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Deepwater Gulf of Mexico Development Challenges Overview Frank Close, Bob McCavitt, and Brian Smith, Chevron North America E&P Company

Copyright 2008, Society of Petroleum Engineers This paper was prepared for presentation at the 2008 SPE North Africa Technical Conference and Exhibition held in Marrakech, Morocco, 12–14 March 2008. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract Chevron's role as a major player in the global energy arena is due in large part to the Company’s extensive oil and gas exploration and production operations. A large proportion of the Company’s extensive reserves are located in deepwater locations throughout the world. The Company is one of the largest producers of crude oil and natural gas on the Gulf of Mexico (GoM) shelf and among the top acreage holders in the Gulf's deepwater1 and ultra deepwater2. Following on from the successes of an aggressive deepwater exploration campaign in the Gulf of Mexico, a series of major discoveries were rapidly appraised and moved to development (Fig. 1).

Fig. 1 Chevron GoM appraisal and development activities This paper will give a high level review of some of the recent development challenges for the deepwater and ultra deepwater fields in the GoM and will explain how these challenges were addressed and how the Company plans to address even more demanding challenges in the future.

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Introduction Operating in all areas of the world brings different challenges. The GoM, although a long established and prolific hydrocarbon basin, has over the past fifteen or so years evolved into an arena where challenges, related to performing operations in ever increasing water depths further from the coast, have been encountered. These challenges relate to all areas of operations including but not limited to, seismic acquisition, drilling operations, completion operations, subsea operations, production operations, logistics support, etc., etc.. In recent times this increased complexity in performing these ever more demanding operations has been set against an unprecedented increase in demand for all oilfield services. The change in the energy market has demanded that the worldwide oil industry produces more and more hydrocarbons. This increased demand has “stretched” every single area of the industry whilst at the same time presented ever more challenging projects to extract hydrocarbons. However, despite the environment as noted above, Chevron has aggressively explored, appraised and is now in the process of developing fields in the GoM which pose the greatest engineering challenge the Company has had to address. This challenge has seen an exploration well being drilled in over 10,000 ft [3048m] of water a subsea production well in the GoM being completed in marginally less than 10,000ft [3048m] of water. It is anticipated that being able to commercially develop resources in such water depths will be fundamental to the continued long term success of the GoM as one of the world’s major producing basins. From a worldwide perspective deepwater developments will account for approximately 25% of offshore oil production by 2015, compared to just 9% at present. The Challenges Many of the prospects in the ultra deepwater GoM have what can only be described as having a unique combination of challenges. The combination of deepwater (Up to 10,000 ft [3048m] water depth), high-pressure (Over 10,000 psi [690 bar] shut in pressures), high temperatures (Over 350oF [195oC] bottom hole temperature), problematic formations (Salt zones, tar zones, etc.), deep reservoirs (Over 30,000 ft [9145m] true vertical depth), tight sandstone reservoirs (< 10mD) and fluids with extreme flow assurance issues separate many GoM deepwater and ultra deepwater wells from deepwater and ultra deepwater wells in other parts of the world. Much of the prospective GoM deepwater exploration areas are in 4,000 ft [1220m] to 10,000 ft [3048m] of water. Most of this area is in a sub-salt environment; with salt canopies ranging from 7,000 ft [2134m] to 20,000 ft [6096m] thick, and have target depth ranges from 25,000 ft [7620m] to 35,000 ft [10668m] true vertical depth.

Fig. 2 GoM Salt Canopy Distribution

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The vast salt zones inhibit deeper seismic resolution and present great challenges in exploration, appraisal and development operations. The requirement to be able to understand the geology associated with the massive salt, and more importantly the quality of imaging below the salt, is one of the paramount challenges facing Operators.

Fig. 3 GoM Salt Deposition One of the key technologies being developed and applied to address this challenge is, “Wide Azimuth Towed Streamer” (WATS) technology. The use of this new technique allows better subsurface imaging for effective reservoir management planning and this will dictate well placement and number of wells required to optimally drain the reservoir.

Fig. 4 WATS Schematic

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As noted previously, the true vertical depths of some of the deepwater wells which are presently being drilled are in excess of 34,000 ft. Drilling wells to these depths brings a host of drilling challenges, some of which are noted in Figure 5.

Fig. 5 GoM ultra deepwater drilling technical challenges The US Minerals Management Service (MMS) has stated that, “High-pressure, high-temperature (HPHT) development is the greatest technological and regulatory challenge to the oil and gas industry today.”3 They also note that, “HPHT compounds the technological challenges faced in deepwater exploration and especially in deepwater completion and production.”3 Chevron is in general agreement with these statements and is supportive of most of the MMS initiatives to address the specific issues pertaining to this unique challenge. As all personnel engaged in the drilling industry will testify, having the “correct” drilling unit to drill the well is without question the number one concern. To address this point in the drilling of the GoM deepwater wells, the Chevron Deepwater Drilling Group has worked closely with the Drilling Contractor, Transocean, to contract two (2) new state of the art drillships on multi year terms to effectively and efficiently drill, complete, test and allow flowback of these demanding wells. The “Transocean Discoverer Clear Leader” and the “Transocean Discoverer Inspiration” are currently being constructed and will enter service in 2009/2010. These units are enhancements to the already impressive Enterprise Class Transocean units and should enable the wells to be drilled even more effectively and efficiently. Fig. 6 and Table 1 show some of the features of the units.

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Fig. 6 Discoverer Clear Leader and Discoverer Inspiration Capabilities Table 1 also lists some other key features of the unit design. Table 1: Equipment features of the Discoverer Class Drillship

75.1/2” Rotary table 100 mT cranes to handle production trees

72” Diverter Dedicated and customized well test deck

3 million lbs riser connections Dedicated ROV deck with 2 full work class ROV systems

12,000 ft riser deck storage Storage for 125,000 bbls of crude

2.5 million lbs derrick (2 million lbs traveling capability) Ability to rack 29,000 ft of tubing

2 million lbs active heave compensated drawworks Spool with HTHP sensor below rams

20,000 bbl mud system with 10 shale shakers 3000 HP cement unit with integrated high pressure Frac pump

Dual 18.3/4” BOP System with drillpipe running tool 5 National Hex pumps

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The complex nature of the formations, combined with the drilling depths required to reach the target zones presents a great challenge to the Drilling Engineers. The complexity is best illustrated in Fig. 7 which gives a “bird’s eye” view looking down in plan view of one of the actual wells drilled. The casing program on the right schematic illustrates a conventional five string casing design which is used on “standard” deepwater wells in the GoM and elsewhere. The casing program on the left schematic illustrates a nine string casing design which has been used in development wells in the deepwater HPHT fields. This demonstrates the amount of casing strings required to drill to target depth and also highlights the challenge in achieving good cement isolation in a tight tolerance annulai, and in HPHT conditions.

Fig. 7 Casing Program Schematic In the case of the development wells, after having successfully drilled the wells the requirement to complete the wells then becomes the next challenge. Fig. 8 illustrates a typical well completion schematic. As mentioned previously, the reservoir zones are generally of “low” porosity (<20%) and permeability (<10mD) and require to be fractured and proppant packed to produce commercial levels of flow. The process of performing these operations in a deepwater, deep well, HPHT environment in an effective and efficient manner is a demanding engineering and operational challenge requiring the highest level of planning and operational focus. Chevron has worked with several of their key suppliers to develop state of the art tools and operational processes to allow these tasks to be performed and continue to work in partnership with the Service Companies to further develop equipment and processes.

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Fig. 8 Typical GoM ultra deepwater well completion schematic

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Once the wells are completed below the mudline the subsea production equipment is installed. The high pressure nature of the fields demands, at this time, the use of 15,000 psi [1035 bar] wellheads and trees. Chevron has worked in partnership with two of the industries major subsea equipment suppliers to develop equipment to allow the wells to be completed in an effective and efficient manner. Many of the existing products had to be requalified for the increased demands of the production envelopes. Since very few fields with the mix of deepwater and HPHT conditions have been developed, Chevron adopted a process that involved a rigorous qualification testing of components and of complete systems in an attempt to mimic as much of the conditions encountered in the field. This approach was used successfully to qualify hundreds of components for use on the developments. As noted above, the use of 15,000 psi [1035 bar] has been required on the last two Chevron GoM developments. For obvious reasons the size of this equipment is a level above what could be considered as standard for subsea developments. One easy way to demonstrate this is in the weight of the subsea trees for the deepwater HPHT developments versus those used on more typical deepwater fields in the GoM and elsewhere. The trees Chevron has used on the deepwater HPHT field have been up to 72 tons in weight (See Fig. 9 and Fig 10) whereas the more standard deepwater 10,000 psi [690 bar] trees have been around 42 tons.

Fig. 9 Chevron Tahiti Tree (72 tons)

Fig. 10 Chevron Blind Faith Tree (62 tons)

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Although subsea wells have been selected to develop the fields, there is a still a requirement to have a production facility to receive the hydrocarbons, process the fluids and then export the fluids. Chevron GoM had experience with a SPAR (Surface Piercing Articulated Riser) on the Genesis project and elected to utilize this on the Tahiti project (Fig. 11). For the Blind Faith project a new generation deep draft semi-submersible hull was preferred (Fig. 12).

Fig.11 Tahiti SPAR

Fig. 12 Blind Faith Semi-submersible

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One very important point worth noting is the impact of the riser system on the topsides design. It is imperative that all aspects of the riser system design is considered in the selection of the topsides unit, be it a SPAR, semi-submersible, tension leg platform (TLP) or otherwise. The impact of the riser design on the topside unit cannot be over emphasized and if overlooked or not recognized at the preliminary design phase then this can have an enormous impact on the engineering and construction of the topsides unit. The preferred riser system must be decided in conjunction with the preferred topside unit. This is particularly true for steel catenary risers, which are generally the most economic riser type but present design challenges due to their strength and fatigue sensitivity at the riser touch down point. Depending on the water depth and riser properties, vessels with high heave and surge motions such as ship-shaped hull forms and semi submersibles, may impart too much motion at the riser hang-off, resulting in excessive stress and fatigue at the riser touch down point. The presence of corrosive fluids in the production stream such as hydrogen sulphide (H2S) can make the hull motion / riser design problem more challenging, since H2S significantly degrades the fatigue performance of carbon steel. High motion vessels may also not be able to accommodate large diameter export risers from a strength standpoint, due to heave induced stresses created at the touchdown point during storm events. Other riser concepts such as top-tensioned risers and hybrid towers may be less sensitive to hull motions but at a greater cost, complexity and may involve specific equipment qualification, such as flexible jumpers for high pressure and high temperature sour fluids. A further point of note is that site conditions in deepwater locations required detailed seafloor surveys prior to front end engineering and design (FEED) and prior to locating any wells, subsea infrastructure, flowlines, pipelines or mooring systems for host platforms. This is due to the complexity in seafloor features such as canyons, seeps, faults, and steep seafloor slope and soil conditions. Many times the layout of the field will be determined by these features and in certain cases they can eliminate development options. An example would be limitations of locations for a host platform that would not allow a geologic central location for the wells. This would eliminate having dry trees and a drilling unit on the host because most of the wells could not be located at the host site. As with every subsea development anywhere in the world, the pipeline and flowline systems must also be designed in an integrated manner within the overall field design concept to manage flow assurance issues. Flow assurance issues dominate the selection of the pipeline and flowline systems. The “cold” seabed conditions combined with “problematic” wellbore fluids requires detailed flow assurance modeling and testing to be performed to prevent issues that may negatively impact the flow capacity of the field. Fig. 13 shows just some of the potential problems to be considered in the pipeline and flowline design.

Fig. 13 Flow assurance challenges

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From the flow assurance results, technologies and methods such as determining the optimum pipeline / flowline sizes, maintaining sufficient operating temperature by optimizing insulation design, specifying the optimum chemical inhibitors and determining the allowable shut-in / shut-down times can be employed to reduce or eliminate the problematic issues. Future Challenges One obvious issue that comes with working in deepwater is the increased hydrostatic head associated with the greater depth. When working at 10,000 ft [3048m], this equates to a pressure on the seabed in excess of 4300 psi [297 bar]. This is clearly a well known and understood phenomenon and is addressed in the design of equipment being utilized. However, two points are worth noting. The first is that whilst the deepwater wells may well be high pressure initially, over time the reservoirs will deplete and the energy to move fluids to surface declines. The impact of this is lower production and lower recovery. To overcome this issue the challenge is to develop and deploy systems which can assist the wellbore fluids to be transported to the surface. The “simple” solution for this is to utilize artificial lift of some description. Chevron, in conjunction with its Partners and the service industry is looking at sub-mudline systems such as electrical submersible pumps (ESP) and hydraulic submersible pumps (HSP) and also seabed boosting systems to both increase production rates and also increase well recovery volumes. The successful application of this type of area of technology is fundamental in ensuring that GoM ultra deepwater fields can be developed economically. The second point to note is the “reluctance” of Operators, the Service Industry and, to a lesser extent, Governmental Agencies to utilize the “benefit” of this huge hydrostatic load in the design of equipment installed on the seabed. In the past, in shallower water depths, the base design of most subsea equipment catered for working in moderate water depths without any real issues. However, as deeper water depth developments, combined with the vast loads associated with HPHT reservoir conditions, have arisen this has caused certain pressure containing equipment to be “apparently” stretched to the limits of the design. When the external affects of the hydrostatic load is considered the stress levels in the pressure containing equipment drop dramatically and in some cases in an ultra deepwater application can be less than in a shallower water application. One enormous benefit of considering the hydrostatic external loading in ultra deepwater applications could be to utilize more conventional field proven 10,000 psi [690 bar] equipment as opposed to customized 15,000 psi [1035 bar] equipment in certain applications. Assuming this could be done would result in a range of benefits from manufacturing, testing, installation and reliability of the equipment. As the industry moves forward rapidly to develop and apply new technologies, one final point should be considered. One of the first tasks any good Engineer will do when assigned any engineering task is to do a literature search to ascertain if the project on which they are working has some or any form of precedence. One example of this is a Chevron non operated venture where the Operator elected to utilize ESPs in caissons to provide the artificial lift required for the field (Fig. 14). Chevron looked around the world at its various assets and found that a riser caisson had been used to develop one of their subsea fields in the North Sea over 20 years prior (Fig. 15). Although not exactly the same application there was sufficient similarity to demonstrate that sometimes as we look forward in the development and application of new technology, looking back might also be beneficial. This also demonstrates that in certain circumstances new technology may actually be the use of existing proven components in a new configuration.

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Fig. 14 GoM ultra deepwater subsea caisson

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Fig. 15 Chevron North Sea Caisson ESP

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Summary

As noted throughout this paper, the word, “challenge” is used extensively, and is used for all the correct reasons. The industry is in the busiest period in its recent history and as we continue to pursue prospects in deeper water depths and more challenging reservoirs, the need for technology development and equipment qualification to meet the corresponding technical challenges for project development are becoming much greater. With fewer “experienced” personnel available the impact of developing and qualifying new technologies is not always recognized early enough in projects and consequently project schedules are negatively impacted. In many instances, the timeline to develop and qualify a new technology may exceed a typical project development schedule hence the need for companies to do a better job of identifying potential technology requirements of future exploration prospects, sometimes even before they are drilled. Performing rigorous front end loading for all areas of engineering and having processes to “aggressively” challenge all aspects of engineering plans has to be engrained into Operators processes to make sure all issues are highlighted and addressed as early as possible in the project planning cycle.

The costs, and risks, associated with working in deepwater are high. All services from seismic, drilling, construction, installation are in high demand and consequently costs have risen to unprecedented levels and are likely to remain high for the foreseeable future. Due to this high cost environment, the number of wells being drilled to explore, appraise and develop fields is being reduced and this combined with being able to accurately predict reservoir performance for reservoirs with limited to no production history or analogues brings an even higher risk profile for all Operators.

As these ever demanding projects arise there is a need for Operators to engage more with governmental agencies to ensure that they are aware of the challenges associated with field developments that require state of the art and often unproven technologies. The demands on Operators to lock down field development concepts without having “confidence” in the selected technologies places a huge burden on Operators and may in certain cases undermine the commerciality of certain developments.

Chevron is proud of how we have stretched the envelope in pursuit of commercializing our assets in the GoM. Chevron holds the record for drilling the deepest well in the GoM (34,189 ft / 10420m); we hold the record for drilling a well in the deepest water depth (10,011 ft / 3052m) as well as the record for the deepest successful well test with Jack 2 well (28,175 ft / 8588m) in 7,000 ft (2134m) of water. Chevron, with the assistance of our Partners, our trusted Service Companies and Drilling Contractors, will continue in our drive to explore, appraise and develop fields in the GoM and we will utilize these skills elsewhere to ensure that Chevron is at the forefront of ultra deepwater field developments throughout the world.

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Acknowledgement The authors would like to thank James Cearley, Scott McLeod, Ian King, Billy Varnado, Buddy Lang, Hugh Barclay, Renard Falcon, Bill Gilliam, Kevin Cunningham, Jay Gagneaux, Jeff Newhook, Keith Couvillion, Ivan Hiscox, Jayne Sieverding and Jennifer Lewis from Chevron Deepwater Exploration and Production (DWEP) and Chris Hey and Hugh Thompson of Chevron Engineering Technology Company (ETC) for their input to this paper. Special thanks also to Tom Burlas, Linda Rice-Naas and Antonio Palmeirim for their input and review of the paper. References

1. The United States Minerals Management Service defines deepwater as water depths greater than 1,000 ft (328m). See page 3 of OCS report: MMS 2006-022, “Deepwater Gulf of Mexico 2006: America’s Expanding Frontier”.

2. The United Sates Minerals Management Service defines ultra deepwater as water depths greater than 5,000 ft (1524m). See page 3 of OCS report: MMS 2006-022, “Deepwater Gulf of Mexico 2006: America’s Expanding Frontier”.

3. See page 50 of OCS report: MMS 2006-022, “Deepwater Gulf of Mexico 2006: America’s Expanding Frontier”.