The Next Major Challenge for Deep Water: Developing Marginal Fields Dr. Keith K. Millheim / MEPS LLC

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1 OTC The Next Major Challenge for Deep Water: Developing Marginal Fields Dr. Keith K. Millheim / MEPS LLC Copyright 2008, Offshore Technology Conference This paper was prepared for presentation at the 2008 Offshore Technology Conference held in Houston, Texas, U.S.A., 5 8 May This paper was selected for presentation by an OTC 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 Offshore Technology Conference and are subject to correction by the author(s). The material does not necessarily reflect any position of the Offshore Technology Conference, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Offshore Technology Conference 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 OTC copyright. Abstract Worldwide, there are hundreds of deep water oil fields that have been discovered, and many hundreds yet to be discovered that are not commercial using existing conventional deep water approaches. A new paradigm based on production materiality is an alternate approach for deep water marginal oil field exploration and development. This new paradigm shows that first oil could be consistently achieved in one to two years from discovery to first oil with attractive economics if there are new ways to significantly reduce drilling costs, capital investment, and operational costs. This paper presents a paradigm of how these results might be possible in the foreseeable future with the innovation of what might be called the micro chip for deep water the self standing riser. INTRODUCTION History of the oil industry shows the early discoveries of oil and gas started with the shallow, easiest to find hydrocarbons, onshore. With innovations in seismic and drilling equipment and technology deeper discoveries were made. Later exploration was extended offshore to the shallow shelf areas. The North Sea and Gulf of Mexico (GOM) and offshore Brazil led the development of offshore technology which focused on drilling with jackups, drill ships, and semi submersibles with most of the production facilities based on compliant platform structures. However, as smaller fields were discovered and field extensions extended beyond the reach of the drilling/production platforms the subsea well became a viable option. Subsea wells near the platform were tied back via pipeline to the platform. However, in some cases, a floating production unit (FPU) was used to process the subsea well(s) production and tie back to the main production line. Other cases where the tie-back to the main pipeline was not feasible a floating production storage off-take vessel (FPSO) was used not only to process the reservoir fluids but also to store the oil for later pick up by an oil tanker. For most of the world (except for the Gulf of Mexico), especially the North Sea, Brazil and Australasia, the subsea well and FPU/FPSO became the normal development path for the smaller offshore fields. The FPU/FPSO offered more versatility, quicker construction, and in most cases better economics. The Gulf of Mexico was a unique case where there has always been enough offshore pipeline infra-structure where all the oil and gas production went into the main pipelines. Because of the pipeline network and some other perceived safety and environmental issues the use of FPSOs was non-existent. Only a few FPUs were commissioned in the GOM. In the middle of the 80s the exploration community, with the help of advanced seismic technology, showed the likelihood of finding large oil fields in deeper water with Brazil leading the way. Deeper water discoveries in the GOM and West Africa followed. Except for the Middle East few places held the potential for the discoveries of big fields like deep water. The new deep water thrust for exploration forced some major changes both in drilling and production strategies. Drilling could be only done with semi-submersibles and drill ships. Long risers to accommodate the increasing

2 2 SPE water depth and to handle the heavy subsea blow-out preventers were now a necessity. This meant that most of the offshore fleet had to make major modifications to handle the long risers and to increase deck space. Riser tensioners had to accommodate more loads. Because of the increased loads and deck space, many drill ships and semi-submersibles were limited by water depth. This increased the demand for a new generation of new semi-submersibles and drill ships. However, the capital costs to build these units were escalating. This was the beginning of the price escalation for the mobile offshore drilling unit (MODU) which in turn would impact the viability for exploring for a certain size of deep water field. The second and more important economic driver for a discovered deep water field was the production options. Now the production facilities had to be FPSOs, SPARS, tension leg platform (TLP), or the semi-submersible designed platform. The GOM gravitated to the non-fpso solution while West Africa and Brazil mainly used the FPSO option. All the options required drilling subsea wells and either tying back to the FPSO or one of the floating structures. All the options had a clear impact on the size of field necessary to support the capital costs for building one of the floating structures. Besides drilling with the expensive MODUs now there was the need for either subsea trees, or in the case of dry tree completions with TLPs, SPARs, or semi-submersibles, there were the costly tie-backs from the wells. The cumulative cost of a deep water field with the combination of the drilling costs, floating facilities, the subsea trees, manifolds and pipelines had a huge impact on the size of field (reserves) that could support such a capital investment and yield competitive economics. All of this was with the lower oil prices at the beginning of Once the oil prices started to increase, around 2003, deep water drilling activities started to increase. Rig rates escalated, ship yards with new orders for MODUs and production facilities filled up. All parts of the service and manufacturing sectors started back logging some orders as far as eighteen to twenty-four months. As the price of oil continued to increase there was a rush by the operators to secure long term contracts for all the MODUs that were in service. Semi-submersibles that once had a per day rate of $45k per day two years later was at $250k per day. Fifth generation MODUs were getting two year contracts at rates above $450k per day. Even though the price of oil increased, costs increased at equal or higher rates. This trend still continues. Along with the greatly escalated operational and capital costs, some asset owners of deep water leases changed the physical terms of the taxes and bonus structure that also impacted the economics of exploration and development of deep water fields. Even though the price of oil significantly increased so did everything else. Deep water fields that were too small to be economic prior to the oil price rise still remained uneconomic with higher oil prices because of all the factors previously discussed. Another factor that deters targeting these smaller fields (less than 100 million bbls) is the paradigm most international oil companies (IOCs) operate from. Wealth is commensurate with the size of reserves i.e. the bigger the field the more the value to the company and shareholders. This is not exactly the case for many National Oil Companies (NOCs) who value production over reserves. Hence, the tendency of most majors who have the deep water experience and technology is to set some field size threshold which meets the corporate guildelines of where they prioritize their opportunities. This generally favors targeting oil field sizes of over 100 million bbl of recoverable oil reserves. Other factors also work against targeting the smaller deep water oil fields. Deep water fields need to have extensive early testing to establish compartment sizes, productivity, and how much energy is available i.e. whether there is any water and gas drives. Usually, these smaller deep water oil fields need some type of supplemental energy to achieve a level of sustained production. This also means early injectors need to be drilled and water injected nearly as soon as the field is put on production. Also, because of the small reserve size the production facility is usually going to be some type of FPSO or FPU meaning all the wells are going to need subsea trees with tie backs to the production facility. All of these factors when considered usually deter most deep water operators from targeting the smaller deep water field. Because of the perceived non-commerciality many of the discovered deep water uneconomic fields were returned to the government or given back to the lease holder. Many of the Figure 1 Number of Discovered Offshore Field Sizes

3 SPE lease holders either do not have the experience or resources to develop these so called marginal deep water fields. Today there are hundreds of these non-commercial, marginal deep water discoveries that for one reason or another will not be developed (Fig. 1 shows the number of discovered offshore field sizes versus reserve size and Fig. 2 (next page) shows the status of oil and gas discoveries in water depths greater than 500 ft.). Even more impressive are the potential exploration targets of less than 50 million bbl that will not be drilled because they are considered noncommercial. Is there another way to try and make these fields economic under today s environment. This paper presents another paradigm for deep water exploration and development for deep water marginal fields. MATERIALITY RESERVES VERSUS PRODUCTIVITY Figure 2 Field Size Range Reserve Materiality In the early days of exploration and development there was only production materiality how much a well or field would produce. For years a company was ranked more by its production than anything else. After the oil crash in the 80 s the production materiality shifted from production to reserves. One main reason was reserves valued the total assets a company had. This in turn was a measureable value of a company s worth especially if they wanted to buy or sell the assets or the company. It also became one of the basic measures of the life span of a company which had an impact on the share price. Production in this sense is a causal result of the reserves. Geoscientists find reserves (and are rewarded as such) and engineers obtain production from the reserves. The reserve paradigm requires some way to evaluate the recoverable reserves. Usually, this was achieved by drilling a number of appraisal wells after the discovery. Seismic interpretation, log analysis and reservoir simulations then led to some type of estimate of recoverable reserves and development plan (or in some cases no development). Deep water fields presented new problems: appraisal wells were very expensive, long term conventional well testing was difficult and costly, and in the GOM was almost non-existent until recently. Most development decisions were based on 3-D seismic interpretation, formation tester results, some cores, and logs. What became the accepted cycle of development was doing seismic, drilling the seismic prospect, running more seismic and doing more interpretation. This was followed by more drilling. This process continued until a company made a decision to budget the amount of money necessary to develop the field or not. Because of the long appraisal time and the time to build the production facility, plus the development drilling the overall time from discovery to first oil generally took in excess of five to six years and in some cases over ten years. Again, this favored prioritizing fields with enough reserves to carry the heavy burden of high capital costs and deferred production for many years. The smaller deep water fields became of no interest to the big producers. Reservoir Quality Generally, most deep water reservoirs exhibit very good reservoir properties with average permeability s in excess of 100 md and porosities above 20 percent. With a reasonable oil viscosity below 5 cp most deep water oil producers will produce well over 2000 bpd. The question is how long will the reservoir sustain these higher flow rates? What the industry has been experiencing in a great many fields is more compartmentalization than ever before presumed. Only long term well testing can answer the compartmentalization question before putting the field on production. Then there is the question of reservoir energy. Without long term testing it is very difficult to determine how much energy is available to support the higher flow rates. Deep water reservoirs with low GORs and higher viscosities need immediate water injection and some type of artificial lift. This puts another burden on the development plans for facilities plus the need for intervention to run and maintain some type of gas lift or

4 4 SPE electric submersible pumps. All of these problems are bad enough for a bigger field, for smaller deep water fields they seem insurmountable. As long as one considers the deep water E&P reserve based paradigm as the only way to approach the smaller deep water fields these fields will always be analyzed as non-commercial. There is little likelihood with today s limited and expensive offshore fleet, long lead times, high cost production facilities and other subsea requirements that the marginal deep water fields of less than between 50 to 100 million bbl of recoverable oil can be economical. In some ways the deep water industry has paralleled the computer industry. The Mainframe PC Analog During the 60 s and 70 s main frame computers were considered the only way to do computing. IBM, Cray, and Digital computers dominated the computing business. Everything, hardware and software, was designed to be compatible with the mainframe paradigm. Conventional wisdom dictated this was the only logical way for doing informational technology. Yet behind the scenes there were some technology disruptors that believed that main frame computing was not the long term answer and that small personal computers could evolve to do the same thing and maybe more. The break though really came in the 80 s with advent of the microprocessor chip. As Fig. 3 shows, the microprocessor evolved into our modern personal computer which was smaller, faster, and decidedly cheaper. Main frames went the way of the dinosaur. It is the author s opinion that the current paradigm for deep water E&P based on reserves and current drilling and production practices are much the same as the main frame. To develop the remaining deep water fields (and history tells us they will get smaller and smaller) will take another microprocessor type breakthrough along with a more systemic solution to the overall challenges previously cited. Figure 3 Evolution of the Microprocessor Production Materiality The logical question is: if the reserve oriented paradigm for finding and developing marginal deep water fields is currently not possible, what is? One possibility is production materiality. If, in some way, a field size now deemed too small from a reserve oriented metric could be made not only economic but very profitable by some other way, how could this be done? There is no one solution to the challenge, no magic bullet. It is a systemic solution including being able to minimize costs, accelerate development time, know compartment volumes and energy, provide supplemental energy for production and achieve economic production rates. Fig. 4 on the following page is an example of a typical marginal West Africa type field with a compartment size too small to sustain production for less than a year. Even with gas lift or an electric submersible pump the 10k bop cannot be sustained for more than three to four years. However, with early injection the primary production is maintained for nearly six years and the decline is not so severe. What makes the higher production rates possible are the good reservoir properties generally found in deep water fields, especially in West Africa. In this case one or two production wells and one injector well can achieve these results. The center point of the example is not the reserve size, but the production materiality to get significant production from a few wells, sustain the production as long as possible, and abandon the prospect at some reasonable economic limit and move on. And most importantly to do all this quickly and at costs that make the venture profitable for the asset owner and the operators. REDUCING DRILLING COSTS There needs to be a way to drill this example marginal prospect at costs much less than the current market rates (that is assuming you could find a MODU). In the late 90 s Unocal 1 and a few other companies 2 innovated the

5 SPE surface BOP system with smaller riser pipe to drill deep water wells off of Thailand with considerable success. In fact, now the surface BOP technology is being accepted by some companies as a way to reduce drilling costs by using lower generation MODUs to drill in deeper water. In a competitive drilling environment this could be successful, but because of lack of MODUs worldwide even the Generation 2 and 3 MODUs prices are at a premium. Also, there is the additional cost and time to modify a conventional MODU to run a surface BOP. Again, anything that radically changes the existing paradigm of a large diameter riser and subsea BOPs seems to run into the overall barrier of change and conventionality if it works why fix it? An industry group in Norway 3 took another approach to the problem a proposed a technology for raising the seafloor artificially to a depth of about 200 meters by using a buoyant supported facility like a submerged TLP where the subsea BOPs and trees would be at 200 meters, hence less riser and possibly less expensive MODUs to drill and complete the deep water wells. Until now this technology still is untried. Both of the deep water solutions for reducing drilling costs were still based on the conventional paradigm of the conventional MODU. What is needed is a solution like the new Indian automobile by Tata Motors 4 proposed to sell at $2,500! The concept is to make a very cheap car just to sell in India at a price range allowing more Indians to own a car. To develop marginal fields the industry needs a radically new offshore drilling solution for deep water that costs less than $100k per day at today s competitive prices. But reducing drilling costs and the time to drill is only part of the bigger system for better speed, cost, and profitability. TESTING THE MARGINAL FIELD A marginal field development like the cited example (Fig.4) cannot wait 3 to 4 years or more after discovery to go through the drill, seismic, drill process to appraise reserves. In this example the discovery needs to be tested as quickly as possible to ascertain some minimum compartment size and productivity index that will sustain 10k bopd with injection for six years. Formation testers cannot provide useable information on compartment volumes or reservoir energy. This requires two types of longer term testing: 1. Short term transient testing (usually less than a six to eight hour flow period with a twelve to twenty-four hour shut-in); 2. Figure 4 Typical Marginal West Africa Type Field Long term production test (which could run up to thirty to sixty days). Both testing periods depend on the formation properties and compartment size. The testing strategy is simple: test long enough to define a minimum compartment size for the given formation properties to make the development of the compartment commercial. Well testing, as just described, is a staple of the upstream oil and gas industry. However, it is not a staple for deep water because of the time delay to mobilize some type of testing and storage equipment, including a full MODU spread with riser and subsea BOPs. Even if the industry operators were prone to do the testing, in today s environment, there are only a few vessels or MODUs that could accommodate these type of long term tests. Over the years there have been a few dynamically positioned vessels specifically designed for longer term well testing. Of note is Petrobras 5 who has been running long term production tests in deep water with such a vessel for a number of years. The main point of this discussion is there is no capacity in the deep water industry to accommodate cost effective deep water well testing. This is another deterrent for going after marginal deep water fields unless a cost effective solution for early testing can be found. PRODUCTION FACILITY BARRIERS FOR MARGINAL FIELDS The major economic constraint for exploring and developing marginal deep water fields are the production facilities. As discussed before, the only solution for deep water is some type of floating facility. However, for

6 6 SPE marginal fields most conventional approaches are just too expensive for deep water production. Unless the marginal deep water field is close enough to tie- back to some near-by production facility there is the need for some type of FPSO solution. With ship yards backed up for over 1 ½ to 2 years, plus the escalating costs of steel and other main components the economics for the production facilities are poor with long time delays for putting an appropriate FPSO that would be economic for marginal deep water field development. This is another reason operators shy away from such an undertaking. Conventional wisdom says: if you are going to commit people and financial resources you go for the bigger development projects even if it takes over six years before you see a drop of oil in the tanks. The production facility is not the only production problem. If you consider the subsea tree, production lines to the FPSO, injection capabilities, and flow assurance the economics are poor for developing a small field of 20 to 50 million bbls of recoverable oil with three to six wells. There needs to be an innovative solution that provides a production system that is very modular and adaptable to production rates of 10k to 25k bopd, able to provide early injection of water and gas, provide some oil storage. And all of this needs be very cost effective. Also, there needs to be another solution other than the conventional subsea tree and pipelines that minimizes flow assurance problems. And finally, the new system should be able to accommodate easy and cost effective intervention, preferably without the use of a conventional MODU, which allows workovers and the routine use of artificial lift, again at low costs. It is the author s opinion: that only by considering a production materiality paradigm can a marginal deep water oil accumulation made commercial. The exploration, testing, and development must be seamless, one production activity phasing into another. The exploration well needs immediate longer term testing. A testing facility that can be the production facility must be ready with the drilling facility. Once confirmed as an economic compartment size the development should include early injection well(s) and a way to later run artificial lift. When the compartment is at the economic limit all the equipment needs to be mobile and modular so it can be removed and used on another marginal field compartment. All of these activities need to be done at a fraction of the costs of conventional approaches and within one to two years from first discovery. What would this marginal deep water exploration and production system look like and how would it work? Is it even possible to deploy such a system in the near future? THE POSSIBLE SOLUTION Over three years ago the author was given the challenge to devise a deep water system that would make it possible to explore and develop the marginal deep water fields in West Africa. The reason West Africa was chosen were the benign sea states (less current and surface sea state) and the shallower higher productive reservoirs. Studying the problem for months it became clear that trying to solve this challenge with the conventional reserve materiality paradigm could not work. Logic leads one to the solution for marginal deep water fields that whatever you need to do, you need to do it quickly, not in a half a decade but in less than a year or two, if possible. This means putting the field on production as quickly and cheaply as possible, plus not making some very costly mistakes on the reservoir or during development. It was clear that some systemic solution was necessary that had the attributes to solve the exploration drilling phase, early well testing, completion, early production testing and phasing into production (assuming minimum production materiality was reached), followed by production drilling of the other producers and injectors to make the marginal prospect economic. The system also had to accommodate intervention to be able to deploy some type of artificial lift. All of these attributes had to synchronize with less initial capital costs, and much less overall operational costs, leading to a faster and cheaper overall system. Logic again leads to major standardization, modularity, off the shelf technology, and most important simplicity. The first big question that evolved from this rationale was: why do all the technology on the sea floor? As mentioned previously Unocal in its Gulf of Thailand deep water drilling campaign decided to drill with the BOPs at the surface using a smaller MODU. This was good for exploration but what about production? Then there was the Norwegian group that had the idea to raise the sea floor to 200 meters from the surface? But this was still a subsea solution with all subsea components. All good ideas, but not the system solution that was needed. However, further investigative thinking leads to the question: is there a way to eliminate the heavy, bulky riser system and the subsea BOPs for drilling, workovers, completions, and interventions? And is there a way to get all the complex expensive mudline technology closer to the surface? Asking the right question always leads towards a possible answer. In this case it was clear that some type of specially designed self standing riser (SSR) could

7 SPE be possibly the micro-chip breakthrough for the deep water. SSRs are not new to deep water technology. Although not used for drilling or direct production, SSRs have been used to support production tie-back lines 6 to FPSOs and other floating production facilities as well as for shallow water intervention by using a SSR with a floating tower to run wire line activities off a workboat 7. The next question is why not use a SSR for drilling? Many of the drilling people would argue it is unsafe: you have a buoyant bomb right underneath the MODU. What happens if you have a catastrophic failure of the riser? The buoyancy device would launch and could damage the MODU. A good question leads to other questions: 1. Can you design a riser and buoyancy device that has almost no risk of catastrophic failure? 2. Can you design the riser and buoyancy device with a minimum risk of sinking and falling over? 3. Can you design the SSR to handle all the well control issues without a subsea BOP? Some of those questions are partially answered. Today material sciences has made it possible to create special stress joints that have extraordinary material properties for superior bending and tensile strength, hoop stresses, and most importantly fatigue failure of the stress joints. Tension leg platforms have been around for over twenty years without a major failure. From these TLP designs stress joints are a standard of the offshore industry. Buoyancy devices of all shapes and sizes have been deployed for decades. There is no doubt Archimedes principle works. Our entire offshore industry, one way or another relies on the principle of buoyancy to support all kinds of structures from weather buoys to the giant offshore floating structures. With the proper engineering why wouldn t it be possible to design various small buoyancy devises to support the riser with various safety features to keep the SSR from sinking or launching. Of course it is possible. It only awaits to the proper design, construction, and testing. One company, Anadarko Petroleum Co. in 2006 deployed such a SSR in 1000m water depth in the GOM. Fig. 5 is a simple depiction of the Anadarko design which is patented pending. Other multiple buoy SSR designs are also patent pending. Figure 5 Self Standing Riser Depiction For the sake of argument, let s expand on the idea that a SSR could be the deep water micro-chip enabler for another approach for deep water drilling, production, completion, testing, production, intervention, and the efficient running of artificial lift technologies like gas lift and electric submersible pumps. The scientific-validationprocess is to first start with the physics of the problem and study all the major challenges to determine if the solution is viable. Can the SSR safely support the riser, can the SSR handle the various sea states; can the riser last 20 years without failure; can the SSR support the BOPs and production tree and provide safe reliable well control. From a more practical point of view can the SSR provide economic designs and flexibility that permit normal offshore oilfield operations? It is not the purpose of this paper to validate the physics of the SSR as described previously. What can be said is anyone competent in riser technology can run the simulations for various sea states and learn the following: 1. With no current a SSR will stay nearly vertical with the proper design and tensioning. With some current the SSR will displace laterally from the vertical depending on the current, current directions, riser design, stress joint design, etc. 2. By moving the SSR some distance below the surface, for example 40 m to 60 m. surface wave action have minimal effects. Even a hurricane state will only cause a few minor transient effects (more of a brief horizontal displacement) if the buoyancy device is below 40 m. Furthermore, state of the art calculations will show

8 8 SPE that a properly designed SSR can have a fatigue life of over 20 years. From a physics standpoint it can be shown that a properly designed SSR could support the loads and resist failure. Assuming the physics is correct the next logical steps would be a verification of the physics by something like wave tank tests. This is a standard marine engineering design step. Again, the purpose of this paper is not to report detailed wave tank results for the SSR which were done, but what can be said if anyone were to run these tests with a scaled SSR under various sea states it is probable the results would match the simulation calculations. Fig. 6 is a picture of one of the wave tank tests with a MODU and a SSR. Operation: Drilling Mode Environment: West Africa 100-Year Swell Rig Orientation: 45 degree Heading Riser System Condition: Intact Figure 6 Wave Tank Testing: Computer models were validated by basin tests. Based on successful physics and verification by the wave tank results the next logical step would be the testing a SSR under field conditions. Such an endeavor was undertaken by Anadarko to deploy a SSR in 1000 ft of water in the GOM (November, 2006) to collect data and further verify SSR simulations and wave tank test results. It is possible reporting of the GOM test will occur in the future. See Fig. 7 which is the buoyancy device suspended under the Helix Q4000 intervention vessel. If the SSR concept is valid and could be the deep-water micro processor chip think of the possibilities. Drilling In a conventional sense any MODU could be used with the SSR. Although many contractors would argue there is no advantage with the SSR and potentially many hurdles that would need to be overcome like the failure of the SSR (either sinking or breaking lose and launching), or the well control problem with the BOPs sitting on the SSR, or a potential run off because of dynamic positioning failure, or the difficulty in deploying the SSR after the surface casing has been run. Like anything that challenges the norm and disrupts a viable conventional technology there are always more reasons not to pursue something different than to try and solve the engineering and operational Figure 7 Self Standing Riser Buoyancy Device Run in the Gulf of Mexico

9 SPE challenges. For example, in most West Africa applications there is near normal pressure, the currents are moderate and the below the mud line depths to the reservoirs are reasonable i.e m to 4000 m. Just by using an anchored MODU the drive off problem disappears. Using some type of subsea shear ram or shut off at the well head gives another level of well control certainty. Using a 9 5/8 dia. tie back liner inside a 13 3/8 in dia. outer riser pipe gives double protection for well control. Simple safety lines attached to the sea floor to the buoyancy devise(s) can prevent launching. Special chambered designed buoyancy devices with other buoyancy safety features can prevent sinking. All very viable solutions and simple. A more practical argument for not using the SSR with a conventional MODU is the extra time and cost to build and deploy the SSR rather than just running a conventional riser BOP package. The question that begs asking is why use a conventional MODU? If you are drilling a place like West Africa with benign sea states why not design a vessel (deep water moored) that can support a simple platform type drilling rig with some modifications for a moderate wave motions. It might be possible this would lead to the Tata Motors cheap car design for deep water drilling! Fig. 8. Is one depiction of such a drilling solution which is also patent pending. What if this facility could be built in such a way a modular rig with the right designs could be used not only to drill but also to run the SSR, complete the well, and provide for the early low cost testing. Maybe this type of rig solution could be built in less than one year and cost less than $50 million. It is further possible the drilling solution could have day rates decidedly lower than the ones today. Then why not do it? It is possible! The overall economic impact on exploration and production deep water drilling in benign areas like West Africa could be immense. No longer would the deep water drilling be the purview of a few. Rigs could be built for both on and offshore use, modularized, standardized, further reducing construction time and costs. EARLY PRODUCTION TESTING Since all the casing is landed in the wellhead at the mudline and the SSR is connected to the well head with another well head at the buoyancy device any number of tie back liners can be run from the mud line well head to the buoyancy device well head. Following drilling, the well could be completed (if considered a potential producer) and production tubing run. A specially designed production tree for shallow water (30m to 60 m) which could be called a damp tree could be used to complete the well with the rig still over the well as a completion rig. This damp tree would be a fraction of the cost of a regular deep water subsea tree. This tree is already available on the market today and is one tenth or less the cost of some of the deep water production trees. The well can be perforated and tested. As mentioned before, with the good formation and fluid properties, in a few hour reservoir boundaries can easily be detected and effective mobility ratios determined. With the damp tree at 30m to 60m on the buoyancy device the production lines are not subject to most flow assurance problems in the shallower warm waters. A simple flexible production line goes to the specially designed floating production unit. Fig. 8 shows one rendition of this unit which is also patent pending. In this case the unit serves three primary functions: 1. Docking station for the drilling station (Fig 9.) shown on the following page, 2. Platform to accept modules for production, water and gas injection, water treatment, and 3. Storage capacity for one to two weeks depending on the production rates. For example, during the testing phase only a sparse testing package would be necessary. Later for the long term testing and production other modules could be added. The importance point is the docking station is part of the total operation from the start providing part of the anchorage for the drilling station (see figure 10). Figure 8 Drilling Station Concept Even though the transient flow and build-up tests can detect boundaries and define effective initial productivity, these tests cannot indicate compartment volumes and potential energy sources from water and gas drives. Only long term production tests can do this. However, with the

10 10 SPE docking and drilling station configuration it is possible to phase from short term testing to long term production testing. It can be shown that in less than sixty days of a long term production test a minimum compartment volume can be ascertained for a production strategy i.e. the need for addition wells in the compartment, an injector and even the placement of the injector. Even an artificial lift strategy can be determined and implemented, if needed. Figure 9 Wet Dock Station Concept Figure 10 Wet Dock Station Concept All of this is possible because the SSR enables a cost effective drilling and completion platform to operate in conjunction with the docking/production/storage station. In this context it is a mini-fpso. Production What really impacts the cost in this realization of the docking station is the flexibility to add and remove various modules as the needs occur. When the well is making little or no water, why have expensive water treating equipment? Also, since the maximum oil production is designed for throughputs of 10k to 30k bopd and the units are modular in design the unit prices can be greatly reduced over larger production systems. If this system could be built for less than $50 million think of the overall economics even at 15k bopd. Once the drilling and completion is completed, the well tested, the drilling station can detach from the docking station and move to another docking station at a different location to commence drilling again. If there are workovers, recompletions the drilling station can return and attach to the docking station and commence operations over the SSR. Another major feature of the SSR design and docking station configuration is the ability to run artificial lift. Because the SSR damp tree is shallow and accessible it would be easy to install and remove electric submersible pumps (ESP) or gas lift equipment. This could be extremely useful for the heavier oil marginal fields. Power for the ESP could be generated on the docking station/mini FPSO. The possibilities are boundless. REALITY VERSUS POSSIBILITY The reality is the SSR shows potential for possibly being the deep-water micro-chip for marginal field deep water exploration and production, especially in benign waters like West Africa. The SSR building blocks are based on sound physics and material science which can create the metallurgy for the stress joints to withstand strong currents and years of motion. Buoyancy devises can be designed and built to withstand sinking or launching.

11 SPE However, the SSR can only be a possibility until it can be used in some type of application that creates a new way to drill cheaper, run effective well tests, and provide new gadgets for low cost production. It is much like the microprocessor. Until the chip found an application like a personal computer it was just an interesting possibility. Then it took years and the right software before the PC became another reality to the mainframe. Maybe the SSR can provide the basis for building a low cost drilling and docking stations like presented in this paper. And maybe this new deep water PC can greatly impact the exploration and development of marginal fields. Maybe there are other great ideas for the use of the SSR for other applications beyond the benign sea state areas. Maybe the SSR could help unlock deep water heavy oil? Maybe the SSR can enable the technology to do cost effective intervention using coiled tubing from a vessel like a workboat. Maybe the SSR could enable new concepts in early testing in deep water wells. Maybe the SSR could be used to enable another way to provide water injection. Again, only the imagination can limit what could be done. However, the reality of anything new like the SSR concept to enable all these new applications requires some first time risk takers accepting the challenge and working towards making possibilities become realities. Only time will tell. ACKNOWLEDGEMENTS This paper is a summary of the work by team of engineers and geo-scientists who wanted to find a new way to exploit marginal oil and gas fields in deep water. Rather than leave someone out the author would like to acknowledge all of dedicated individuals and supporters who made contributions to this project. You know who you are. The author would like to acknowledge Anadarko Petroleum Co. for its support on the project. REFERENCES 1. Marshal DeLuca: Surface BOPs free modest semis for immodest depths. Offshore Engineer, March SBOP drilling from a floating rig was originally used in the 1960s but was popularized for the deepwater by Unocal in the early 1990s through its SX exploration drilling program off Indonesia. 2. William Furlow: Shell takes novel solution to new depths First DP application of SBOP offshore Brazil, Offshore Magazine, March Atlantis Deepwater Technology Holding AS. The Atlantis Artificial Seabed Concept. A Step Change in Deepwater Technology. Presentation Tata Motors: Bombay, India of 24 Homi Modi Steet. India's largest automobile company started in 1945 with over 4 million cars on Indian roads Gustavo Castro, Petrobras; Bruce Crager, Consultant; Petrobras Leads in Deepwater EWT with DP FPSO, Offshore Magazine, September, Girassol Project: Total. Offshore Angola, Block 17, Subsurface Riser Tower with Flexible Hoses to FPSO. 7. Pieter G. Wybro, I Kadi; FH Rodriguez; Subsea Wirelining Innovation Operational at Kepiting ; Ocean Industry, 23 (1988), p. 26 (June).