decipher productivity secret to optimise well stimulation for Keshen tight gas reservoir,” SPE Asia Pacific Hydraulic Fracturing Conference, Beijing, Aug. 24-26, 2016.
    19. Zhu, J., Li, L., Li, L., Zhang, Z., Cheng, R., Zhang, J., Liu, X., and Li, J., “Application of UDM-2 drilling fluid technology in the development of upper-deep oil and gas resources in Tarim Basin,” SPE Asia Pacific Unconventional Resources Conference and Exhibition, Brisbane, Nov. 9-11, 2015.
    20. Zhang, D., Kang, Y., Selvadurai, A.P.S., You, L., and Tian, J., “The role of phase trapping on permeability reduction in an ultra-deep tight sandstone gas reservoirs,” Journal of Petroleum Science and Engineering, Vol. 178, pp. 311-323, 2019.
    21. You, L. and Kang, Y., “Integrated evaluation of water phase trapping damage potential in tight gas reservoirs,” SPE 8th European Formation Damage Conference, Scheveningen, Netherlands, May 27-29, 2009.

    The authors

    Dujie Zhang ([email protected]) is a postdoctoral researcher at Sinopec Research Institute of Petroleum Engineering, Beijing, China. He holds a BS (2013) in petroleum engineering and a PhD (2019) in oil and gas field development engineering from Southwest Petroleum University, Chengdu.

    Lei Yang ([email protected]) is a researcher at Chengdu Kangpushen Petroleum Technology Development Co. Ltd., Chengdu, Sichuan. She holds a BS (2013) in petroleum engineering and an MS (2016) in oil and gas field development engineering from Southwest Petroleum University.

    Junbin Jin ([email protected]) is a professor and director in the drilling fluid institute at Sinopec Research Institute of Petroleum Engineering, Beijing, China. He holds a BS (1996) in drilling engineering from China University of Geosciences, Wuhan, and an MS (2010) in oil and natural gas engineering from China University of Petroleum, Beijing.

    Yili Kang ([email protected]) is a professor in the oil and gas engineering department at Southwest Petroleum University, Chengdu. He also directs the formation damage control group in the State Key Laboratory of Oil and Gas Reservoirs Geology and Exploration in China. He holds a BS (1986) in petroleum geology from Daqing Petroleum Institute, an MS (1989) in petroleum geology, and a PhD (1998) in well drilling engineering from Southwest Petroleum University.

    Continue Reading

    Most Read