Oil-Based Muds for Reservoir Drilling: Their Performance and Cleanup Characteristics
- J.M. Davison (M-I LLC) | M. Jones (M-I LLC) | C.E. Shuchart (Mobil Technology Co.) | C. Gerard (M-I LLC)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- June 2001
- Document Type
- Journal Paper
- 127 - 134
- 2001. Society of Petroleum Engineers
- 2.4.3 Sand/Solids Control, 2 Well Completion, 5.3.2 Multiphase Flow, 5.1 Reservoir Characterisation, 1.11 Drilling Fluids and Materials, 6.5.3 Waste Management, 1.11.2 Drilling Fluid Selection and Formulation (Chemistry, Properties), 2.5.2 Fracturing Materials (Fluids, Proppant), 1.6 Drilling Operations, 2.4.5 Gravel pack design & evaluation, 1.8 Formation Damage, 1.6.9 Coring, Fishing, 4.1.2 Separation and Treating
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This paper evaluates the performance of a standard oil-based mud (OBM) to drill horizontal wellbores, concentrating on its formation-damage characteristics and the flow-initiation pressures (FIP's) required for production to flow through the filter cake. For heterogeneous reservoirs, damage is relatively low in low-permeability rocks, but the FIP is high. Conversely, for high-permeability rocks, the FIP is low but formation damage is relatively high. If the drawdown pressure available from the reservoir is low, the scenario exists where inflow will occur predominantly from the higher-permeability formations, which could be damaged badly, but little inflow will occur from relatively undamaged lower-permeability rocks. In terms of maximizing production, this is obviously a less-than-optimal scenario.
Evaluations of cleanup fluids were conducted to gauge their effect on lowering the FIP of OBM filter cakes. Various fluids were screened for their mud-removal performance, which would indicate potentially good OBM "chemical breakers." Mud parameters such as oil:water (O:W) ratio, base-oil type, and emulsifier content all affected the efficiency of the cleanup fluids. The best cleanup fluids were used then in a series of core tests to evaluate their effectiveness in reducing the filter-cake FIP. Reductions between 25 and 40% were possible, although parameters such as soak time and overbalance pressure were critical to their success.
Increased inflow area offered by a horizontal wellbore over a vertical wellbore, and hence the greater productivity available, has led to a large increase in the drilling and completing of horizontal wells. These wells often are completed with open holes where screens either with or without gravel packs are used. Where the ultimate goal of the drilling and completion phase is to minimize the skin and maximize productivity, the drilling fluid can have a major impact on achieving this aim.
Various laboratory evaluations of drilling-fluid performance, in terms of the formation damage and FIP, have been reported in the literature.1-7 Although both water-based mud (WBM) and OBM results have been reported, there has been a relative emphasis on the former, particularly sized-salt and polymer-carbonate drilling fluids. This paper aims to assess both the formation damage and FIP for an OBM applied to a variety of reservoir rock permeabilities and to assess the use of displacement/cleanup fluids. Performance advantages of OBM, such as the lubricity, shale stability, and fluid loss and filter-cake characteristics, can make them particularly suitable for reservoir-drilling applications. However, if the design of the completion phase involves the use of a water-based brine or gravel-pack fluid, then the engineering of the fluids and displacement procedures will have a significant impact on the overall success of the completion (i.e., minimum skin).
Displacement efficiency will depend on the hydrodynamic characteristics of the drilling and displacement fluids as well as the chemical interaction of the drilling and cleanup fluids. This paper evaluates some properties of the drilling fluid that control the efficiency of these cleanup fluids. Cleanup fluids also are evaluated for their efficiency in reducing the FIP needed to initiate flow from reservoir rocks. Where the FIP of the filter cake is higher than the flowing pressure available from the reservoir, it will be necessary to reduce the filter-cake FIP to achieve inflow from as large a section as possible of the horizontal wellbore.
OBM Formation Damage and FIP
A variety of rock types covering a range of permeabilities were used as substrates to evaluate the formation damage and FIP for OBM in heterogeneous reservoirs. These are listed in Table 1. Core plugs 25 mm in diameter and 30 mm in length were used throughout this study. The cores were vacuum saturated with brine, then flushed with Isopar L, a highly refined, isoparaffinic kerosene. The cores are brought to residual water saturation using Isopar L at a flow rate of 7.67 mL/min. For the formation damage and FIP tests, the permeability of the cores was measured at imposed constant flow rates of 2, 4, and 6 mL/min. For all the flow rates, the pressure drop across the core was measured by a pressure transducer fitted to the inlet of the core holder. Permeability of the core plugs was calculated by plotting the pressure drop vs. flow rate and curve fitting the data points.
After measuring the initial permeability of the core plug, drilling fluid was placed in the cell, and the core was exposed to the mud at a temperature of 180°F, a differential pressure of 500 psi, and dynamic filtration at 150 rev/min for 3 or 17 hours.
After the mud-filtration phase, permeability to Isopar L was measured again, flowing in the production direction, using the same flow rates as used to measure the initial permeability. As backflow was imposed, a peak in the pressure was observed, which appears to correlate with cake rupture.1,2 This pressure peak has been used by some authors as an explicit value to signify the reservoir drawdown needed to initiate flow through the drilling-fluid filter cake.1,3 Others use the difference in peak pressure with the equilibrium flowing pressure in the damaged core and define this as the FIP.2,4 Following Alfenore et al.,3 in this paper we will use the overall pressure peak, FIPpeak, as the drawdown needed to initiate flow from the reservoir and FIPeq as the pressure where the FIPpeak is adjusted for the equilibrium flowing pressure (Fig. 1). The recovered permeability is the difference between the equilibrium flowing pressures before and after the mud-filtration phase and is a measure of residual damage.
Table 2 lists the drilling-fluid formulations used. A standard OBM using a low-toxicity mineral oil was the base fluid. The drilling fluid had an O:W ratio of 75:25 and mud weight of 10.53 lbm/gal (barite-weighted). As well as the various mud products needed to make up the fluid, Rev Dust (calcium montmorillonite) was added at 15 lbm/bbl concentration to simulate drilled solids. The drilling fluid had an API plastic viscosity (PV) of 31 cp and yield point (YP) of 21 lbm/100 ft2.
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