Deepwater challenges dominated technical presentations at the recent Offshore Technology Conference in Houston.
Replacing reserves in deep water will require predicting outcomes earlier in the cycle. Drilling in deep water will face increased subsea geohazards.
New tools and evaluation methods are being used for producing oil from previously inaccessible areas and from deepwater subsea wells.
And moving production in deepwater fields from well site to platform or floating production facility will challenge existing technologies for flowline design, maintenance, and repair.
Replacing reserves
Exploration departments grappling with replacement of the first wave of deepwater reserves face enormous technical challenges, said Dodd DeCamp, formerly with ARCO and now an exploration vice-president with Phillips Petroleum Co.
The main challenge is to advance the ability to predict outcomes earlier in the cycle. The key need in this area is to deal with multiple attenuation; in other words, to develop better techniques for removing multiply reflected events from seismic data.
"It is not enough to predict the correct predrill structure and stratigraphy of the initial discovery well," DeCamp said. "Extraordinary predrill prediction of reservoir architecture, reservoir properties, and long-term performance are now also necessary earlier in the exploration and development cycle to dramatically reduce delineation and development costs and rapidly implement optimal depletion plans."
As the industry pushes the envelope of water depth, objective depth, and complex geologic settings, its tolerance for risk decreases.
DeCamp said that more than 35 billion boe has been discovered in more than 500 m of water and that only about 20% of that has been placed on production. Deepwater production, an estimated 1.5 million boe/d now, at a minimum will more than double in 8-9 years.
Developments are moving into more than 1,000 m of water, exploration beyond 2,000 m, and rig capabilities beyond 3,000 m.
To manage subsurface risk most effectively, DeCamp said, "we want a complete and accurate model of the subsurface, including the rock properties and fluid content of both overburden and reservoir intervals."
Kirchoff imaging has served as the industry standard and workhorse in 3D, but wave-theoretic imaging techniques are being used increasingly. This involves more-comprehensive imaging and inversion techniques that require data free of multiples.
Addressing hazards
Geohazards such as shallow water flows, hydrates, mud volcanoes, seabed topography, and slump-fault features became a key topic for drilling professionals and earth scientists.
Discussions spread out over several technical sessions disclosed three concerns offshore operators must deal with: site selection, surface and subsurface geohazard avoidance, and geohazard mitigation.
Fortunately, a continuing trend towards multidisciplinary teamwork, involving civil engineers, drilling engineers, geologists, petrophysicists, and geophysicists, has provided rig crews and team members with open networks of information, allowing for better location selection and improved decision making.
Drillers take note
While preparatory work for offshore site selection continues to take advantage of sophisticated sensing technologies and data packages, operators must now pay greater attention to the threat of near-surface geohazards (mudline through intermediate casing point), perhaps as much as they do in the lower pay zones. Otherwise, uncontrolled events may result in well-control situations, lost wellheads, poor cement jobs, rig instability, damaged casing, reentry problems, and even abandonment.
According to Mark Alberty, BP Amoco PLC, shallow water flows (SWFs) on 106 recent wells cost the industry $175 million ("shallow" in this context refers to the subsurface, not water depth). On these locations, operators spent 64% of their time performing remedial work, the remainder on prevention measures.
A new definition
Alberty proposed an expanded definition for this worldwide problem:
"Shallow water flows are the occurrence of geopressured sands above the point that the well design would normally permit the installation of the conventional marine riser and blowout preventers (BOPs), providing a hydraulically closed system, which provides an overbalanced drilling environment."
As such, techniques used to resolve SWF problems must consider the physical properties of the sediments. For example, shales and sands take on a "lower state of compaction for a given depth below the mudline."
Accordingly these rock types take on higher porosities and lower compressive strengths. In turn, sands will also exhibit higher permeability values, larger pore throat sizes. Thus, formation temperatures become lower in SWF, as formation pressures become higher.
"Each of these physical changes can impact drilling practices," Alberty said. For example, the lower rock strength impacts the rate of penetration and dilation properties of sands and shale. This, in turn, impacts torque and drag.
And because shales contain a higher water content, clay problems can result in increased balling up of bottomhole assemblies.
Just as important, dealing with hydrostatic and formation pressure relationships has become a top priority. "SWF is a problem in narrow margin drilling, which arises from a combination of sand over-pressure and low formation strength," said John Pelletier, Shell International E&P Inc., in another presentation.
"Drilling shallow, soft, and overpressured formations with a long riser full of weighted mud and controlling ECDs [equivalent circulating densities] within a tight margin, is no simple proposition, given margins as low as 0.2 to 0.5 ppg," he said.
Basically, if pore pressures are not controlled, the shallow sand formation will flow, leading to washouts, ineffective cementing, sand compaction, damaged casing, and hole reentry problems.
SWF indicators include shifting conductor pipe, kicked drill pipe, excessive torque and drag, and reduced formation salinity. Alberty said SWF risks can be mitigated by avoiding the crests of SWF sand structures and educating all key team members on the nature of SWF.
He says future SWF problem-solving strategies will include:
- The use of oversized marine risers.
- Drilling with weighted mud and returns to the seafloor.
- The yet to be deployed rotating subsea BOP stacks and dual gradient drilling systems (OGJ, Aug. 16, 1999, p. 32).
Offshore Nigeria
U. Yahaya-Joe, SNEPCO-a consortium of Agip SPA, Esso Norge SA, and Elf Aquitaine SA (TotalFinaElf SA)-said "geohazards prevalent in deepwater environments are significantly different than those found in shallow marine, shelf, and slope environments." The company, which has drilled seven wells to date off Nigeria, is operating in water depths of 200-1,500 m.
He said some of the hazards encountered in deep waters include:
- Surface debris and obstructions.
- Incompetent sediments.
- Slump and scour features.
- Steep faulting and glide planes.
- Shallow gas pockets.
- Mud volcanoes.
- Gas hydrates and moulds.
- Overpressured zones.
Data used to access these occurrences include both conventional and reprocessed 3D seismic, 2D and 3D high-resolution seismic, seismic velocity data, analog site surveys, and core samples.
The 3D seismic data are used for an improved understanding of the environment of deposition and sedimentological units and high-resolution 3D can be used to depict "vivid images" of the sea bottom.
And in exploration plays with limited well data, seismic velocity data can be used to detect overpressure zones and hydrates. In additional, analog site survey data, which include high-frequency data acquired from echo sounding, sidescan sonars, and subbottom profiling, can provide accurate bathymetry maps, seafloor mosaics, indications of seafloor gas, and shallow fault detection.
Finally, digital site-survey data lead to improved imaging of the subsurface near the seafloor, leading to improved fault and thin-bed mapping. Unfortunately, although these data consist of higher frequencies than 3D seismic, "they have the disadvantage of being unable to resolve the 3D nature of the hazards," Yahaya-Joe said. "However, when used in conjuction with 3D data, they aid in the interpretation."
With these data, gas pockets can be depicted by seismic data and attribute analysis that produce anomalous high amplitudes and reflection time sags. Similarly, indications of hydrates can be found with seismic data, attribute, and velocity analysis.
Mud volcanoes and pock marks, on the other hand, can be depicted through 3D seafloor visualizations and seismic sections, said Yahaya-Joe.
Moreover, seafloor debris can be seen with sidescan sonar, while slumps and faults can be shown as breaks in seismic reflections using 2D and 3D seismic sections and time slices.
Tools, evaluation
Producing oil from previously inaccessible areas and from deepwater subsea wells requires new tools and evaluation methods.
Halliburton Energy Services' Anaconda system aims to allow the industry to gain access economically to more portions of mature fields, while Chevron Corp., in its deepwater Kuito development, relied on dynamic models to design downhole orifices properly for its gas lift system.
Accessing remaining reserves
At OTC, Halliburton Energy Services introduced a system for enhancing reservoir drainage. The company said this drilling system, featuring carbon-fiber composite coiled tubing containing embedded electric conductors, can drill more-complex and longer well paths than currently feasible with heavier steel-tubular-based systems.
David Lesar, president of Halliburton Co., said "This is the first real step change in well construction and intervention processing in over 20 years."
Halliburton developed the Anaconda system in conjunction with Statoil AS, which will apply the tools to drill wells for draining currently inaccessible remaining reserves from some of its mature North Sea fields, such as Gullfaks.
The embedded electric conductors allow for two-way transmission of data signals from downhole to surface and control commands and power from surface to downhole. The downhole real-time data are received at surface several thousand times faster (156 kilobytes/sec) than currently available systems, Halliburton said.
The surface equipment includes a control center, injector and reel, a tower and pipe-handling system, blowout preventer, and a digital control and data-acquisition system. The equipment's footprint is small enough so that the equipment can be used on many types of wellhead or production platforms.
Operating the system will be a three-person team that includes a pilot to run the equipment, a systems engineer to maintain system integrity, and a navigation engineer who interprets the sensor data, builds detailed subsurface maps, and guides the well path.
Halliburton said that, for additional flexibility, these functions can be performed from remote locations, when required.
The bottomhole assembly (BHA) includes a standard drillbit, mud motor, and direction sensors along with tools such as:
- A 3D steering tool that is dynamically controlled to maintain the optimum well path. It can build rates up to 60°/30 m. No BHA rotation is required, and the tool can be adjusted to a 0° bend for drilling straight holes.
- A resitivity tool with five transmitters and dual frequencies to provide 16 depths of investigation.
- A quad-gamma ray tool with four sensors, each reading from a 90° segment of the wellbore.
- A pressure-while-drilling tool to convey mud-motor performance data in real time and also monitor borehole conditions.
- A circulating sub with angled jets to ensure high-velocity hole clean.
- Dual tension and compression tools for maintaining the composite tube in tension and for optimizing weight on bit while drilling.
- An electronically sequenced tractor for controlling weight on bit while drilling and for pulling the tools into high-angle laterals. Hydraulic forces propel the tractor when electric commands are sent from the surface control center.
- A cased-hole collar locator.
Halliburton's first system includes a reel with about 22,000-ft of 27/8-in. composite tubing and a 31/8-in. OD BHA. The tubing was jointly developed with Fiberspar Spoolable Products.
Halliburton has used the system to drill one test well at its Duncan, Okla., facility and is preparing to drill another well soon.
At present, nonspoolable connectors are available for the tubing, and Halliburton is working on developing spoolable connectors.
Halliburton's plans include developing larger-sized tubing and tools that might be able to reach 50,000-ft measured depths.
According to Jody Powers, president of Halliburton Energy Services, "This technology will bring together formation evaluation experts, drilling engineers, reservoir engineers, geologists, and geophysicists to make better decisions."
Deepwater gas lift
In deepwater well completions, many operators include gas-lift capabilities that will provide artificial lift once natural flow from the well declines.
Shauna G. Noonan, Chevron Petroleum Technology Co., and Kenneth L. Decker, Decker Technology, presented one such design for the Kuito field, off Angola's Cabinda enclave.
They said that because deepwater well intervention is very costly, a subsurface gas-lift system must be designed for the life of the well, and unloading and operating procedures must be tailored to minimize erosion of the gas-lift valves and orifices.
For the Kuito development, Chevron used dynamic modeling to determine an optimum orifice size for long-term operations over a given range of injection rates, water cuts, and productivity indexes.
A dynamic model aided in developing start-up procedures that minimized erosional effects on the downhole orifice and helped answer questions regarding cyclic production pressures at the subsea wellhead.
Kuito field, discovered in April 1997, lies on Block 14, in 200-1,500 m of water. The field went on production in late 1999. The initial development phase includes a 12-slot subsea production manifold and a remote gas injection well with the crude oil being produced to a floating, production, storage, and offloading (FPSO) vessel for processing.
The field produces with a 200 scf/bbl GOR, and Chevron selected gas lift to eliminate flaring the associated gas.
In the Kuito wells, Chevron installed a single-point gas injection valve with 0.3125-in. square-edged orifices made of hardened materials. The orifices have a moveable check piston to keep the valves in a closed position until a preset differential has been applied.
The authors said that the gas-lift design for this deepwater development differs from conventional wells primarily because the intervention costs for these wells are considerably greater than for traditional completions. Gas-lift, therefore, must be designed with special attention to reliability and longevity.
To size the port, Chevron designed the operating valves based on anticipated production conditions over the life of the well. Although the wells are equipped with sidepocket mandrels, Chevron expects the costs of replacing the valves to be too great to justify the work. The valve design, therefore, had to consider a wide range of production conditions.
Unlike a conventional gas-lift installation with several nitrogen-charged unloading valves, Chevron installed only one valve per well without nitrogen bellows because of the possibility that either the nitrogen charge in the dome could leak off or the bellows itself could fracture at the high gas-injection pressures.
The elimination of the unloading valves posed two other considerations that require special attention:
- The port in the square-edged orifice valve had to be sized to anticipate a wide range of flowing conditions-too large a port would encourage unstable lifting conditions; too small a port would lower production rates.
- Because the orifice valve is the only avenue for fluids in the annulus to be unloaded, Chevron had to ensure that the orifice port would not erode during unloading of the annulus.
Chevron addressed this possibility by specifying an orifice valve treated with a surface-hardening process and by closely monitoring the gas-injection rates at the surface during the unloading process.
Flowline efforts
Optimum design and installation of flowlines, especially for the deeper environments envisioned by many presenters, were the main pipeline problems addressed in several papers at OTC.
Options
Deepwater development in the US Gulf of Mexico must address the added complexity of flow assurance in colder environments, higher pressures, longer well offsets, and greater repair difficulties.
Margaret Hight and Janardhan Davalath, FMC Energy Systems, reviewed the various systems currently available to combat flow problems in both oil and natural gas flowlines in deep water.
They reported on a simulation study that used four fluid compositions, to represent black oil, volatile oil, condensate, and dry gas.
One phase of the study looked at single vs. dual flowlines and concluded that dual lines offer greater flexibility in capacity and velocities as well as the capability for round-trip pigging that may be needed as part of a paraffin-control program.
Single flowlines, they said, may be desirable when hydrates and paraffin deposition may not be a problem or can be controlled chemically.
The second phase of the study looked at flowline thermal options.
For liquids-dominated fluids, pipe-in-pipe (PIP) flowlines can more than double the flowline costs and may not be justified for a field that is only marginally economic. The most flexible option for preventing thermal losses is electric heating, because it can be used only when needed. It is also less costly than PIP.
External insulation and burial are also effective for heat conservation at high rates, but dual flowlines may be needed later in a field's life to keep flow rates closer to design.
For gas flowlines, Hight and Davalath said, heat loss is always going to occur over long distances regardless of the thermal insulation or pipe burial.
Temperatures at less than ambient levels can be avoided by sizing flowlines with sufficient capacity to avoid excessive pressure losses.
Another phase of the study looked at remediation options. As background, the authors noted that a survey by the Deepstar project had turned up 55 documented cases of hydrates and paraffin blockages, almost all of which occurred in uninsulated flowlines.
And they indicated there are three important considerations for handling flowline blockages: flowline monitoring, locating blockages, and removing blockages. For the latter, various hydraulic, thermal, and mechanical methods are available, according to blockage type (hydrates or wax) or severity (partial or complete).
The final part of the study compared capital costs of the various flowline options in a base case of dual 4.5-in. OD uninsulated flowlines using burial, external coating, PIP, and PIP with electric heating.
Burial vs. PIP
Recent in situ and laboratory investigations have indicated the thermal conductivity of deepwater soils is far better than previously thought. Kenneth Loch, Stolt Offshore Inc., said those findings and recent advances in flowline burial warrant a reconsideration of buried and coated (B&C) flowlines for longer distances.
These single-skin flowlines have generally been limited to short and medium distances.
The preferred design for longer flowlines, said Loch, has been PIP technology, which is comparatively difficult to manufacture, install, and repair and is overall more expensive than single-skin flowlines.
B&C flowlines, he said, can provide the required steady-state outlet temperatures for many long flowline systems at a fraction of the cost of equivalent PIP systems.
Loch presented a comparison of the overall heat-transfer coefficient (OHTC) or U value for bare pipe, coated pipe, buried pipe, buried and coated pipe, and PIP.
Burial of bare pipe provides insulation equivalent of about 60 mm of low-conductivity, external coating. Combining burial and coating achieves U values that approach PIP.
If lower soil thermal conductivity or thicker external coating is used, the B&C system can achieve the same U values as PIP.
More importantly, the fully installed costs of a PIP system are more than double those for a comparable B&C system.
Further comparisons of PIP with B&C systems, on the basis of maintaining fluid temperature within a narrow range, indicated that burial alone provides greater thermal insulation than do significant amounts of low-conductivity external coating.
And when combined with external coatings, Loch said, B&C systems have steady-state thermal performance near those of PIP.
Estimated potential savings of B&C over PIP for deepwater flowlines is about $10-30 million, depending upon flowline size, length, and installation water depth.
In addition, B&C systems have realistic repair scenarios, he said. PIP systems, on the other hand, are difficult, if not impossible, to repair using existing technology.
Heating
Electrically heated flowlines offer a fundamentally different and simpler approach to managing hydrates in deepwater oil flowlines, when compared with conventional solutions.
That was the message of F.M. Pattee and F. Kopp, Shell International Exploration & Production Inc., in a presentation that compared electrically heated pipe (EHP) with more widely used methods for both gas and oil pipelines.
EHP is a fast-maturing technology that has the potential to be cost-competitive in deep water, said Pattee and Kopp. At present, there are three basic approaches for providing electrical resistance heating to flowlines: "perfect insulation," "earthed current," and "pipe-in-pipe." Statoil AS, for example, employs an earthed-current system in its
Using general cases and generally identified field examples, the authors examined operational aspects in detail, comparing them with the operating sequences currently used with the "blowdown strategy."
The primary benefit, they said, can be seen in the management of hydrates.
For oil flowlines, Pattee and Kopp concluded, EHP systems offer distinct operational advantages over systems designed according to the blowdown strategy, including substantially simplified operational activities, increased system availability, and the ability to remediate hydrate plugs.
EHP flowline systems may also extend the conditions in which successful flow-assurance designs can be achieved and enable single flowline developments.