Water-base fluid cuts environmental costs in Bohai Bay

Caliper log comparison with offset wells shows significant reduction in hole washout and borehole instability between the new WBM (far left) and two wells using a PHPA/KCl water-base system.

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Typically, invert emulsion fluids have been the systems of choice for horizontal, ERD, water-sensitive formations and similarly demanding wells. These formations and well paths require a system exhibiting superb inhibition to minimize the interaction of the fluid with shales and other water-sensitive formations. Further, economics demand the fluids demonstrate high rates of penetration coupled with excellent lubricity to minimize the risk of stuck pipe. For the most part, oil and synthetic-based systems successfully address those requirements, but in many drilling theaters, including Bohai Bay, complying with environmental regulations on the disposal of cuttings generated by invert emulsion fluids increases the overall costs of a program. Consequently, the development of a system that would balance operational and environmental issues has long been a quest of the drilling fluids industry.

Over the years, a number of attempts have been launched to engineer an aqueous system that would come within reach of the performance levels of an invert emulsion drilling fluid. Water-based systems designed around silicates, salt/glycol, partially hydrolyzed polyacrylamide (PHPA), and CaCl2/polymers, among others, have been promising. Nevertheless, they have not been completely successful in inhibiting the hydration of highly water-sensitive clays, all-too-often resulting in bit balling, accretion, wellbore instability, and poor penetration rates. While many of these systems demonstrated satisfactory inhibition, the range of applications was seriously limited. Thus, a major research effort was undertaken to develop a water-based drilling fluid with the performance characteristics of an invert emulsion system.

Early in the fluid development program, it was concluded that merely creating or revamping additives to enhance existing water-based systems would not be sufficient to reach the ultimate goal of engineering a new system that would exhibit the performance flexibility of its oil-based counterpart. A total system approach was initiated that focused on the full performance spectrum of an oil-based mud, rather than centering on one characteristic, such as lubricity, inhibition, or thermal stability. The result was a new water-based drilling fluid that in the laboratory exhibited performance characteristics close to those of an oil-based system and was superior to other aqueous systems.

Triple inhibition

The system was designed through a triple inhibition approach: shale hydration inhibition, shale dispersion inhibition, and accretion inhibition. The drilling fluid comprises five synergistic products, three of which were created specifically for the new system.

Shale hydration inhibition is provided by a polyamine liquid additive that acts as a clay hydration suppressant. The product reduces the space between clay platelets so that water molecules will not penetrate and cause shale swelling. Molecular modeling has shown that the molecular structure of this compound provides a fit between clay platelets and tends to collapse the hydrated structure of the clays, thereby reducing the tendency of clays to imbibe water from an aqueous environment. The component is water soluble, exhibits low marine toxicity, and is compatible with other additives in the system.

A low-molecular weight dry copolymer developed for the new water-based drilling fluid minimizes shale dispersion to provide cuttings encapsulation with minimal viscosity contribution and enhanced filtration properties. It also has been shown to be an effective anti-crete agent.

The system incorporates an accretion inhibitor/ROP enhancer, which is a blend of surface-active agents that will keep the bit and the BHA free of solids. The suppressant assists in preventing the build-up of drill solids below the bit, thereby allowing the cutters to make good contact with new formations and improve the rates of penetration. The additive also lowers torque and drag by reducing the coefficient of friction and provides general improvement in drilling properties.

The system includes xanthan gum for rheology control and an ultra-low viscosity cellulosic polymer for filtration control. Fluid loss control additives vary from ultra-low viscosity PAC to starches, depending on conditions and desired fluid properties.

Researchers performed a number of tests to evaluate the inhibitive properties of the shale inhibitors and the entire system. The test methods included bentonite inhibition, bulk hardness, slake durability, and accretion in various shales and with various base fluids, such as pure seawater, KCl/seawater, and sodium chloride/seawater to simulate global applications. The system was tested against oil-based mud and a 20% NaCl/PHPA fluid. The results showed the system comparable to the oil-based drilling fluid and superior to the water-based system. The conclusions of the tests have since been verified in nearly 150 deepwater, shelf, and land wells worldwide.

CFD drilling campaign

The CFD 11-1/2 development program was initiated in November 1999 and April 2001, with discovery wells CFD 11-1-1 and CFD 11-2-1, respectively. So far, 22 wells have been drilled on blocks to an average total depth of around 7,000 ft (2,115 m) measured depth, where they target the Lower and Upper Minghuyizen, Guantao, and Dongying formations. Once land-locked, Bohai Bay is now a saltwater environment. Its shales were deposited in freshwater, further compounding the reactivity of these young formations. Further, since Bohai Bay lies in a region prone to incessant earthquakes, tectonic stresses have created a number of faults and fractures, magnifying the downhole challenges.

Before the widespread use of the new inhibitive water-based fluid, the operator employed the more field-tested PHPA/KCl system for its vertical exploration wells. In its first applications, the new system was used entirely in the directional development program. However, owing to its performance in the development program, the system was selected for exploration well CFD 23-3-1 earlier this year. That well was drilled some 14.39 fewer days than the planned 31 days, making it one of the fastest-drilled wildcats in Bohai Bay. The performance on that well has since made the new system the operator's fluid of choice for its CFD 11-1/2 development program.

The new system is employed in the 12 1/4-in. intermediate sections with average interval lengths of 4,779 ft (1,457 m). The eight wells drilled in the CFD 11-2 development program required an average of 102.38 hours to drill the 12 1/4-in. section. For the 14 wells drilled in the CFD 11-1 development program, improved capabilities of the Bohai 8 drilling rig, the directional well plans, and targeted formations helped cut average drilling time to 56.77 hours. This timeframe compares favorably to the 50.23 hours required to drill the average 4,694-ft, 12 1/4-in. sections of the best available offsets drilled with an oil-based fluid, thereby attesting to its ability to approach the drilling performance of invert emulsion systems. The new system has provided improved hole stability and reduced washouts experienced with the PHPA/KCl system. Further improved inhibition and less swelling and/or filtercake build-up in certain formations contributed to an average 25% to 30% reduction in back-reaming.

Highlighting the performance improve- ment and capabilities of the new system was the drilling of the CFD 11-1-A20 and CFD 11-1-A11 extended reach wells from the WGP-A platform. The latter was drilled to a Bohai Bay record of 9,850 ft measured depth and 3,519 ft true vertical depth, at an inclination of 78° with the open hole section measuring 7,577 ft. CFD 11-1-A20 was drilled to 9,610 ft measured depth and 3,680 ft true vertical depth at an inclination of 78° with the open section measuring 7,317 ft.

While water-based systems intrinsically have higher dilution rates, the new water-based fluid delivered rates per barrel remarkably lower than the PHPA/KCL system and comparable to oil-based fluid. The average dilution rates of 1.57 bbl of fluid per bbl of formation drilled on CFD 11-1 and 2.48 on CFD 11-2 compare favorably to 2.87 and 3.93, respectively, for the PHPA/KCL system used during the exploration phase on 11-1 and 11-2.

The most striking advantage of the new water-based system, however, is illustrated in the cost per meter drilled as compared to oil-based fluid. For the 22 wells in the oil-based program, the cost of re-injecting the cuttings raised the cost/meter drilled some 2.1 times higher to an average of $365.4 per bbl of open hole. This does not include the costs associated with the average 20.42 hours of rig downtime per well experienced early in the CRI program. As the cuttings generated by the new water-based system were approved for offshore discharge, the operator saved the nearly $5 million incurred in the 22-well re-injection program on the oil-based offsets. ;

Authors

Jim McRae is the director of Drilling and Completions for Kerr-McGee China Petroleum Ltd.

David Bump is supervisor of drilling engineers for Kerr McGee.

Chuck Montgomery is general manager of China Nanhai Magcobar Mud Corp. Ltd., a joint venture between M-I Swaco and China Oilfield Services Ltd.

Rodney Martin is a project engineer for China Nanhai Magcobar Mud Corp. Ltd.