ADVANCES IN DRILLING COVERED AT CONFERENCE IN SOUTHEAST ASIA

Recent advances in drilling technology include R new applications for various polymer-based drilling fluids, an analytical evaluation of certain gas control additives for light cement slurries, the use of a new wellhead connector, and the development of a unique completion tool for slim hole wells.

These topics were covered in several papers prepared for the Offshore South East Asia 9th Conference and Exhibition held Dec. 14, 1992, in Singapore.

Drilling fluids formulated with partially hydrolyzed polyacrylamide were used successfully and economically to, control well bore problems in a development drilling program in southeast Asia. Another paper presented results on the use of various cationic and anionic materials to control shale stability problems common to areas offshore western Australia. In studies in Malaysia, certain palm oils have shown some promise as replacements for diesel in oil-based muds.

Another paper presented results of an evaluation of five common additives used control gas migration problems in light-weight cements.

In addition to these fluid topics, recent mechanical developments were covered. A wellhead connector with numerous bolted segments has been used as an easy-to-install, effective replacement for conventional flange and two-piece clamps. A coiled-tubing-conveyed completion tool with a large internal bore has been developed for use in slim hole wells. The tool can isolate several perforated intervals while other zones remain open for production.

PHPA MUD SYSTEM

A drilling mud system with partially hydrolyzed polyacrylamide (PHPA) helped maintain gauge holes in a formation in the South China Sea where well bore enlargement is a problem for wells drilled with other muds.

Drilling problems frequently encountered in this area include deviated holes, hole cleaning, hole enlargement, and stuck pipe. Additionally, typhoons cause a number of drilling shutdowns, leaving formations exposed to the drilling fluid.

In a multiwell development program in Southeast Asia, hole problems during drilling, logging, and running casing were almost completely eliminated by the PHPA mud, according to Terry Heppel and Don Parrish with China Nanhai-Magcobar Mud Corp. Ltd. in their paper, "PHPA Mud System Successful in South China Sea Drilling Project."

More than 35 wells were drilled back to back from a semisubmersible rig in 350 ft of water. None of these wells had any sticking or hole cleaning problems despite a number of shutdowns for weather and for deviated hole problems. The wells typically had angles ranging from 40 to 63.

A number of factors contributed to the success of the drilling operation:

• A change in the casing program helped prevent key seats.
• Good solids control allowed reuse of the PHPA mud.
• Mud properties and hydraulics were closely monitored to maintain laminar flow.
• New mud was mixed with old mud to adjust properties.
• Lubricants were added to control high torque in the well bore.

The exploration wells in the area had problems with high mud costs and hole enlargement during drilling of several highly dispersible, water-sensitive shales. The development drilling program targeted several normally pressured oil zones below 11,500 ft. Thus, the drilling program required a low solids, inhibitive fluid with a low mud weight.

The 121/4-in. section was the most troublesome to drill. This interval consisted of highly dispersible shales with hard limestone stringers in the top and abrasive sandstone in the bottom.

On the first few wells, the active PHPA polymer concentration was maintained at less than 1.0 lb/bbl to minimize mud cost. The effect on hole enlargement in the 12 1/4-in. section was monitored until an optimum concentration of 1.25-1.5 lb/bbl was determined.

In addition to the PHPA, the typical mud dilution included 0.5 lb/bbl soda ash (discontinued with depth), 0.5 lb/bbl caustic soda, 1.0 lb/bbl polyanionic cellulose, 1.0 lb/bbl lignite (for the bottom section), and seawater/ freshwater to control salinity.

After a typical well was drilled for a few hours, the mud properties were the following: mud weight of 8.7 ppg, funnel viscosity of 65 sec/qt, plastic viscosity of 23 cp, yield point of 30 lb/100 sq ft, gels of 10 and 17 lb/100 sq ft, and a pH of 9.3.

Solids control was important to maintain high mud quality. The solids control equipment included three high-speed shale shakers, a desander, a desilter, a 200-mesh mud cleaner, and a low-speed barite recovery centrifuge. The shale shakers were run with 120-mesh and 150-mesh screens for most of the 121/4-in. section.

The average daily rate of penetration increased from 530 ft/day to 692 ft/day because of the faster drilling with the PHPA mud and the fewer problems. The PHPA mud cost was less than the cost for comparable muds on similar wells in the area.

SHALE STABILITY

Cationic polymer drilling fluids can stabilize shales better than conventional mud systems, according to S.S. Rahman and Q.V. Le with the Centre for Petroleum Engineering at the University of New South Wales and P. McNaughton with Baroid Australia Pty. Ltd. in their paper, " Investigation of Drilling Fluid System in Stabilizing Shale Sections in West and North West Shelf of Australia."

Many of the wells drilled into t&e Cretaceous shale sections in the west and northwest shelf of Australia have problems with tight holes and large breakouts. Numerous fluid systems (pure brine, brine with water-soluble polymers, oil-based mud) have been used with varying degrees of success to stabilize these shales. Some of these drilling fluid systems have limitations in properties, applications, and cost.

When a clay formation containing shale is exposed to water-based fluids, the formation hydrates, swells, and disperses or sloughs into the well bore. This chemical interaction is aggravated mechanically and physically by pipe rotation, erosion from fluid circulation, and overburden pressure. These problems can lead to hole enlargement, stuck pipe, and bottom hole assembly balling.

Common deflocculants and polymers can coat the clays to inhibit hydration. These additives are effective if they are run in the appropriate geological area and if they are properly maintained. Without an understanding of the fluid/shale interaction, however, an operator may only, hit or miss the proper application of these chemicals.

Several drilling fluid samples were hot rolled for 24 hr at 120 C. for rheology and filtration tests. The samples were then treated with 18% KCl. The properties of the cationic fluid system remained stable, but the properties of the partially hydrolyzed polyacrylamide (PHPA) and carboxymethyl cellulose (CMC) fluids degraded.

For a cuttings integrity test, shale samples were crushed and added to the hot rolled fluids. The cuttings were then tested for strength with a cone penetrometer. The depth of penetration in the shale from the cationic system was 48% less than that for the shale from the PHPA mud.

The mud samples were hot rolled, and filtrate was collected from an API filter press. Core samples were exposed to the filtrate inside a radial expansion test cell. The amount of KCI needed to minimize volumetric expansion of the core was cut in half by adding anionic polymers. The addition of cationic polymers reduced the KCI requirements even further.

• The potassium ion was the most effective cation in stabilizing Cretaceous shales. However, a high amount of potassium ions in the drilling mud can offset bentonite and anionic polymers used to control rheological and filtration properties.
• Polymers can stabilize shale to some extent by adsorption on the open surface of the shale, by flocculation of the shale particles, and by bridging. The presence of certain polymers can reduce the amount of KCI needed.
• A mixture of nonionic and cationic polymers is the ideal solution for stabilizing swelling shales. The cationic polymer adsorbs on the negative surfaces of the clay platelets, and the nonionic polymers help control rheology.

GAS CONTROL

A mixture of silica and either a copolymer of vinyl alcohol or polyethyleneimine can help control gas flow in lightweight cement slurries, according to Gino Di Lullo and James Tan with BJ Services Co. in their paper, "An Evaluation of Gas Control Additives."

Gas flow after a cement job can result from a poor bond between the casing and the cement or the cement and the well bore or from the loss of hydrostatic pressure as the liquid cement sets. To eliminate these problems, an internal gas-generating additive can be used to produce stable compressible cement slurries or a lattice material can be used to enhance the cement bond.

Proper hole conditioning, mud displacement, and low free water help improve the cement bond at the cement interfaces. However, additives are often necessary to restrict gas flow through the cement matrix. The additives must maintain the cement's matrix pore pressure or fill, bridge, or make impermeable the microcapillaries formed during the setting process.

Compressible slurries maintain pore pressure with additives that generate gas in situ or with foaming agents that form small bubbles with entrained air or formation gas. However, cements with bridging agents are generally preferred to the more complex compressible slurries.

Latex, polyethyleneimine (PEI), liquid fume silica, a copolymer of vinyl alcohol (termed PVAP), and poly vinyl sulfonated copolymer (PVS) are five commercially available additives used to restrict gas flow in setting cement. Cements with these additives were tested in a deviated annulus across an unfractured, low permeability, high pressure gas zone and a low permeability, low pressure water zone. The slurries were first tested according to conventional API procedures for thickening time, free water, fluid loss and rheology.

The latex is a water solution of microscopic particles of styrene/butadiene stabilized with surfactants to avoid flocculation and reaction with the calcium ions. The cement particles control fluid loss by bridging the pore throats. Under applied pressure, the latex particles (0-1-0-25 u) flow with the interstitial water into the pore throats. As gas contacts the latex particles, the surface tension between the gas and solids increases, and the particles coalesce to form a gas resistant film.

The liquid fume silica is a water solution of silica particles with an average size of 0.4 [t. Alone, fume silica will not control fluid loss or gas. However, it does fill and pack interstitial pores to reduce the mobility of fluids to improve fluid loss control. The silica works as a bridging agent providing structural support to common polymers and fluid loss additives.

PVAP is a liquid solution of a chemically modified, high molecular weight copolymer of vinyl alcohol, and it is slightly anionic. As the cement hydrates, the PVAP precipitates to form a film among the cement particles, accelerating the setting transition period. The film is insoluble to hydrocarbons.

The PVS controls fluid loss by polymer adsorption to cement particles, plugging of pore spaces by deposition of a film or filter cake, and by viscosification of the interstitial fluid.

The PEI (30% solution of a high molecular weight polyethyleneimine) controls gas invasion in the cement matrix by gradually increasing the viscosity of the cement interstitial fluid during hydration.

• The ability of liquid fume silica to control gas depends mainly on the elasticity and consistency of the film deposited by the fluid loss additive. Fluid loss additives that are derived from hydroxyethyl cellulose produce a weak film; PEI, PVAP, or PVS should be used instead.
• Although PVS slurries have excellent fluid loss, at concentrations greater than 0.8 gal/sack, they failed all inclined tests. PVS should only be used in conjunction with liquid fume silica for gas control.
• PEI, PVAP, and latex are true gas control additives which can be used to optimize a slurry for any downhole conditions.
• the gas migration properties of latex are only activated when gas enters the cement matrix. The slurry should be carefully designed when latex is used in highly permeable gas zones that contain high concentrations of hydrogen sulfide or carbon dioxide.
• Light weight slurries with gas control properties are somewhat difficult to design. The best results come from combinations of liquid fume silica and either PVAP or PEI.

PALM-OIL MUD

A palm-oil-based fluid has shown some promise for use as a nontoxic invert-emulsion drilling mud, according to Abu Azam Md. Yassin, Mohd Omar Abdullah, and Maketab Mohammed with Universiti Teknologi in Malaysia in their paper, "An Environmentally Acceptable Oil Based Drilling Fluid."

In Southeast Asia, oil-based drilling muds have been widely used for drilling through productive zones and water-sensitive formations. Diesel (No. 1) is typically the base for these fluids, but it is harmful to marine life. Several mineral oils, although less toxic than diesel, used alternatively in these fluids have adverse effects on the benthic fauna. Several local governments no longer permit the discharge of cuttings from wells drilled with conventional oil-based mud.

A number of vegetable oils have been used to formulate muds with characteristics similar to diesel and mineral oil muds. The vegetable oils are generally nontoxic, have no aromatic content, and are available in large quantities.

The basic guidelines for the base oil include the following: low toxicity, low aromatic content, nonfluorescence, low kinematic viscosity, flash point greater than 100 F. to minimize fire hazards and vapors, pour point less than ambient temperature to allow pumping of the mud from the storage tanks, and an aniline point greater than 65 C. to minimize the deterioration of rubber components.

Two palm oil derivatives, methyl ester of palm fatty add distilled and methyl ester of crude palm oil, were tested for Theological properties and toxicity.

• The two palm oil methyl esters had acceptable base oil properties, especially a greater flash point and greater fire point than diesel. The palm oil has a greater pour point, making it undesirable for use in cold climates, but ambient temperature limitations are not a problem in the warm Southeast Asian climate.
• DRILLING MUDS MADE WITH THE PALM OILS HAD GREATER GEL strengths and slightly greater viscosities than conventional oil-based muds. The palm oil muds also had thicker mud cakes and greater volumes of filtrate.
• The palm-oil muds were much less toxic than mineral oil or diesel muds.
• They had greater plastic viscosities and gel strengths than conventional oil muds. However, the use of low viscosity palm oils, the addition of a thinner, or the use of a partial oil/water emulsion may help minimize the viscosity problems.
• The palm-oil muds were sensitive to contaminants (drilled solids, freshwater, artificial seawater, and cement slurries). The effect of contamination should decrease in a low-solids drilling operation.

WELLHEAD CONNECTOR

A segmented-clamp for wellhead connections has better load characteristics and installs faster than conventional two-piece clamps, according to Lee Yeow Chuan with FMC Southeast Asia Pte. Ltd. in the paper, "The Role of Segmented Clamps on Wellhead, Riser, And Tree Connections in Reducing Rig Times and Increasing Safety."

Most platform wellhead assemblies and other drill-through components use conventional two-piece bolted clamps to connect equipment. In sizes greater than 7 1/16 in., the two-piece clamps are large, heavy, and difficult to install, often requiring special handling tools and extra manpower. During make up, the two-piece clamps are often forced into position with a sledge hammer as the studs are tightened. Conventional flange connections require numerous small bolts. Tightening the bolts is time consuming because the access to the bolts is limited.

The forged segmented clamp is smaller and, therefore, easier to handle on the rig floor. A typical 13 5/8-in., 5,000-psi, two-piece clamp weighs about 333 lb, whereas the similar segmented clamp weighs 95 lb.

The clamp is preassembled to the wellhead, riser, or Christmas tree, eliminating the loose pieces when it arrives at the rig site. The segmented clamp can be installed by one man in about 10 min and requires only an impact wrench. Conventional clamps can take hours to install and may require two men.

The clamp's bending moment capacity is equivalent to that for two-piece clamps, and it can be used in sour service and in temperatures from - 75 F. to 250 F.

The segmented clamp is designed for use with conventional API ring gaskets, thus allowing the use of existing drilling equipment with conventional clamp hubs. The outer profile does not interfere with typical cellar or wellhead deck spaces.

The forged segments are mechanically isolated from each other to prevent transmitting hoop stresses. This isolation permits a uniform stress distribution and allows the segments to react independently in proportion to the separation end loads from external bending and internal pressure.

Because the segmented clamp locks to the hub, weight from the blowout preventer or riser equipment is transmitted through the segments and not the bolts.

SLIM HOLE COMPLETION

A slim-wall isolation tool allows selective completion of multiple zones inside slim hole wells, according to Robert J. McNair with Baker Oil Tools U.S.A. in his paper, "A Unique Completion Method for Isolating Production or Injection Zones in Slimhole Wells."

McNair defines a slim hole as a well completed with 3 1/2-in. production casing. The small internal diameter of 3 1/2.-in. casing presents many challenges for future workovers in which selective isolation of zones is required for production.

Conventional completion equipment, such as wire line nipples and plugs, that can be set in 31/2-in. tubing is not viable for slim hole wells. If a plug or nipple is used inside 3 1/2-in. casing and becomes stuck, the well could be lost or an expensive milling job fill result.

The use of sliding sleeves in 3 1/2-in. production casing also has a high risk of failure. When the 3 1/2-in. slim production liner is cemented in place, debris can accumulate in the shifting mechanism, nipple profile, and circulation ports, making the sliding sleeve inoperable. Although the use of larger equipment has similar problems, the risks are less because the ports and mechanisms are correspondingly larger.

An operator in Southeast Asia drilled several slim hole wells and completed them with 3 1/2-in. production tubing tied into 3 1/2-in. casing, essentially making these wells monobores with no open annulus across the production intervals. The wells had several producing zones and several water injection zones with lengths up to 300 ft. The reservoirs were lo", pressure (2,500 psi) and moderate temperature (280 F.).

The completion system had to allow selective isolation of production (gas cap and oil zones) and water injection intervals.

A slim wall selective isolation tool was developed to isolate the lengthy intervals in one run on coiled tubing or electric line. The tool needed an internal diameter large enough to allow passage of through-tubing inflatable equipment or perforating guns.

The 2 3/4-in. OD tool has a 2 1/4-in. ID, which can accommodate the smallest (2.13 in.) through-tubing inflatable electric downhole motor and pump which would be used for setting inflatable bridge plugs in these wells.

The isolation tool uses hydraulically set packing elements and slips and slim hole premium internal thread connections. The tool has hydraulic disconnects to release from the coiled tubing or electric line. The tool can hold a differential pressure of 1,500 psi inside 3 1/2-in. pipe.

Before the tool is run, a retrievable through-tubing inflatable bridge plug is set around 350 ft, and another is set deeper above the safety valve. This safety measure is necessary because coiled tubing or wire line lubricators typically are not long enough to hold the isolation tool when it is set for 300 ft.

With the tool hung in the pipe rams, coiled tubing is then run inside the tool to retrieve the inflatable bridge plugs. After the plugs are removed, the coiled tubing is then made up. on the selective isolation tool and run in the hole to the appropriate depth. Depth control is maintained with a collet attached to the coiled tubing running tool or a collar log when run on wire line.

The isolation tool is then set across an open upper zone. Inflatable bridge plugs can be run through the tool and set below it to isolate lower zones. After an oil zone has watered out or water injection is stopped, the tool can be removed from the well on coiled tubing or wire line.

Copyright 1993 Oil & Gas Journal. All Rights Reserved.