A New Approach for Designing an Underbalanced Cementing Plug Using a Managed Pressure Cementing and Pump-Pull Method with Narrow Pore-Frac Pressure Window in HPHT Exploration Well: An Offshore East Kalimantan, Indonesia Case Study

Abstract

The operator was drilling their first high-pressure high-temperature (HPHT) exploration well with narrow pressure window in a swamp area of East Kalimantan. The gas field was discovered in 1977 and production started in 1990. Since then, more than 1500 wells have been drilled in this area yielding a total gas production of 9.7 Tcf. Currently T field enters established mature field status which has quite marginal reserves. Therefore, further exploration is seen as one of the solutions to locate additional reserves to enhance overall gas production. The well was drilled directionally with no offset well nearby. While drilling the 6-in open hole section, an unexpected high-pressure zone was penetrated. The zone condition was made worse by lost circulation and a high gas reading. Two cement plugs were placed using a managed pressure cementing with pump and pull method. The first plug was set by applying surface back pressure (SBP) to maintain equivalent bottom hole pressure (BHP) between lowermost pore pressure (PP) and fracture gradient (FG) at the previous shoe. After pumping 1 m3 of cement into the annulus, pump and pull operations commenced. While performing post job circulation on the first plug, it was observed that the returned fluid density at surface was less than original mud weight, indicating the possibility of contaminant invasion from formation. After waiting for the cement to reach 500 psi compressive strength, pressure buildup was observed when annulus was shut-in, indicating an inadequate pressure seal across the cement plug Applying lessons learned from setting the first plug, new design considerations were implemented such as increasing cement volume in the annulus to 4 m3 prior to the pump and pull operation to minimize cement overlapping risk and applying SBP at BHP near FG. A contingency plan was in place to determine the appropriate SBP value to be applied whenever the pumping rate was changed. A second plug job was performed safely and flawlessly by achieving the top of cement as desired. A successful inflow test was performed with indication of no contaminant invasion nor pressure bypass around the cement plug. The rig was able to continue its next operation to sidetrack the well. This paper presents the design considerations, methodology applied, and lessons learned two managed pressure cement plugs using pump and pull method in a well bore with a narrow pore-frac window where the new techniques were implemented to enhance success of the plug job despite the complexity and risk inherent with an underbalanced operation.

A wellbore fluid performance parameters–temperature–pressure coupling prediction model during the managed pressure cementing injection stage

“…At present, a number of companies have developed their own MPC systems and carried out on-site applications. [6][7][8][9][10] Due to the limitation of field conditions, it is difficult to launch downhole pressure monitoring tools during the cementing process, so the acquisition of wellbore pressure data relies on the prediction through mathematical modeling.…”

“…The study of MPC technology will greatly reduce the cost of cementing, improve the quality of cementing, reduce the occurrence of accidents, and ultimately further improve the level of oil and gas drilling and completion. At present, a number of companies have developed their own MPC systems and carried out on‐site applications 6–10 . Due to the limitation of field conditions, it is difficult to launch downhole pressure monitoring tools during the cementing process, so the acquisition of wellbore pressure data relies on the prediction through mathematical modeling.…”