OGJ SPECIAL Practical Drilling Technology Aggressive program, simplicity cut drilling time offshore Trinidad

Enron Gas & Oil Trinidad Ltd. used fundamental drilling practices and an aggressive casing program to cut drilling time and costs on a multiwell project offshore Trinidad. Contributing to the success was Global Marine Drilling Co.'s Adriatic IV jack up, shown with the rig package cantilevered over Enron's Kiskadee platform in 225 ft of water.

About this report

An aggressive casing program, emphasis on simplicity, and sound operational techniques cut the time and cost to drill deep directional wells offshore Trinidad, an article in this Practical Drilling Technology Report shows. Another article covers the successful application of foamed cement to set a liner and isolate problem formations in a deep, high-temperature, high-pressure well in Mobile Bay.

Rounding out this report are two articles on state-of-the-art small diameter bits and positive displacement motors and on a new logging-while-drilling tool that can produce wire line quality sonic logs in real time.

Attention to detail and the use of operational techniques that have been around since the 1960s and 1970s have resulted in the drilling of directional platform wells more than 18,300 ft deep, at up to 58, in just 23 days from spud.

The techniques described in this article reveal neither exciting new technology nor exotic new equipment. Rather, the emphasis of the work was on extracting maximum performance through fundamental application of sound, basic drilling engineering principles.

The techniques used on this project in Trinidad have a broader application worldwide, especially onshore and offshore Venezuela and in numerous other comparable depositional environments.

Simplicity should be a key word descriptive of almost any drilling project, but the word is especially applicable during execution. Design should stay simple during the well planning stage. Whenever possible, an engineer should specify "low tech" when designing and selecting tubulars, materials, wellheads, mud programs, cement programs, directional plans, and completion techniques.

For the purpose of maintaining speed and operational efficiency, the decision-making process should be kept extremely uncomplicated (only the well site supervisor and shorebase drilling manager for almost all decisions) during the drilling execution phase. To effect many advantages of the speed factor, upper management plays a vital role by its willingness to empower personnel at the operational level to make decisions.

Well costs are basically a function of the time to drill and complete a well. Serious problems can adversely affect drilling time curves. Avoidance of problems needs to be part of the well plan, and simplicity is a primary key to avoidance.

Drilling a series of field development wells from a platform offers a number of opportunities and challenges, which are compounded significantly when the zones of interest and production intervals are deep. Such was the case from Enron Gas & Oil Trinidad Ltd.'s Kiskadee platform off the east coast of Trinidad. A nine-slot jacket and deck were set in mid-1993, and in late July 1993, drilling commenced to develop a sand at about 15,300-15,800 ft true vertical depth (TVD). All of the wells are directional, and the measured depths range from 16,400 to more than 18,000 ft, with bottom hole displacements of 5,000-7,000 ft.

Some of the problems encountered and the solutions required to drill wells of this magnitude and complexity (as many as five targets identified for intersection) included the following: casing design (number of strings, size, and setting depth), mud program (selection of a drilling fluid to clean 35-50 well bores and provide enough lubricity to allow rotation of 18,000 ft of drill pipe), optimized use of the drilling rig (for the final few thousand feet of well bore drilled, the top drive was operated at near design limits, and 5-in. drill pipe was nearly at its maximum tension limit), directional design (kick-off points that factored in all target intersections and torque limitations that were imposed and exacerbated by excessive hang-down weight).

These were but a few of the more serious operational considerations that had to be dealt with to drill, and then complete, these wells successfully to total depth.

Drilling in the 1990s can be a difficult game of economic survival. Cost control measures need to be tight for project viability. Successfully drilling and completing wells, which require this amount of operational sophistication, with safety and efficiency on a tight budget is the real challenge. Cooperation and coordination among operator, drilling contractor, and all of the service companies takes on a special meaning with wells such as these. A single weak link in the chain can be catastrophic in terms of time and expense to carry forward.

Kiskadee success

The drilling program from the Kiskadee platform in Trinidad was successful. Enron Gas & Oil Trinidad recently completed a 2-year, 15-well, three-platform drilling program offshore Trinidad's east coast. Global Marine Drilling Co.'s Adriatic IV was used during the project.

Enron's daily production capability from 11 producing wells is 185 MMcfd of gas and 11,000 bo/d. Production is currently curtailed by the purchaser to 150 MMcfd of gas and 9,400 bo/d.

Enron has found that the high level of technical attention required to get these wells down does not require higher and higher levels of applied technical science. Rather, being very basic with standard drilling applications (including mud, cementing, casing, directional work, etc.) is what worked. To be both successful and economical, Enron defined its objective to be on the leading edge of "low-tech."

Drilling performance steadily improved throughout the project. The Kiskadee A7 well was drilled to a total depth of 18,067 ft in just 23 days from spud (Fig. 1 [79315 bytes]). This well was an abnormally pressured, 44 directional well with 6,605 ft of displacement.

Two normally pressured wells without intermediate casing were also drilled from the platform. One of those wells, the Kiskadee A6, was a 47 directional well with 5,578 ft of displacement drilled to 12,537 ft total depth in just 7 days 41/2 hr from spud (Fig. 2 [77783 bytes]).

High levels of performance all around contributed to the following accomplishments:

• A total of 246,996 ft of hole was drilled in 25 months of operation by a single rig. The footage did not come easily: Each well was directional, overpressured, and deep, with an average depth of 16,450 ft.

• Minimal mechanical or equipment downtime was noted for the entire project. Enron recorded less than 10 hr/year downtime on equipment, an incredibly low number. The usual events of lost time associated with drilling rig downtime (waiting on equipment, waiting on orders, etc.) were almost nonexistent for this project.

• During the summer of 1995, the rig crews reached the 1-year mark for no lost time accidents.

• One of the largest factors that can make or break an operator is the integrity of the contractor's drillstring. During the course of drilling some 247,000 ft of hole, much of that directional, there were only a couple of instances of pulling the drillstring for a suspected washout-truly an outstanding record of accomplishment.

• After a misstep on the first well and overspending the drilling and completion authority for expenditure (AFE) by $4 million, a focused recovery was made, and the "lost" money was made up on the subsequent wells. In the end, the entire 15-well project was completed for $12 million under AFE ($80 million actual cost, $92 million AFE cost), including more than $1.3 million under the bid on a difficult turnkey well Enron drilled for another operator.

• Bonuses for outstanding performance were earned by rig crews on 7 of the 15 wells drilled. The commitment was more than just a token-Enron rewarded excellent work with more than $500,000 in bonuses to the rig workers (including toolpushers, electricians, roughnecks, galley hands, etc.) who helped attain the results.

  A number of other drilling accomplishments include some firsts for work offshore Trinidad and some technical feats which may be world records:

• Fastest drilled 171/2-in. surface hole on well IB5 (Fig. 3 [79292 bytes]). The well reached casing total depth at 3,010 ft with an average penetration rate of 365 ft/hr, including connection time. The 171/2-in. hole was drilled from 458 ft to 3,010 ft in 7 hr (which includes 30 min to clean a plugged flow line).

• Fastest 121/4-in. milled tooth bit run on well IB5. A total of 6,296 ft were drilled in 56 hr, and then the bit was pulled after the well drilled through the objective sand and reached total depth. (The longest world record run for a bit of this type occurred in 1991 when a 121/4-in. milled tooth bit drilled 6,490 ft in 110 hr.)

• Fastest 121/4-in. polycrystalline diamond compact (PDC) bit run on well KA6 (9,537 ft in 77 hr to the well total depth of 12,537 ft).

• Deepest, fastest, longest 81/2-in. PDC bit run on well KA7 (3,590 ft in 98 hr, with the depth out at well total depth of 18,067 ft).

• Several record times were set on wells drilled from spud to total depth: KA6, 7 days to 12,537 ft in a 45 well; KB1, 16 days to 16,435 ft in a 23 well (Fig. 4 [74669 bytes]); KA7, 23 days to 18,067 ft in a 44 well; IB3, 23 days to 18,311 ft in a 58 well; and IB5X, 5 days to 9,305 ft in a 15 well.

• Shortest flat spot (2 days) to set 95/8-in. casing on well IB3 at 14,450 ft in a 51 well bore with more than 11,400 ft of open hole (Fig. 5 [79709 bytes]).

  Only 51 hr elapsed time was required, after total depth was reached in the 121/4-in. hole, to complete the wiper trip, run and cement casing, nipple up, change bottom hole assembly and run in the hole, test casing, drill out, perform the leak off test, and drill ahead in the 81/2-in. hole.

• Most hole drilled in the shortest period of time by a single rig was 15,575 ft in 10 days from spud. (The well IB5X was drilled to 9,305 ft to test a fault block, plugged back, and redrilled with a new hole from 3,070 ft to 9,340 ft to test a second fault block. Total depth on the second fault block was reached on day 10 from spud of the original well.)

Keys to this operational success in a remote operating area were good planning and well engineering prior to spud and a lack of downtime. Good on site drilling supervision and rapid decision-making capability contributed to the drilling efficiency.

Operational risks-not chances-were taken to succeed. For example, Enron drilled its 18,000-ft wells into pressure with only four strings of casing (30-in. drive pipe, 133/8-in. surface casing, 95/8-in. intermediate casing, and 7-in. liner), as opposed to eight strings used by other operators to drill to 15,500 ft nearby (42 in., 30 in., 20 in., 16 in., 135/8 in., 113/4 in.,95/8 in. and 7 in.). A four-string program is not without operational risk as it necessitates up to 11,600 ft of directional open hole, but the reward is substantial for success.

The operator used a decidedly turnkey approach to drill these wells. A turnkey operator drills for money, and the size of this paycheck is determined by how efficiently it can drill the well. Although Enron is not a turnkey operator, the conundrum is to mesh that turnkey approach with an operator's objectives.

Some other contributing factors to the success of the Kiskadee drilling project included a good working relationship among the drilling contractor, the local labor contractor, and the unions. Enron has not had any unrest with the labor force or unions in Trinidad. A bonus system provided cash rewards to drilling crews, supervisors, other field personnel, and yard labor for exceptional performance.

These and other factors, primarily such as keeping it simple in Trinidad, enabled Enron to drill and complete its deep Kiskadee wells for $4-6 million each (Tables 1 [25437 bytes] and 2 [26188 bytes]).

Background

Drilling conditions offshore from the southeast coast of Trinidad are much the same over a wide geographical area. The Orinoco River delta empties from the Venezuelan coastline that is in some places less than 20-30 miles away from Trinidad.

Sediments deposited in the Columbus Basin off Trinidad's east coast are of relatively recent geologic age. The Pliocene sediment thickness exceeds 20,000 ft. The Miocene probably extends well below 30,000 ft.

A pressure transition from normal gradient is usually experienced somewhere in the mid-Pliocene. Sandstones, shales, and siltstones typify the stratigraphic sequences. Normally pressured formations extend to deeper subsea strata than might be experienced in other areas.

Major growth fault axes parallel the northwest-to-southeast trending coastline of Venezuela and the Orinoco. Not surprisingly, most of the already discovered gas, oil, and condensate fields in this large sector lie within these northwest-to-southeast trending structures.

Fields and discoveries that fit this generic description both geologically and physically include the Kiskadee, Oilbird, and Ibis fields (Enron has the bird fields), the Dolphin and Marlin fields (one operator has the fish), the Cassia, Immortelle, Flambouyant, Poui, and Teak fields (another operator has the trees), the Southeast Galeota, East Queens Beach, and East Mayaro discoveries.

With all these identified fields and structures there are striking similarities with respect to geologic age of sediments, depositional environment, trapping mechanism, stratigraphy, and pressure regime. The methods used to develop discoveries have been very different, however. This article covers the drilling approach that Enron has undertaken.

Drilling efficiency

The following items influenced the ability to drill efficiently and keep well costs low: drilling supervision, casing program, mud and chemicals, directional services, bits and hydraulics, cementing, personnel rewards, and decision making. These items relate to numerous other subjects that are not commented on individually in this article but which affect a deep platform drilling project.

Drilling supervisors

The drilling supervisor has to have the ability, experience, and good sense to put the well plan that has been provided to him into effect.

The operator should do what it takes to keep the best available person in this position. It should save money in some other area rather than cutting costs on good supervision.

Casing program

When the entire well plan is designed, the casing program dictates what a major portion of the well cost is going to be. As the number of strings of tubulars increases, so do fixed costs for the pipe itself, cement, bits, and rig time (especially if hole opening or underreaming operations are part of the plan).

Staying aggressive while following environmental regulations, but ignoring local standard drilling engineering practices for wells of this nature, has the potential to save rig time and millions of dollars.

Because the pressure transition zone was deep (below 12,000 ft TVD), the longest drilling stretch was to get to the intermediate casing point, without needing to set two intermediate strings. This required 10,000-11,000 ft and more of open hole in a directional well.

There is, of course, not much appeal to this amount of open hole under normal circumstances, unless the potential gains are great enough to justify the operational risk. Particular attention to the mud properties and some specialized techniques have helped push the limits of this section successfully.

During platform development drilling, the opportunity exists to consider elimination altogether of a conductor string. Too many factors come into play to discuss in this article, but this 20-in. string was eliminated in five out of the first eight wells drilled from the platform, with savings in the order of hundreds of thousands of dollars.

Enron's approach contrasts with more conservative well plans that have been used in Trinidad on similar wells to Pliocene targets (Fig. 6 [79072 bytes]). The AFE cost of tubulars alone for those wells, which used 42-in., 30-in., 20-in., 16-in., 135/8-in., 113/4-in., and 95/8-in. casing (not including 7-in. liner and tieback string), exceeded $3.5 million for measured well depths of 16,000 ft.

The total actual expenditure for the Kiskadee A7 well tubulars, consisting of 30-in., 133/8-in., and 95/8-in. casing (and also excluding the 7-in. liner and tieback), was $515,000 for a well that was drilled to 18,067 ft. The entire drilling cost of the Kiskadee A7 well from spud to total depth, including all tangible and intangible expenses, was $2.931 million. There is a payoff for being aggressive and making the plan work.

Mud and chemicals

During the drilling of the first well (Kiskadee A1) from the platform, a major lesson was learned about how critical the drilling fluid properties are to the success of the well.

Stratigraphically, it was found that the interbedded sands, shales, and silts tend to be more sandy and silty than shaley. Unloading cuttings from the hole, especially if fast rates of penetration are planned, becomes critical.

There were several sand packages in the 11,000-13,000 ft depth range that have more than 1-darcy permeability. These high-permeability sands represented a major opportunity for stuck pipe. The lethal combination of poor hole cleaning, high penetration rates, a 44 well bore, a highly permeable sand, and a poorly selected intermediate casing point resulted in differentially stuck pipe on the Kiskadee A1.

Almost 5,000 ft of hole was lost and had to be redrilled, but several valuable lessons were learned. Enron then began spending much time ensuring that precise mud system properties were maintained. A very simple lignosulfonate mud system was used to keep costs low and maintenance easy. The key was to keep that very simple system controlled to within a tight band of parameters.

Some of the most significant procedures included the following:

• Keep the variety of additives to a minimum, with the purpose of each one strictly defined. Let someone else experiment with new products.

• Pay particular attention to the mechanical separation equipment, how it is manifolded, and how pit-to-pit transfers of cleaned mud are made.

• Bentonite was the most important additive to the system. Run concentrations were of 26-30 lb/bbl, which may be as much as double what might otherwise be considered "normal" usage.

• Keep the Fann 3 and 6 rpm readings at 10-12 lb/100 sq ft for the mud in the 121/4-in. hole and at 6-8 lb/ 100 sq ft for the mud in the 81/2-in. hole

• Dilute often, and never let low-gravity solids exceed 6%, even during fast drilling in the top hole.

• Maintain pH very low, in the 8.5-9.0 range.

By using these general guidelines, mud bills for a typical 16,000-18,000 ft well were always significantly under $500,000.

Keeping the drillstring torque at an acceptably low enough value to rotate the pipe was a challenge on these deep wells. Drilling fluid lubricity was exhaustively tested in the laboratory to find the best properties. There were several factors entwined that had to be delicately combined "to finesse" one of these wells to total depth.

The rig's top drive reached a maximum at 1,000-1,050 amps. The premium 5-in., 19.5-lb/ft S135/G105 combination drill pipe string was rated at 561,000 lb tensile strength. Even with buoyancy factored into the calculation, often less than 100,000 pounds remaining overpull was available for the last few thousand feet of drilling.

How does one keep a roller cone bit on bottom when the torque sensitivity at the drill floor 31/2 miles up and 11/2 miles displacement away from the bit is nonexistent? How does one keep a PDC bit on bottom when the extra amperage that the drag bit introduces cannot be tolerated by the top drive?

How does one drill with a motor when after slacking off 5,000 lb on surface, the stabilizer that has been hanging finally breaks loose and dumps 40,000 lb on the bit and stalls the motor?

How does one get a bit out of a tight hole when the top drive is totally useless for backreaming because the extra 50,000 lb of tension gained with the bit off bottom sucks the pipe into the wall of the well bore, resulting in too much torque to rotate?

How does one keep from wearing out the intermediate casing while rotating and tripping with hundreds of thousands of pounds of hang-down weight below the kick-off point?

The answers to these questions revert back to paying strict attention to techniques and practices:

• Maintain the lubricity of the drilling fluid at optimum levels using Soltex, gilsonite products, or lubricants as necessary.

• Drill as rapidly as possible. The high rate of penetration helps with hole problems because there will be less time for hole deterioration

• Keep the curves and doglegs out of the well bore. The goal for dogleg severity should be 21/2/100 ft. This low dogleg severity will help reduce torque and casing wear.

• Limit intermediate casing wear during pipe rotation with the introduction of plastic beads to the drilling fluid at 4-6 lb/bbl concentrations. A bead recovery system downstream of the shale shakers was required. Beads served the dual function of limiting torque and reducing casing wear.

• Consider the use of nonrotating drill pipe protector rubbers across the build section that is behind pipe to further reduce torque.

• Consider the use of higher strength drill pipe (5-in., 25.6-lb/ft S135 or 65/8-in., 25.2-lb/ft S135) at the top of the string to increase the margin of overpull.

Clearly there are reasons for the different methods various operators have used to drill in Trinidad. The good news is that the wells can be drilled successfully, consistently, and efficiently by using good drilling practices and good planning.

Directional services

The points in the previous sections indicate how critical torque can be. Torque can be minimized as drilling progresses by making the kick-off point as deep as possible, keeping the build trajectory very smooth, and minimizing up/down and left/right walk. More motor drilling and higher directional services costs are one compromise to minimize torque.

In an unusual step for an operator, all bottom hole assembly (including stabilizers, pony collars, subs, nonmagnetic drill collars, etc.) equipment was owned by the operator. This policy allowed for minimizing the number of connections in other custom bottom hole assemblies. It also allowed having a preferred connection type with more desirable bending-strength ratios.

A part of directional services, which is directly related to overall well costs, was the number and size of targets that must be hit. One way to minimize well costs was to work out the best compromise possible with the explorationists for the largest targets acceptable.

Bits and hydraulics

Money can be saved in the big hole sizes by using the least expensive bits possible. For the 26-in. and 171/2-in. holes, type 1-1-1 soft formation, nonsealed bearing bits should be used.

With PDC bits in 121/4-in. and 81/2-in. hole sizes, Enron Gas & Oil Trinidad has found that hydraulic horsepower per square inch (hsi) was just as important as flow rate in maximizing penetration rates. One should aim for at least 2.5 hsi in the 121/4-in. hole and 3.5-4.5 hsi in the 81/2-in. hole.

With roller cone bits, the flow rates can be reduced somewhat, although rapid penetration is more effective at reducing hole washout than is a reduction in annular velocities from lower circulating rates.

Cementing

As with almost everything else in this project, the less complicated the cementing recipes and procedures were, the better the chances for success.

The lead slurries for the 20-in. conductor and for the 133/8-in. surface pipe were Class G cement with 4% prehydrated gel in the mix water at 100% excess of the open hole volume. Class G neat cement with a small amount of retarder, if required, was used for the tail slurry.

For a 4,000-ft liner, zonal isolation was critical. Cement was circulated up to the liner lap for a good seal. A basic Class G slurry at caliper volume plus 30% excess was used.

Bottom hole temperature was about 230 F. A silica flour slurry was not used unless temperatures exceeded 250 F., however.

Positive standoff turbolators were effective at two or three per joint across the pay zone and in the liner lap.

Personnel rewards

Since drilling operations commenced in July 1993, there have not been labor problems or any serious drilling-contractor rig equipment problems. It is believed that neither of these occurrences was a result of chance.

The attitude of the workers and crews is reflected from the attitude that management shows to them. Workers appreciate a safe, clean workplace where the food is good. People will generally work as hard as they are requested to work, and they can only work hard when the tools and equipment provided function properly. Rig maintenance and crew performance has been high because it is expected.

Everyone likes a "pat on the back" for a job well done, but a cash reward is much better received and remembered. The crews knew that outstanding performance, which results in reduced drilling times and lower well costs for the operator, would generate a bonus check to each man. Cash did not go to the contractor; it was paid directly to the individual employees who did the work.

Keeping crews motivated has generated big savings for both the drilling contractor and operator. On seven occasions in the past 25 months, the crews earned bonus money totalling more than $500,000 (for millions of dollars of savings in well costs for the operator).

Decision making

The ability to make rapid, on-the-spot decisions had a big impact on the operator's and contractor's abilities to cut drilling costs. Operational decisions should be kept as close as possible to the source of the activity at all times.

In this case, the source was at the drilling rig, and the drilling supervisor must be empowered to make as many decisions as possible. Speed was of the essence in decision making.

Results

The more difficult and complex a well plan, the more important it becomes to stay simple and basic for the execution phase. By refining practices and techniques that have been around for many years, it was possible to drill some very difficult wells to total depth in what may be world record drilling times.

It is generally recommended here to avoid state-of-the-art, high technology for these deep, directional wells and concentrate on extracting the maximum performance achievable from the old standard methods. The most important aspect about getting these wells drilled successfully, safely, and economically was to do whatever it took to get the best people available for the project. A good well plan with due consideration being given to an aggressive casing program was essential.

Torque was the enemy. On an 18,000-ft well, torque had to be minimized in every conceivable way with the directional plan, mud system, and mechanical methods (plastic beads, nonrotating protectors, etc.).

The style used by turnkey drillers can potentially save large amounts of money during the course of a well. When contractors, service companies, and drilling crews perform in an outstanding manner, recognition is justified. Recognition in the form of cash awards pays back big dividends to the operator.

The Author

Gary L. Wallen works for Enron Gas & Oil Trinidad Ltd. in Port of Spain, Trinidad. He has worked for Enron for the past 3 years in Trinidad, first as drilling manager and now as operations manager. He previously worked internationally for Sedco Inc. for 11 years in the North Sea, Algeria, Spain, Holland, Libya, Tunisia, and Morocco.

With Sedco, Wallen worked as a roughneck, derrickman, drilling engineer, assistant rig manager, and then rig manager of a semisubmersible. After working for Sedco, he worked 2 years for Triton Turnkey on turnkey drilling projects onshore and offshore in the Gulf Coast, New Zealand, and Korea. He then worked for Nicor as drilling and production manager in Denver for 4 years.

Wallen earned a degree in petroleum engineering from the Colorado School of Mines in 1974.

Copyright 1996 Oil & Gas Journal. All Rights Reserved.