The particle blend and size distribution of the designer fluid were optimised to plug fractures and formation pores
New technologies help Statoil drill into a depleted reservoir in a challenging North Sea HPHT field.
Early production of hydrocarbons from HPHT reservoirs while still drilling development wells has the undesirable effect of lowering reservoir pressure. This in turn creates a convergence between pore pressure and fracture pressure in the reservoir and reduces fracture gradient. In such an environment it is easy for overbalanced drilling fluids to fracture weaker elements of the formation, leading to massive mud losses and loss of well control. This was the situation faced by Statoil ASA after drilling nine wells in the Kvitebjørn HPHT gas condensate field, offshore Norway. On the last conventionally drilled well, 34/11-A-2, 140–170 bar of depletion was encountered and massive fluid losses were experienced. The problem was so serious that production operations had to be temporarily shut down in order to avoid further pressure depletion of the reservoir. At this time, there were six further development wells left to drill.
The operator solved this problem by introducing two new technologies for drilling depleted reservoirs1:
1. Managed Pressure Drilling (MPD): MPD is a technique that uses a reduced mud weight and surface controlled backpressure to manipulate the down-hole pressure profile to keep within the narrow ‘drilling window’.
2. Fracture Gradient Enhancement (FGE) or Stress Caging: FGE is achieved by use of a drilling fluid that strengthens the pressure depleted (weakened) sand formations by creating stabilised short fractures that increase the hoop stresses around the wellbore. The fractures are made stable by packing them with special-sized particles and sealing off the mouth of the fracture with an impermeable filter cake2. Such fluids are commonly referred to as ‘designer fluids’.
Designer fluid in Kvitebjørn
Kvitebjørn development wells 34/11 – A-13 T2 and 34/11 – A-12 were successfully drilled in 2007 using the enhanced MPD system, including a formate designer fluid. The fluid was based on 1.81 s.g. / 15.11 ppg cesium formate brine containing a blend of calcium carbonate, graphite and nut plug1. The fluid was designed to contain the optimum particle blends and size distributions to plug the fractures and formation pores.
In order to maintain the formation strengthening effect, the particle size distribution (PSD) of the designed blend had to be monitored and maintained during drilling and fluid circulation. This required a reliable method of monitoring PSD during drilling. In Kvitebjørn, Statoil has used an on-line particle size monitoring system with Focused Beam Reflectance Measurement (FBRM) for remote real-time PSD monitoring3. The improved system measures not only size distribution like most methods, but also particle concentration. The solids-free nature of formate brines can benefit FBRM by helping to ensure accurate measurement and control of particle size distribution and concentration.
Since these first field trials in 2007 a further two HPHT wells (A-03 and A-09 T2) have successfully been drilled in Kvitebjørn using MPD and designer formate fluids.
This type of FGE ‘designer fluid’ based on brine would be useful for strengthening well bores in deepwater fields where low fracture gradients are prevalent and lost circulation incidents are commonplace4.
Increasing hoop stresses around the well bore by creating short stabilised fractures
1. Syltøy, S., et al: “Highly Advanced Multitechnical MPD Concept Extends Achievable HPHT Targets in the North Sea”, SPE/IADC 114484, 26–29 January 2008.
2. Aston, M.S., et al: “Drilling Fluids for Wellbore Strengthening”, SPE/IADC 87130, 2–4 March 2004.
3. Ronaes, E., et al: “Remote Real Time Monitoring of Particle Size Distribution in Drilling Fluids During Drilling of a Depleted HTHP Reservoir”, SPE 125708, 26–28 October 2009.
4. Van Oort, E., et al: “Avoiding Losses in Depleted and Weak Zones by Constantly Strengthening Wellbores”, SPE 125093,4–7 October 2009.