Challenges to drilling subsea, high-angle HP/HT wells

The company defined the reservoir, in a Middle Jurassic structure below the Base Cretaceous unconformity, consisting of three separate sands with highly varying properties. The initial plans called for 60° wells penetrating the low-permeability sand and wells with inclination less than 40° penetrating the high-permeability sands.

As Statoil’s understanding of the reservoir matured, the company realized the reservoir length exposed to the production wells had to be increased for the low-permeability sand with high-inclination wells through the reservoir.

The company’s basic well design was maintained with the production casing landed at 4,500 m (14,764 ft) TVD in the shale above the reservoir. An 8 1⁄2-in. hole was drilled through the rest of the shale and into the reservoir with all hole building from 60° to 85° performed in the 8 1⁄2-in. section.

Another complication arose when essential parts of the completions equipment were delayed, making it impossible to complete the wells immediately after the drilling was finished. The wells were temporary abandoned after drilling, leading to the introduction of a 7-in. (178 mm) liner in the reservoir.

Fluid selection

The most important factors in choosing drilling fluids were:

• Well control
• Formation damage
• Formation evaluation
• Drilling progress
• Fluid stability
• Well completion strategy.

The company originally selected the drilling fluid for the 8 1⁄2-in. sections on Kristin based on the experience of several operating companies with drilling fluids for HP/HT projects and Statoil’s own experience with the Huldra project. The HP/HT oil-base mud (OBM) was to be used to drill the 8 1⁄2-in. (216 mm) sections of the 10 wells that were to be completed with liner and perforated in underbalance. There were also two open hole sand screen wells to be drilled with the fluid, Cs/K-COOH. A change in completion strategy to screens for all wells led to the introduction of the Cs/K-COOH as the drilling fluid for all wells. This change also was motivated by the well control advantages of a solids-free drilling fluid and Statoil’s HP/HT experience with Cs/K-COOH. The invert emulsion HP/HT OBM was used in the 12 1⁄4-in. (311 mm) sections. When washout was experienced in the shale sections using Cs/K-COOH, HP/HT OBM was qualified as an alternative fluid for high angle reservoir sections. The company recognized the danger of plugging the screens for wells that were planned with open-hole sand screens. An invert emulsion HP/HT OBM system with micronized barite as weighing agent was qualified as a reservoir drilling fluid.

Cesium/potassium formate drilling fluid

The cesium/potassium drilling fluid was based on clear cesium and potassium formate brine. The main benefits compared to the following oil based drilling fluids included:

• No sag potential as the density comes from the clear brine itself
• Low ECD
• Less screen plugging risk due to a low level of solids in the system
• The particles in the formate would be CaCO3 for fluid loss control. These particles can be acidized should screen plugging become a problem
• Low gas solubility and enhanced kick detection.

Cesium/potassium formate exhibits low viscosity and goes easily into turbulent flow. This and the buoyancy of such fluids reduce the need to viscosify such a system. For practical reasons, it is normal to viscosify the system with xantan gum to improve hole cleaning and to be able to add filter loss material. The company added starch, PAC, CaCO3, and special HP/HT polymers for fluid-loss control, and recognized that hole stability in regard to swelling of clay was very good as the water activity was very low. One problem was that the low activity of the water dehydrated the formation and occasionally resulted in large washouts. In sand sections, the fluid has very good characteristics and did not influence the hole quality. The fluid loss in the permeable parts of the hole was controlled by adding CaCO3 of various sizes together with fluid-loss polymers.

The fluid normally has a low influence on surge, swab, and ECD due to the low viscosity. Compared to oil-based drilling fluid, the thermal expansion was similar, but the compressibility was lower. So, the equivalent static density (ESD) would be lower than the surface density. The temperature and density properties of the fluid must be monitored to control the downhole ESD. To run screens, Cs/K-COOH was used because the risk of screen plugging would be minimal. Cs/K-COOH also was attractive from a well control point of view since the sag potential is non-existent, the gas solubility is very low, and thermal fluid stabilization is achieved quickly during flow checks.

Invert emulsion HP/HT oil-based drilling fluid

The HP/HT OBM system was based on paraffin, as base oil, weighted with standard API barite. The focus point in the design was a low, flat viscosity profile to reduce the impact of the ECD and to ensure sag stability and bridging capability when exposed to high pressure and temperature. The fluid was successful when drilling the high angle 8 1/2-in. hole on Kristin. Formation damage was acceptable for the wells drilled with HP/HT OBM. This applied to wells completed with perforated liners. Downhole sand screen plugging has been questionable and is the most important factor for avoiding this fluid in wells completed with downhole screens.

Invert emulsion HP/HT OBM with MBS

Invert emulsion fluid consisted of specially treated weight materials to improve drilling fluid performance. The barite was ground to micron size (D50 of 2 micrometers) and coated to prevent particle-to-particle interactions. The fluid had very low viscosity, low surge/swab effect, and good anti-sag stability. The small particle size of the barite reduces the chance that the drilling fluid was less likely to plug downhole screens. Formation damage from this fluid depended on optimization of particle size distribution using plugging materials, such as CaCO3. Formation stability was equal to a standard OBM system.

Formation damage testing

Two different types of formation damage tests were done on Kristin drilling and completion fluids to qualify them for use. First was the dynamic formation damage test, where drilling fluid is circulated in front of the core to simulate drilling and circulation, and overbalance pressure is kept on the core for the duration of the test to allow for seepage loss. Second was the static formation damage test, where a predetermined volume of fluid is injected into the core and the core is shut off.

Several fluid formulations were tested, including different lab formulations and the actual drilling fluid. Test results gave direction as to when to use and where to use these fluids and what is acceptable formation damage.

Field development preparations

The three major issues that must be addressed to develop an HP/HT field are equipment, procedures, and competence. The company compiled an extensive HP/HT well control manual prior to operations. The manual was revised several times in the operational phase based on actual experience.

A key element of the manual was the company’s requirement to perform fingerprinting and well control training prior to drilling the 8 1⁄2-in. section. The fingerprints were designed to map the well response to certain operations.

Fingerprints included:

• Flowback/drainback volume during connections
• Drilling fluid expansion due to temperature increase
• Effect of drill string rotation on ECD
• Surge/swab pressure to break circulation
• Trip tank fingerprint during connections
• Checking ESD vs. PWD measurements.

The well control manual also gave requirements for backup drilling fluid volume and drilling fluid chemicals needed onboard.

Drilling depleting reservoir

Kristin faces rapid depletion after production startup. Continued drilling is dependent on coping with severe depletion. In terms of drilling fluid, the addition of particles to strengthen the borehole wall and/or filter cake to create a stress cage is one approach that has been pursued. Field tests using HP/HT OBM and HP/HT OBM with MBS examined the feasibility of maintaining an elevated concentration of solids in the drilling fluid. The focus of the field tests was on the handling of big bags on the rig and on the shaker screen size selection.

The well was displaced to a drilling fluid pre-blended with a certain distribution of CaCO3 and graphite. In addition, big bags with a pre-blended mixture of various sizes of CaCO3 and graphite designed to replace what was stripped out at the shakers were added to the active system at a rate of 2.95 tons/hr. Thus, a wide range of particle sizes were present in the drilling fluid. The test showed that it is possible to drill ahead and maintain a certain concentration of various particle sizes in the drilling fluid.

Acknowledgments

We thank the members of Kristin BITE. It is their dedication, effort, and professionalism which facilitated the drilling of these wells. We also acknowledge the Kristin partners (Eni, ExxonMobil, Norsk Hydro, Petoro, and Total).

Editor’s Note: This article is a summary of paper SPE 103336 prepared for presentation at the 2006 SPE Annual Technical Conference and Exhibition held in San Antonio, Texas, Sept. 24-27, 2006.

S.A. Hansen, D.H. Breivik, M. Gjønnes, K. Svanes, M. Vujovic, P.E. Svela, O.I. Sørheim
Statoil