DRILLING TECHNOLOGY Unocal building range of solutions for drilling deep Norphlet environment Producer developing strong bottom hole assemblies, efficient casing design, and 150-day wells
Michael Sprawls
Unocal
Percentage breakdown of tangible and intangible costs on a $31.2 million satellite well with production facilities in the Mobile area of the US Gulf of Mexico.
Unocal has operated six Norphlet exploration wells in five Mobile Area blocks 10-15 miles off the coast of Alabama since 1986. One well, the 90 No. 1, was a directional well and the others were vertical. Four of the wells, the 904 No. 1, the 916 No.'s 2 and 3, and the 961 No. 2, were productive. Three of the productive wells were completed and one, the 961 No. 2, was temporarily plugged and abandoned (TP&A) in April 1995 to allow for the design, order, and delivery of completion tubing and accessories.
A typical Norphlet well for Unocal is 23,000 ft deep and has five strings of casing to TD (including drive pipe). The well is drilled in 170 days and has a dry-hole cost of $15 million. The well is completed in 45 days for $10 million (without production facilities).
Further, because Unocal has two large, main production complexes, somewhat centrally located in the firm's Mobile Area blocks of interest, and because the unproven Norphlet reserves will likely be found in relatively small, fault-segmented paleo sand dunes, the remaining deep wells will likely be satellites.
The 916 No. 3 is an example of Unocal's most recently completed satellite well and is currently the only satellite with production facilities installed. The second satellite well, the 961 No. 2, will have facilities installed late in 1995.
Well design
Unocal's Norphlet wells are designed to accommodate a completion in a 6-in. minimum hole diameter at total depth. Specifically, the design centers around a 5-in. heavy-wall corrosion-resistant alloy (CRA) liner, a full or partial production casing tieback, and 3-1/2-in. CRA tubing. The wells are perforated overbalanced in kill-weight, oil-based mud with 2 3/4-in. hollow-carrier casing guns.
Because of the high incidence of drilling problems in these wells, it is necessary to have a contingent drilling liner, which would double as production casing in a productive well. Other features of the design include a million-plus pound intermediate casing string (again, a portion of which might function as production casing), a surface string which protects the highly reactive Midway Shale, and a conductor and drive pipe section. When these are cemented together, they act as a unit to support the load of all tubulars. A caisson, driven just prior to the rig move off, provides support for the well in a 100-year storm until a platform is installed at a later date.
Drilling challenges
Mobile Area Norphlet wells offer a unique set of challenges which are obstacles to quickly and cheaply drilling the deep wells. One of the biggest challenges is designing drilling assemblies which drill efficiently and stay together in the harsh formations.
While the area is known to be particularly hard on bottom hole assemblies (BHA), it was not completely understood why until the drilling of the 916 No. 3. In the No. 3, a 13-1/2-in. hole (12-1/4 in. had been the standard) was drilled to 17,168 ft using 5-1/2-in. drill pipe and a tapered string of 9-1/2-in. and 8-in. drill collars.
The intent of the larger hole was to accommodate a bigger pipe program which would result in a 5-1/2-in. liner at TD. An attempt was made to improve on previous drilling performances by using a larger drill string to improve hydraulics at the bit and a higher water loss mud (150 cc/30 minutes) to wet and soften the formation ahead of the bit. As it turned out, a high water loss mud aggravated a problem which occurred to Apparently, mud filtrate dissolved or loosened the binding materials in the formation and the formation fell apart under the energy of the highly turbulent circulating mud. In logging the well later, it was later discovered that the hole diameter was greater than 20 in. (the limit of the caliper) from just 150 ft off bottom all the way back to the surface casing shoe.
In an area where the rock is so hard that at 12,000 ft the penetration rate is less than 15 ft/hr, it is hard to imagine that the hole would be anything but a gun barrel. Not only was the hole washing out, but it was washing out significantly around the BHA. As a result, the BHA problems which had occurred in other wells were magnified in this well.
In the 13 different BHA configurations used to drill the intermediate hole alone, there were 34 cracked boxes, five cracked pins, one twist off, two broken drilling jars, nine washouts, and numerous galled and damaged threads. This occurred despite 12 BHA inspections in 27 trips.
The vast majority of those failures occurred while drilling between 8,000 ft and 14,000 ft, where the highly laminated limestone-shale sequences were more prone to excessive washout.
Prior to and through the drilling of the No. 3 well, the focus for solving BHA problems primarily was on improving the bending strength ratio (BSR) of the connections in the BHA and on optimizing BHA geometry (stabilizer placement, number of each size collar, crossover specifications, etc.).
Though it is a good idea to have a thorough understanding of what BSR means, it is equally important to understand that there is a hole size large enough such that no matter what the BSR, the BHA connection will fail. Therefore, mud design and mud flow regimes must be considered when addressing BHA failures in offshore Mobile wells.
Formations in the Mobile Area can be difficult for reasons other than washout. Some of the harsh, unfriendly formations include:
- Highly abrasive sands and pyrite, which reduce bit life
- Fractured limestone just above the Norphlet which is a potential lost-circulation zone
- A massive creeping salt section (the Louann Salt) below the Norphlet, which if drilled is likely to stick the drill string.
Hostile downhole conditions which make these wells challenging are the high bottom hole temperatures (420 degrees F) and pressures (up to 19,600 psi) and the presence of H2S and CO2 in the Norphlet which all test the limits of mud and tools.
In addition to the hostile formations, some of the operations which we chose to conduct, like conventional coring a 6-in. hole at 22,000 ft plus or turning a PDC bit at 1,000 rpms, are challenging, as the nature of these operations increase the chances of sticking tools and/or having a failure which might result in a fishing operation.
Besides being hostile, the area is challenging. Unlike most other areas in the gulf, it is not possible to The problem is that the methods normally used are not accurate in areas where massive carbonate sections are present. So, the exploratory wells are designed for the worst pressure case, which for Unocal is 19,600 psi BHP. To further complicate matters, many of the wells have over-pressured water and/or gas sand compartments which can occur anywhere from 14,000 ft to TD.
Unocal encountered high pressure gas in one and high pressure water in three of its six wells. There is, however, sometimes a slight drilling indication of approaching pressure - bit/BHA torque - which is only relieved by increased mud weight.
On the surface, the area is environmentally sensitive because there are beautiful Alabama and Florida beaches nearby and because Mobile Bay, a zero discharge area, is a few miles away.
Completion challenges
When the well is logged and evaluated, and completion begins, the challenges do not end.
The first big challenge in a completion operation is getting the production liner to TD and adequately cemented. So, what's the big deal? Well, try jamming a rigidly-centralized 5-in. liner in a 6-in. hole, when the water-based mud has been sitting in a CO2-containing, porous media (the Norphlet) for thirty hours at 420F. Then, spot about 10 bbl of cement in a 1/2-in. by 900 ft annulus 4-1/2 miles in the ground. Don't over-displace!
Once the liner is cemented, the fun is still not over. The cement and float equipment is drilled out with a very small bit (make a fist - that's the bit size) on some very small tubulars.
Another challenge in completing these wells is coping with long-delivery, high-dollar tubulars and accessories. In fact, because it is not acceptable to inventory $5 million worth of severe service, special order equipment (tubing - $3,300,000, SCSSV's - $450,000, tree - $600,000), the completion tubulars, and accessories are ordered after the well is evaluated to be commercial.
Consequently, the wells are planned to drill, evaluate, and TP&A with the production liner in place. The rig is demobilized, the completion and production facilities are designed, and the needed equipment is ordered. Six to nine months later, the completion equipment arrives, a rig is moved on, and the well is completed. The rig is then demobilized and the production facilities installed.
Other challenges include perforating small liners in deep, hot, oil-based mud environments and working with oil-based packer fluids because of tubular compatibility constraints.
Achievements
Probably the single most significant achievement is the development of stronger, longer-lasting BHAs. Basically, BHAs are designed with maximum penetration rates and bit life in mind. Generally, that means rigidly stabilized, large drill collars in a packed hole drilling assembly.
The size of the drill collar closest to the bit is chosen by selecting one roughly equivalent in stiffness to the largest shock sub that can be washed over in a given hole size. Fundamentals, as described in the Drilco Drilling Assembly Handbook are applied:
- Drill collar sizes are stepped down to maintain a 5.5:1 or less BSR between adjacent BHA components.
- Core back and stress relief grooves are used.
- Drill collars and accessories are torqued to 20% over the API recommended minimum.
High temperature-high pressure pipe dope is used. Near bit and string roller reamers are used when possible. Roller reamers and/or stabilizers are placed in the tapered BHA such that there are more of the stiffer collars than of the more limber collars between them, and there are an odd number of drill collars between stabilization points when possible.
Connection BSRs are maintained in the 2.75-3.25 range. All drill string components are initially subjected to a service category five inspection as detailed in the T. H. Hill Associates. Standard DS-1 Drill Stem Design and Inspection publication. Subsequent blacklight inspections are performed regularly on the BHA throughout the drilling of the well.
While improvements have been made to the mud design with respect to its effect on hole washout, the efforts met with limited success, and BHA problems as a result of very badly washed out hole (12-1/4-in. washed to 24 in. in some spots) continued to be a problem on the last well drilled, although to a lesser degree than previously experienced.
A failed attempt at fixing a problem, however, improves understanding and makes success in the future much more likely. With that, it can be said that there may be a place for synthetic muds in certain hole intervals for these difficult wells.
Another big achievement is the ability to better match the formation type with the proper PDC or diamond-impregnated bit and mud motor to drill it. Thirty-eight bits were used on the last well drilled, 961 No. 2, where 57 were used on the previous best drilled well, the 916 No. 2.
The 15.9 ft/hr average penetration rate in the former was 46% higher than the 10.9 ft/hr average penetration rate in the later. Additionally, positive displacement and turbine mud motors were utilized in the 961 No. 2 for periods of 328 hrs and 600 hrs, respectively, where only turbine mud motors were used (196 hrs) in the 916 No. 2.
As alluded to earlier, the casing design has evolved into one which is highly efficient. The design of the drive pipe and conductor casing as a unit has saved more than $150,000 over recent wells. Casing shoes are placed to protect from the wide variety of possible drilling hazards, and two of the strings, the intermediate casing and the drilling liner (if run), can double as production tubulars.
In the area of better well planning, Unocal's exploration department is working to identify a method of predicting pore pressures in the carbonate-rich Mobile area. A few other achievements worth noting are efficient logging programs and procedures as negotiated between the drilling and exploration departments, and the implementation of a contractor incentive program which rewards rig personnel for beating a certain agreed-to day curve. These two improvements made it possible to run an intermediate casing string in seven days instead of the normal twelve days.
Summary, conclusions
The Mobile Area is a difficult one in which to drill, and the learning curve is steep. An open exchange of ideas, however, between Unocal and its partner, Chevron, which has drilled a number of Norphlet wells, has been essential to the rapid improvement in understanding the area and how better to drill the wells. For example, it is believed that in the very near future, a typical Unocal exploration well could be drilled and completed in 150 days instead of the current 225 days.
Byron Michael Sprawls is a drilling/workover engineer with Unocal and has eight years of drilling, completion, and workover engineering experience, mostly in the US Gulf of Mexico. He holds a BS in petroleum engineering from Louisiana Tech University (Ruston).
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