Offshore Report

Petronius teaches new lessons, extends ERD technology

ChevronTexaco’s innovative project in the deepwater Gulf of Mexico has stretched the capabilities of extended reach drilling, to four miles in some cases, while enabling improvements in well planning, rig design and drilling practices

 William (Bill) Rau III and Chase Hinson, ChevronTexaco, New Orleans

 An ongoing development program in the deepwater Gulf of Mexico has offered the operator an opportunity to achieve new performance levels by using extended reach drilling (ERD) while also saving money. Over the last several years, ChevronTexaco has been able to develop reserves at Petronius field that otherwise would have been bypassed or required more expensive subsea development.

 While drilling extended reach wells, the firm achieved a number of significant successes and learned new lessons with further applicability. These achievements involve rig improvements, casing design and running, drill string design and failure prevention, hole cleaning, a mud and lost circulation material (LCM) program, equivalent circulating density (ECD) and hole stability control. It should be noted that completion of these extended reach wells presented unique challenges, although these situations are excluded for purposes of this discussion. 

  FIELD HISTORY

 Petronius field is a deepwater development in Viosca Knoll Blocks 786, 830 and 742 of the Central Gulf of Mexico. As operator, ChevronTexaco has a 50% working interest, and Marathon Oil holds the other 50%. The field is 130 mi southeast of New Orleans and 100 mi south of Mobile in 1,750 ft of water.

 The first appraisal well was drilled in 1995 by a semisubmersible rig. An appraisal program confirmed the discovery, and a field development project was approved in August 1996. An aggressive project timeline followed. Six wells were pre-drilled using a semisubmersible through a well template, with one well pre-completed.

 In that well, 20-in. conductor pipe was set, and the first well location was pre-drilled to 1,000 ft, bottom mixed layer (BML), for the remaining 15 template well slots. A compliant tower was installed in 1998 that (to this date) remains the world’s tallest freestanding structure at 2,001 ft. First production was achieved in July 2000.

 During 2002, daily oil production averaged 48,700 bpd and 71.9 MMcfgd (approximately 26,500 net boed). There are 21 slots on the compliant tower platform. Sixteen wells have been drilled, including six extended reach wells that have had vertical sections ranging between 14,956 and 21,636 ft, Table 1. 

  RIG PERFORMANCE AND UPGRADES

 For platform drilling and completion, the rig chosen was a 3,000-hp platform drilling rig, the Ensco 25, Fig. 1. Rig crews and supporting personnel worked 454 days without any environmental or safety incidents prior to having a recordable accident in March 2003. This outstanding H,E&S performance record may have been due to a total commitment by the operator and drilling contractor to incident free operations (IFOs). 

Fig. 1. The operator and drilling contractor maximized the rig’s mechanical limits and made several upgrades to its capabilities before drilling commenced on the Petronius platform.

 The rig’s mechanical limits were maximized for the extended reach program. Prior to attempting to drill and complete some of the Petronius field wells, the following upgrades were made by the operator:

•  One additional 1,050-kW generator set was added.
•  A flow line from the sand trap to the mud pits was added and modified, increasing capacity to 1,400 gpm
•  Derrick finger capacity was increased to handle 279 stands of 5-7/8-in. drill pipe, +/- 25,389 ft.
•  The SCR circuit system was upgraded. Air conditioning of the rig floor motor control center (MCC) was also added for accessory equipment, such as the cuttings dryer, vacuum, etc.

 These upgrades allowed the operator to drill one Petronius field well as a 12-1/4-in. hole to a 24,127-ft MD. 

  CASING DESIGN AND RUNNING

 A typical casing program and well profile are shown in Fig. 2. Directional drilling begins almost immediately below 20-in. casing pre-set at a 3,141-ft MD/ 3,141-ft TVD. A build rate of 2°/100 ft is used to build up to 70° or greater. The build section is cased off with 13-3/8-in. casing set at a 6,500-ft TVD. A long tangent section is then drilled with 11.5-ppg synthetic-based mud (SBM), to control wellbore stability. At 10,000 ft, TVD, 9-5/8-in. casing is set, and the mud weight is cut to 10.3 ppg to drill the regressed pay sand interval. A 7-in. production liner is run at total depth drilled to protect the reservoir.

Fig. 2. In this typical Petronius casing program and well profile, directional drilling begins just below pre-set 20-in. casing.

 The 9-5/8-in. casing is 53.50-lb, L-80 & Q-125. Hunting’s BOSS connections are used in the top of the casing string through the build section. These connections are made up to withstand 50,000 ft-lb of torque. Early in the drilling program, the operator made up the casing connection torque resistance to 40,000 ft-lb, but there was one occasion, where a 958-in. joint backed out during a fishing operation. This resulted in significant trouble time.

 After that event, the plan was changed to 50,000 ft-lb. In the open hole where drilling torques and bending stresses are less, the operator used Hunting’s SEAL LOCK Semi Flush (SLSF) and made up these connections to 18,000 ft-lb. To rotate and ream the 7-in. production liner, crews ran 29-lb, P-110 grade with Hydril 513 connections in the production liner segment of the hole. 

 Designing the casing to withstand drilling and/or production loads is one issue – getting it to bottom at reaches of more than 4 mi is another. One cannot overemphasize the importance of performing detailed drag modeling in advance, to see if it is even possible to get the casing to bottom. Much of the credit for the drilling program’s success goes to K&M Technology, as well as to Schlumberger, for helping the operator conduct detailed modeling and extensive monitoring of the wellbore conditions. This ensured that there were no surprises while trying to run casing.

 At some depths, the hookload capacity is simply not enough to overcome the frictional forces realized with such high-angle hole and wall contact. An iterative process was used in the modeling – which evaluates different casing weights and available processes (such as floating casing and employing drag reduction devices). This process helps to make sound engineering judgments as to which casing string design and tools should be employed.

 The pre-drill K&M models showed that some casing string weights would be impossible to reach to TD bottom in the plan. Accordingly, the operator used Weatherford Lo-Drag centralizers in the 9-5/8-in casing and Weatherford Lo-Torque/Lo-Drag centralizers in the 7-in. liner to help reduce torque and/or drag. Good success was achieved with these products, as well as a Baker Uniflex liner hanger on the 7-in. production liner. The products combined to afford the capability to ream the casing to bottom, if needed. The liner hanger also provided an ability to rotate the casing while cementing, as will be discussed later. 

  DRILL STRING DESIGN AND INSPECTION

 Drill strings were designed by the operator with the philosophy that the rig would not be able to pull or twist pipe in two, as fishing at these high angles and deep depths would have been difficult and costly. An attitude and mindset of no drillstring failures was also adopted. Nothing went into the hole that had not been inspected to DS-1 Category 5.

 Pipe was also required to have 90%-to-95% remaining wall, because a conventional premium rating for drill pipe would likely have been insufficient to provide the margin of error required for this drilling program. Chromium-based hard-banding was required on all drill pipe to reduce both torque and casing wear, in addition to protecting the pipe. 

  HYDRAULICS AND WELL BORE CLEANING

 Wellbore cleaning and good hydraulics were critically important in these high-angle wells. To match the mechanical targets, as well as to ensure adequate hydraulics, the following drill pipe design was chosen: 

•  A full string of 5-7/8-in. pipe with 6-5/8-in. heavyweight drill pipe (HWDP) in 17-1/2-in. and 12-1/4-in. hole. The deepest 12-1/4-in. hole to date is 24,127 ft, MD/10,200 ft, TVD, on the A21 well, with 13-3/8-in. pipe set at 7,894 ft, MD. 
•  A full string of 5-in., 19.50-lb S-135 drill pipe in 8-1/2-in./9-1/4-in. hole. The deepest of these holes to date is 27,107 ft, MD/11,547 ft, TVD. 

 With the ODs and IDs provided by this drill pipe design, the following mud and drilling fluid flowrates were achieved, which better ensured adequate hole cleaning: 

•  1,200 to 1,400 gpm in 17-1/2-in. hole
•  900 gpm in 12-1/4-in. hole
•  450 to 550 gpm in 8-1/2-in./9-1/4in. hole.

 As many studies have shown, in addition to good hydraulics, bit rotation is required to clean the hole. It has been observed in drilling numerous ERD wells that a step change in cuttings transport efficiency occurs with bit rotations above 100 to 120 rpm. This might not always be possible due to BHA restraints and/or rig equipment constraints.

 For Petronius wells, the operator adapted the following guidelines that proved effective: 120 rpm in 17-1/2-in. hole and a minimum of 90 rpm in 8-1/2-in./9-1/4-in. hole. Schlumberger’s Power Drive Rotary Steerable System (RSS) was also used in the 8-1/2-in./9-1/4-in. hole to allow for high rpm and continuous rotation. This kept the cuttings stirred up and suspended in the drilling fluids.

 Instantaneous ROP was also limited to volumes that could be adequately transported out of the hole. Although pressure-while-drilling (PWD) data were used to monitor ECD as an indicator of hole cleaning, it was found that monitoring torque and drag on connections was of greater value in determining if wellbore cleaning was adequate. Short trips were minimized, if not eliminated, as they were found to be of minimum value. Short trips could actually contribute to wellbore instability by swabbing and surging the formation. 

  MUD AND LCM PROGRAM

 In the surface hole, 9.6 low-lime seawater mud was used. Below the 13-3/8-in. surface casing, MI’s Novaplus SBM was the product of choice. Some of the things that worked well included:

•  Use of MI’s Virtual Hydraulics program to design drillstrings that would maximize flow rates, minimize ECDs and optimize daily drilling decisions concerning ROP and hole cleaning, mud properties, etc. 
•  Incorporating Ecotrol Fluid Loss Additive for better fluid loss control and filter cake.
•  Using VG Supreme anti-sag organophillic clay to prevent barite sag, and running Viscometer Sag Test to monitor barite sag potential. 

 Use of the right LCM mixture in the right application is also crucial. This is especially true in high-angle, extended-reach wells, where shale break-out is likely. Using the LCM products actually enhanced borehole stability. In addition, mud technical experts from ChevronTexaco’s internal Drilling Technology Center (DTC) in Houston were asked to help select the correct mixtures.

 One of the tests routinely run by DTC is the Particle Plugging Test (PPT) that determines the fluid loss and filter cake produced by an LCM mixture. The PPT is more accurate than standard API and high-pressure, high-temperature (HPHT) testing, as the disks used in testing had permeability similar to that likely to be encountered in the well.

 In general, the LCM program that has been used successfully is as follows:

•  Fine and medium cellulose fiber, plus fine and medium calcium carbonate in background at 20 lb/bbl 
•  Sweeps every third stand, containing course cellulose fiber, course calcium carbonate and MI G-seal at 50 lb/bbl 
•  Pre-spud PPT qualification testing of products by the DTC.

 The operator is so convinced of the benefits of PPT testing, that crews often run daily tests offshore, which is not routine for most of the firm’s operations in that area. 

  ECD AND HOLE STABILITY MANAGEMENT

 One of the primary questions or concerns with extended reach wells in deep water is managing the frac gradients and preventing hole collapse caused by shale break-out. For this situation, wellbore stability modeling was used to predict the mud window that would allow the well to be safely drilled. While the well was drilled, Schlumberger’s No Surprise Drilling Services was used to monitor drilling and casing running to validate the models, and to monitor real-time for any potential problems that might develop.

 To help reduce ECD, a bi-centered 914-in. hole was drilled. The 8-1/2-in. by 9-1/4-in. bi-center bit was run on Schlumberger’s Power Drive Direct Point the Bit Rotary Steerable Assembly. Schlumberger told ChevronTexaco that this was the first time that this combination was tried anywhere in the world.

  CONCLUSIONS

 ERD operations at Petronius enabled ChevronTexaco to reach reserves that normally would have been sidestepped or required costly subsea schemes. Reaches in excess of 4 mi were, and can be, achieved. However, careful planning and execution are required for these wells to be drilled effectively and efficiently. Ongoing improvement and cost reductions can be realized by continuing to use new technologies, as well as learning from experience and from other operators who continue to push the edge.  

THE AUTHORS
	William E. (Bill) Rau III graduated from Tulane University in May 1975 with a BS in mechanical engineering and immediately went to work for Chevron EL&P in New Orleans. His 27-year career has included assignments as a drilling representative supervising offshore workovers and drilling, as well as a drilling engineer for well planning and cost estimating. In addition, Mr. Rau has been a drilling training engineer conducting well control, drilling practices and drilling engineering schools; a drilling engineering supervisor; a consultant for drillstring, wellhead and OCTG quality assurance; and a drilling superintendent. He has worked on various drilling projects around the world and is assigned to the Petronius project as senior project drilling superintendent.
	William Chase Hinson graduated with a BS in mechanical engineering from Mississippi State University in 1990 and has worked for Chevron and now ChevronTexaco since graduation in various positions. These include facility engineering, drilling foreman, drilling engineer, and field support team leader. He is now the GOM shelf drilling technology broker. Mr. Hinson is president of AADE’s New Orleans chapter and is a member of SPE.