Summary The Genesis project was ChevronTexaco's first Gulf of Mexico deepwater development project and the first industry project to use spar technology for drilling, completion, and production operations.1,2This paper discusses the unique results and lessons learned through the first 4 years of the Genesis project in the areas of integrated teams, organizational learning, spar operations, completion practices, well performance, and reservoir management. Introduction The Genesis field is located in Green Canyon Blocks 160, 161, and 205 in the Gulf of Mexico. The spar is located in Green Canyon Block 205 in 2,590 ft of water. The Genesis project is a joint venture among three partners:56.67% ChevronTexaco (operator), 38.38% ExxonMobil, and 4.95% BHP Billiton. The discovery well was drilled in 1988, and several delineation wells followed in the early 1990s; development funding was approved in 1996.Asemisubmersible rig was used to batch set 36-, 26-, and 20-in. casing strings on 19 wells. The seafloor well pattern includes locations for 20 wells and two export riser bases. Spacing between locations is 20 ft in a140-ft-diameter circle. The semisubmersible rig also drilled and cased the first two development wells. The spar was installed in mid-1998, followed by topside and rig installation. Hookup work began, and the first rig operations—running the export risers—began in November 1998; first production occurred in late January1999. Through the first 4 years of the project, 14 producing wells have been drilled in the Genesis field. These 14 wells include 10 wells with single completions and four wells with stacked wireline-selective completions. Major rig workovers to change producing zones have also been performed on two of the initial 14 wells. Maximum daily production from the Genesis field was 61,130 BOPD and 98,670Mcf/D of gas, achieved on 4 July 2001.Future plans for the field include numerous sidetracks and major rig workovers. Ref. 1 discussed the development plan for the Genesis field as it related to drilling and completion design and execution. This paper presents a unique comparison between the planned and actual development program and describes results and lessons learned through the first 4 years of the Genesis project.

Completion workstrings must endure an extremely hostile environment of erosive and corrosive fluids. Today's improved internal plastic coatings can protect the significant investment in drill pipe from erosion/corrosion, as well as minimize completion trouble time caused by pipe debris (scale). An internally coated, Class 2 drill string was used for 2 1/2 years to successfully Frac Pack seventeen, high productivity, Gulf of Mexico Deepwater completions in the Genesis Field. More than 2,000,000 pounds of abrasive proppant was pumped without a pipe failure. Introduction The completion workstring requirements were reviewed during the development well planning for the project in 1998. During completion processes, this pipe would be subjected to only minimal tensile stress and torsion; however, the pipe would need to bear the rigors of numerous Frac Pack completions. The plan originally included 22 Frac Pack completions from 16 wells with anticipated surface treating pressure of up to 10,000 psi (depending on the selected completion string diameter). The planned wells ranged in depth from 12,000' to 23,000' and in hole angle from 16° to 66°. During each completion, the 6 5/8" drill string would be changed to a smaller diameter completion workstring to displace the well to CaCl2/CaBr2 completion fluid, tubing conveyed perforate (TCP) underbalance, pressure surge the perforations, wash sand fill, and Frac Pack. The workstring would then be sent to a pipe yard to be stored outdoors until the next completion operation occurred in roughly one month. After reviewing the alternatives, the rig contractor's 5", 19.50#/ft, S-135, 4 1/2" IF drill pipe was selected for the completion string. This workstring was a collection of used pipe with an RP7G API-IADC Used Drill Pipe Classification System rating of Class 2 due to undersized tool joints.1 Some of this pipe was as old as 20 years yet the tubes met Premium Class standards with 80% wall thickness (0.290") remaining. Premium Class tubes have a tensile rating at minimal yield strength of 560,764 lbs and an internal yield pressure rating at minimum yield strength of 15,638 psi. The reduction in torsional strength due to the reduced tool joint diameter was not a concern due to minimal rotation for drilling cement anticipated. These specifications met the anticipated completion workstring requirements and the rig contractor was pleased to find commercial use for this drill pipe rather than scrap it for roughly $50 per joint or replace the tool joints for roughly $700 per set. An abrasion resistant internal drill pipe coating was considered to combat further internal wall loss due to proppant laden Frac Packs. A wall loss of only 0.036" could downrate the Premium Class tubes to Class 3 (<70% wall) which has no RP7G published rating for tensile forces or internal yield pressure. The drill pipe would then be scrap pipe. Additionally, the internal coating should minimize internal pipe rust and eliminate the need for acid pickle treatments. For deepwater operations, acid pickle treatments cost roughly $10,000 for purchase, transportation, rig time, and disposal. Most importantly, using an internal coating would eliminate the safety, environmental, and liability risks associated with handling and disposing of acid. A liquid-applied, modified epoxy-phenolic internal coating specifically formulated for drilling environments was considered for the completion program. Standard industry tests for coating abrasion resistance (Taber Abraser test, ASTM #D 4060) measure a test sample's weight loss in mg over 1000 cycles of abrasion using a CS-17 wheel with a 1000 gm load.2 In 1998, the coating considered for use had results, provided by the supplier, of 47 mg of coating lost / 1000 cycles. A bare steel plate was tested to determine the weight loss without a coating; surprisingly, the results were similar (45 mg of metal lost / 1000 cycles). Taber Abraser test information, although useful to compare coatings, does not answer the question of whether a coating will survive repetitive Frac Pack treatments.

Extended-reach, naturally perforated, water-injection, frac-pack producing completions and frac-pack producing selective completion interventions were successfully implemented in the deepwater Gulf of Mexico Petronius field, setting both Gulf of Mexico and world records. Success was achieved through careful planning of procedures and specification of equipment. This paper describes the planning for these challenging extended-reach completion and intervention operations, along with the lessons learned while implementing these case-history jobs. IntroductionChevron and Marathon each have a 50% working interest in the Petronius project, which is operated by Chevron. The field is located in the Gulf of Mexico, 150 miles south of Mobile, Alabama. The project was sanctioned in August of 1996 after both compliant-tower and subsea-development options were evaluated. The compliant-tower alternative was selected because of its greater well-intervention capability, less-complex seawater-injectionsystem design, lower investment requirements, and future hub potential. The 2,001-ft-tall Petronius compliant tower is set in 1,754 ft of water and is the world's tallest free-standing structure.The Petronius project originally targeted two main reservoirs which were delineated by seven preplatform-well penetrations. Once these two original pay sands were developed, the operators set their sights on developing suspected pay zones much farther from the platform in deeper water. The development of these distant zones required mechanical success in implementing difficult world-record extended-reach processes and, of course, success in finding economic quantities of pay.For the past 3 years, a successful program of just such worldrecord extended-reach development has been ongoing. The program has seven wells to date, with horizontal displacements ranging from 14,000 to more than 25,000 ft. These horizontaldisplacement values far exceed the ≈11,000-ft true vertical depth (TVD) of these wells. Fig. 1 summarizes the directional data for the Petronius extended-reach program in chronological order of well development, and Fig. 2 illustrates the complexity of the directional profile of the most challenging of these wells.This extended-reach program is quite an accomplishment considering the unconsolidated deepwater environment. To date, the program includes two water-injection wells and five frac-pack producing wells. Three of the five producing wells include stackedfrac-pack completions. Future well plans include an additional extended-reach frac-pack producing completion and a sidetrack of an extended-reach water-injection well.

A large number of well perforation jobs are conducted successfully worldwide each year. However, gunshock related damage poses a significant risk when perforating high-pressure wells. This paper presents gunshock studies done with a simulation tool specifically developed to predict perforating gunshock loads and the associated structural loads on the equipment. This simulation effort includes results from seventeen Tubing Conveyed Perforating (TCP) jobs on high-pressure deepwater wells, with pressures ranging from 13,800 psi to the highest pressure wells ever perforated in the Gulf of Mexico at 20,700 psi. The results show very good agreement between software predictions and actual field data. When planning perforating operations in high-pressure wells, engineers strive to minimize the risk of equipment damage from perforating gunshock loads, such as bent tubing and damage to packers. The risk of equipment damage from perforating gunshock loads increases very rapidly as the bottomhole pressure increases beyond 15,000 psi. The simulation tool used to perform gunshock studies is fast and can reliably identify perforating jobs that have a high possibility of gunshock related damage. For those cases where the chance of gunshock damage is high, design changes can be implemented to reduce or eliminate those potential risks. In this review, computational predictions are compared with high-speed pressure gauge data, with the residual deformation of shock absorbers, and with high speed acceleration data. Fast gauge pressure data shows that predicted wellbore pressure transients are sufficiently accurate in magnitude and time. Peak pressure amplitudes measured at the gauges are, on average, within 8 percent of the predicted values. Residual deformations of shock absorbers correlate favorably with predicted peak axial loads, and available fast gauge acceleration data shows that the asymptotic gunstring acceleration is well predicted, both in amplitude and frequency. The ability to identify and reduce risks in perforating operations is important because the value of deepwater wells is very high and rig time losses are costly. With the software tool presented in this paper, engineers can optimize high-pressure well perforation designs in order to minimize the likelihood of gunshock related damage and the associated rig time losses.

Wireline tractoring technology has set world and Gulf of Mexico records for several logging applications during the initial completion and intervention of two extended-reach, deepwater frac pack wells and one extended-reach, deepwater water-injection well. This paper reviews some of the challenges involved with conventional conveyance methods in extended-reach wells, describes the planning process for wireline tractoring operations, including prejob modeling, and summarizes the results of a project.The authors will also share the lessons learned and best practices implemented. Proper utilization of this technology has led to significant cost savings for the example project. Introduction The Petronius project, located 150 mi south of Mobile, Alabama in the Gulf of Mexico, is operated by Chevron Corporation, with Chevron Corporation and Marathon Oil Corporation having a 50% working interest in the project.The project was sanctioned in August 1996 after a compliant tower and subsea development options were evaluated.The compliant tower alternative was selected based on superior well intervention capability, less complex seawater injection system designs, lower investment, and future hub potential.The 2,001-ft tall Petronius compliant tower is set in 1,754 ft of water, and is the world's tallest free-standing structure. The Petronius project targeted two main reservoirs that were delineated by seven preplatform well penetrations.Once these two original pay sands were developed, sights were set on developing potential pay much further from the platform in deeper waters. The development of these distant zones required mechanical success in difficult world-record, extended-reach processes and, of course, success in finding pay. For the past 3 years, a successful program of world-record, extended-reach deep-water well development has been ongoing.To date, there are 7 wells in the program with horizontal displacements of 14,000 ft to over 25,000 ft.This far exceeds the ~11,000-ft true vertical depth (TVD) of these wells.Fig. 1 illustrates the magnitude of the directional profile of the most challenging of these seven wells (Well #3 in this paper). This is quite an accomplishment considering the unconsolidated deepwater environment.To date, the program includes two water-injection wells and five frac pack-producing wells.Future well plans include an additional extended-reach frac-pack completion and a sidetrack of an extended-reach water-injection well.