Comparative Study of Using Oil-Based Mud Versus Water-Based Mud in HPHT Fields
Growing demand for oil and gas is driving the exploration and production industry to look for new resources in un-explored areas, and in deeper formations. According to the Bureau of Ocean Energy Management, Regulation and Enforcement, former Minerals Management Service (MMS), over 50% of proven oil and gas reserves in the United States lie below 14,000 ft. subsea. In the Gulf of Mexico some wells were drilled at 27,000 ft below seabed with reservoir temperatures above 400 °F and reservoir pressures of 24,500 psi. As we drill into deeper formations we will experience higher pressures and temperatures.
Drilling into deeper formation requires drilling fluids that withstand higher temperatures and pressures. The combined pressure-temperature effect on drilling fluid’s rheology is complex. This provides a wide range of difficult challenges and mechanical issues. This can have negative impact on rheological properties when exposed to high pressure high temperature (HPHT) condition and contaminated with other minerals, which are common in deep drilling. High Pressure and High Temperature (HPHT) wells have bottom hole temperatures of 300 °F (150 °C) and bottom hole pressures of 10,000 psi (69 MPa) or higher.
Water-Based mud (WBM) and Oil-Based mud (OBM) are the most common drilling fluids currently used and both have several characteristics that qualify them for HPHT purposes. This paper compares the different characteristics of WBM and OBM to help decide the most suitable mud type for HPHT drilling by considering mud properties through several laboratory tests to generate some engineering guidelines. The tests were formulated at temperatures from 100 °F up to 600 °F and pressures from 5,000 psi to 25,000 psi. The comparison will mainly consider the rheological properties of the two mud types of mud and will also take into account the environmental feasibility of using them.
Key words: Oil-based mud; Water-based mud; HPHT fields
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