Advancements in engineering/design and field operations
Three special reports describe computer-based facility design tools, advantages of data storage and insight into key riser tension calculations to aid design engineers. A special facility for pre-testing downhole tubular cutting tools is described. And three U.S. independents and an engineering company describe successful field projects presented at a recent conference on maximizing recovery.
The new technologies presented here include: 1) a unique fixture to pre-test down-hole chemical cutters; 2) how 3-D modeling decreased CAD time for a unique North Sea rig design; 3) shared experiences from four projects that improved recovery and profits; 4) important basic facts about calculating riser tension and mud weights; and 5) how geologists’/geophysicists’ productivity was increased with a data storage system.
Unique chemical cutter test fixture
Patrick C. Hyde Engineering, Hurst, Texas; and Monty Harris, President, Harris Tool & Specialty, Inc., Azle, Texas
Recovery of tubular strings by down-hole chemical cutter or radial cutting torch becomes a more complex problem when considering all combinations of metallurgy, pressure, temperature and fluid media. With increased day rates, testing to verify cutter performance is a sound economic decision. The technical problem is how to set off an explosive device inside a closed test chamber under simulated wellbore conditions–and do it safely and economically.
The test fixture shown in Fig. 1 is the evolution of years of experience with different types and sizes of cutters and tubulars, as well as a myriad of wellbore fluids, pressures and temperatures. Advantages and use of the test fixture are presented here, along with results of two case history applications.
Objectives, test approach. The ideal situation is to perform a cut in an actual wellbore, using volume effects of the relatively large (compared to a test fixture) axial capacity, both above and below the cutter. The first hurdle is to design a fixture that will simulate volume both above and below. The second obstacle is the firing of an explosive in a closed vessel of relatively small volume, under pressure and temperature. The final obstacle is to accomplish a technically realistic simulation both safely and economically.
The most straightforward method of simulating well volume in a test fixture is to employ a nitrogen ([N.sub.2]) gas cushion. This approach was used in early testing, in which fluid levels were dropped about 6 ft and the top of the fixture was filled with [N.sub.2]. In a simple fixture design, this provides a cushion on top of the fixture, but provides no cushion from below.
While this simulation is realistic when cutting on top of a plug, or close to TD, it does not represent firing a cutter at some distance from an obstruction. Early testing also resulted in abnormally high vessel pressure, accompanied by the occasional venting of high-pressure gas at the time of the cut.
To understand why it is necessary to go to some length to simulate volume below the cutter, it is necessary to understand one of the primary requirements of a good cut; i.e., the cutter must remain stable (not move) in the axial direction during the cut. To accomplish this objective, cutter designs feature some method of anchoring the severing head inside the tubular to be cut. That method usually employs round anchor buttons with wickers, located above the severing head and activated by increased internal pressure of the reacting chemicals. The anchors must extend and “grip” the tubular before energy is expended at the severing head.
When the cutter operates, high-pressure gas exits the severing head nozzle. If there is an obstruction close and below the cutter head, pressure waves return rapidly to the bottom of the tool, tending to lift the cutter head, thus placing axial loads on the tool (and the anchor system) that are considerably greater than those expected in wellbore operation. The return time of these waves is also considerably less (less distance traveled) than in actual operation.
Fixture design features. Design and fabrication of the cut fixture features an [N.sub.2] cushion both above and below the cutter to simulate “wellbore volume” in both places. The cushion above is obviously provided by the [N.sub.2] cushion in the tubing above the cutter. The cushion from below is accomplished by an additional concentric tubular with [N.sub.2] in the annular area between the tubular to be cut and the outer vessel housing.
The 6-ft [N.sub.2] column in the tubing cushions fluid above the cutter, and fluid below the cutter is cushioned by another 6-ft [N.sub.2] column in this annular area. The two columns can be isolated or connected; the effect is the same.
When activating an explosive in a closed chamber, a method of safely controlling maximum vessel pressure must be devised. Should a device malfunction or simply liberate an amount of high-pressure gas sufficient to damage the fixture (exceed its internal pressure rating), a relief system must be employed. The fixture employs independent shear type relief devices that trigger at [approximate] 11,200 psi both on top of the fixture and in the bottom plug. Since cutters are generally run toward the bottom of the fixture, abnormal events often generate pressure waves that can damage the fixture on bottom before they lift the column of heavy fluid and activate the upper shear-type relief; hence, the bottom plug shear device.
Situations have been experienced in which the lower shear device was activated with the top completely removed from the fixture. Both devices are identical in design and open a 3/4-in. hole to “atmosphere.” The lower device opens a port to the bottom of the well and the upper device opens a port to a 2-in., 15,000-psi-rated flowback system with de-energizer. These devices open the upper and lower ends of the tubing to atmosphere, should tubing pressure approach rated vessel pressure. An optional Autoclave Engineers burst disk mounted in a 1/4-in. connection can be installed in the upper annulus to relieve gas pressure.
Testing proved that the upper and lower cushion design is effective in simulating volume, but some cutters increased internal vessel pressure in excess of 2,000 psi when fired. Since this condition would likely not be present in wellbore operation, it was obvious the cushion had to be larger on both sides. Cutters are sensitive to external pressure, and increased external pressure during a cut would prove to be detrimental and would definitely skew test results.
Vessel internal volume could be increased to provide the extra cushion necessary, but that would require a long and expensive fixture as well as a large volume of high-pressure [N.sub.2] each time a cut is made. To reduce cost/time to increase pressure, a high-pressure test chamber (22,000-psi WP) was converted to an accumulator for use in cut tests. The accumulator is dressed with a 1-in. X 2-in. plug valve and 1-in. hose to the vessel’s tubing and annulus chambers. The manifold system used in cut testing is shown in Fig. 2.
The accumulator can be pre-charged with high-pressure [N.sub.2]. Pre-charging also reduces time to reach test pressure, as only fixture pressure must be increased from ambient. Just prior to firing the cutter, the plug valve is opened, introducing the added accumulator volume to the circuit. When the tool is fired, gas is exchanged between fixture and accumulator. This cushions internal gas pressure in the fixture by effectively increasing fixture total volume. Prior to normal pressure release, the plug valve is closed. Since high-pressure gas is trapped in the accumulator after a cut, it need not be pressurized for subsequent cuts, saving time and [N.sub.2] expense.
Should there be a problem with the [N.sub.2] pressurizing equipment, vessel pressure can be increased by introducing high-pressure liquid through a line installed in the bottom of the fixture.
Results. Using this cut test fixture, vessel pressure increase has been limited to a few hundred psi when the cutter is fired. Cuts have been more uniform, and cutting tools are retrieved in excellent condition. The pressure chart illustrates a chemical cut at temperature and pressure. The example pressure chart is for high-chrome, heavy-wall 4 1/2-in. tubing inside 9 5/8-in, casing, Fig. 3.
In the first of two example case histories, British Borneo Exploration, in the process of re-completing a deepwater subsea well in the Gulf of Mexico, required a reliable tubing cutter to function under conditions of 9,000 psi at 150[degrees]F in CaBr fluid. Tubing to be cut was 3 1/2-in., 13 Chrome material. Operating a chemical cutter at this elevated pressure has a prominent effect on performance. Pressure generated by the chemical mix must overcome pressure outside the cutter, in addition to the pressure required for an effective cut. Using a conventional tubing cut fixture would result in a vessel’s considerable pressure increase over hydrostatic, resulting in inaccurate test data. Use of the cut fixture described here resulted in a pressure spike of only 650 psi, declining immediately to a net vessel increase of 67 psi, as a result of produced gases and liberated heat.
Shell U.K. required that a 7-in., 29 ppf, SM2535-125 tubular be parted inside 9%-in., 47 ppf casing under 4,200 psi and 265[degrees]F, in brine water completion fluid. The objective was to completely part the tubing without damaging the parent casing. When cutting this rather-large tubular, vessel pressure spiked only 720 psi, with residual pressure increase of 100 psi as a result of produced gases and liberated heat. Using a conventional cut fixture, increased vessel pressure would result in inaccurate test data when evaluating parent casing damage.
3-D modeling decreases CAD time for drilling system design
By creating a 3-D model of the Snorre B RamRig, Aker Maritime’s Norwegian subsidiary, Maritime Hydraulics, completed the CAD design in 50% less time than if it had used 2-D CAD. And when the rig was assembled, there were practically no clashes–an unlikely occurrence when a large project such as this is done in 2-D. Instead of designing the various components of the rig separately and documenting them on a series of 2-D drawings, engineers created a 3-D model of the entire system–including piping, structural, architectural, electrical, HVAC and mechanical components–based on AutoPLANT from Rebis, Walnut Creek, California.
When changes to the design were needed, they were done on the 3-D model instead of modifying individual drawings. After the design was finalized, fabrication drawings were generated automatically. Time saved was the result of several factors, such as the ease of making changes on the model vs. revising drawings by hand, and the speed of generating isometrics automatically. The lack of clashes was the result of the superior visualization 3-D modeling provides, as well as the ability to include components from all design disciplines into one model.
Aker’s RamRig concept for drilling/workover packages can be used for both fixed and floating installations, Fig. 1. It is available as single, double or triple stand rigs, with capacities from 150 to 1,000 t. Hoisting and lowering is done by two cylinders instead of the conventional drawworks and derrick. Hoist lines are fixed length, parallel lines with one end anchored at the drill floor, the other at the top drive. The lines are run over the yoke sheaves, thereby transforming the push from the rams to upward lifting force to the top drive. Main benefits are lower weight and cost, greater efficiency, and improved safety over conventional packages.
Tight space. The Snorre B project involved installation of a RamRig system on an offshore platform in the North Sea. This project was a joint venture between Aker Maritime and Kvaerner Oil & Gas. It involved design/construction of a semisubmersible drilling/production platform for Norsk Hydro ASA. In addition to the rig supplied by Maritime Hydraulics, the platform features combined cycle power generation units (gas turbines and steam) and an undersea power cable linked to Snorre A for import and export of excess power. Snorre B exports oil to Statfjord B and gas to Snorre A.
The total RamRig weight was 1,400 mt, with dimensions of 20 m X 20 m (66 ft X 66 ft). This was a very small area in which to fit a great deal of equipment, including manifolds, cabins and tensioning system, as well as all the mud and hydraulic piping. A RamRig uses high-pressure hydraulics to lift the drill string. There is very high flow on those lines, many of which are 8 in. in diameter. All piping for the drill system had to fit within the rigs dimensions. Height was limited by the low drill floor and the BOP height, leaving less than 5 m of effective height, Fig. 2.
The Snorre B was Maritime Hydraulic’s first use of advanced 3-D modeling. In previous projects, engineers had used 2-D AutoCAD to place equipment, pipes, structural steel, and so on. Routing pipe this way was particularly difficult in 2-D because it required piping engineers to imagine elevations and indicate with elbow symbols whether a pipe went up or down. They had to maintain consistency with other drawings as they worked, visualizing the Z component of those other views as well. Each 2-D drawing was actually an exercise in piping design.
Another drawback to working in 2-D was the difficulty of detecting interferences when only two dimensions were visible. This was true within a single discipline, such as piping. Designers used plan, section and elevation views to try to spot clashes, but if pipe heights on two drawings did not match perfectly, it was possible for an interference to go unnoticed. It was also difficult to detect interferences between different disciplines because they typically did not share a common base like a 3-D model.
A third drawback to the previous 2-D method was that once a design was done, it was necessary to produce, from scratch, all of the isometrics and other drawings needed for fabrication. A typical project required hundreds of isometrics, and this could be one of the most time-consuming aspects of a project. Finally, when changes to the design were needed, it was necessary to make modifications on the drawings. This was time-consuming since one change could affect many drawings. It also compromised accuracy because it was possible to overlook a drawing that should have been changed.
These drawbacks, combined with the tight space limitations of the Snorre B project, led Maritime to consider upgrading to 3-D plant design software. The search was limited to programs that ran on top of AutoCAD since this program was so widely used, both within the company and in the oil/gas industry. Maritime chose AutoPLANT because–in addition to being an AutoCAD add-on program and providing full 3-D modeling capabilities–it included modules for specific design disciplines. This would make it possible to exchange 3-D models between disciplines and automate more of the design process.
For example, rather than sketching crude representations of mechanical equipment, a structural engineer could place existing equipment models into his design. Maritime purchased five sets of AutoPLANT Piping, one set of AutoPLANT Equipment, two sets of the intelligent piping and instrumentation diagram (AutoPLANT P&ID) application, five sets of the AutoPLANT Structural steel design module, and four sets of AutoPLANT Isometrics, which produces isometric drawings automatically from the 3-D model. The company also purchased the necessary import/export utilities from Regis for transferring AutoPLANT data to AutoPIPE and ISOGEN. The software was purchased from Mandal Engineering Co., which also provided implementation support.
Team design. Fifty engineers worked on the Snorre B project, with about 20 working concurrently in AutoPLANT. Some had previous experience working in 3-D, but the company also provided two- and three-day training sessions to familiarize everyone with the new software. On this project, the mechanical, piping and structural engineers worked in AutoPLANT, while those in the electrical, architectural, and HVAC disciplines used plain 3-D AutoCAD. Mechanical engineers used the Equipment module to model and place pumps, tanks and other vessels in the model. This module automated much of their work by providing a library of parametrically defined components. With the library, an engineer simply entered a few values representing the equipment specs, and the software drew the model.
Piping engineers used the Piping module to route the pipe. To do this, they drew lines indicating where pipes should be placed, as they would in 2-D. But rather than simply having geometric representations, the digital model of each pipe was actually an object containing additional information from the database, such as performance and material specs. And because the engineers were working in 3-D, they were able to include the Z dimension in the model–routing a pipe 10 m horizontally, for example, then up 5 m, and then horizontally another 10 m.
Another benefit of building a 3-D model of the piping was that entire lines were visible, compared to drawings that showed only pipes in a certain section of the rig. When an engineer finished routing a line, he could see the impact of his work immediately, rather than flipping through 2-D drawings and trying to follow it. All these features helped speed the process of routing pipes; but what made this approach significantly faster than 2-D was that, with the 3-D model, piping was designed only once, instead of over and over again on each individual drawing.
Structural engineers originally used plain AutoCAD to design the structural framework of the Snorre B rig. Then they realized how easy it would be to convert their work to 3-D using the Structural module. This application provides the functionality needed for: placing 3-D structural steel, including drawing setup and creation; 3-D grid placement; steel placement and database management; steel editing and display options; steel annotation; and access way (stairs, ladders, platforms and handrails) placement.
Similar to the Equipment module, Structural Modeler has a library of standard shapes. When an engineer wants to run a beam from one location to another, he simply chooses beam shape and indicates desired location. The software draws the model of the beam automatically. On this project, engineers simply selected lines from the AutoCAD drawings, indicated in a dialog box the type of members they were, and the software drew the 3-D shape.
Although electrical, architectural and HVAC engineers used plain AutoCAD, everyone’s work contributed to creation of the 3-D model, since geometry created in AutoCAD could be referenced into the 3-D model by means of the AutoCAD “x-ref” feature. This made it possible for engineers to reference each other’s models and be aware of other design changes that affected their work–this was one way that the company was able to eliminate clashes. But Maritime also used AutoPLANT’s Explorer module after the entire design was complete to perform a thorough evaluation for clashes. The software recognized all one-, two- and three-dimensional AutoCAD entities for viewing and interference detection, including lines, polylines, 2-D surfaces, meshes, 3-D faces, ACIS solids, and blocks, as well as any custom 3-D objects created with AutoPLANT.
Some interferences were found during this operation. The changes necessary to fix those problems, as well as others, perhaps requested by the customer, went much faster compared to those done in 2-D. This time, changes were made by modifying the 3-D model. It was not necessary to alter any individual drawings because drawings are associative to the model and are updated automatically when the model changes. This was much faster than going back and modifying many drawings to reflect a change; it was also more accurate. When the team worked strictly with drawings, it was possible to miss some that were affected by a change. That did not happen, because drawings were “spun off” from the model.
Isometrics were the only form of piping drawing used on this project. They were not produced by hand, but generated automatically from the model. Engineers simply selected the views they wanted and commanded the software’s Isometrics module to create the drawings. Only a few minutes were spent on each drawing, doing minor touchup such as adding a special number required by the customer. All the other information was automatically extracted from the model. The drawings had elevations and dimensions tagged and located, for example, and materials for purchasing were automatically derived from the database. Drawings produced in this manner required minimal checking because the software ensured that they were consistent with the 3-D model.
The RamRig was installed on the Snorre B platform in May 2000. Though it was clear to Maritime that working in 3-D significantly reduced design/documentation time, the company was even more pleased with the new approach when the rig was assembled and there were no clashes.
Shared experiences from extra-recovery projects
E. Lance Cole, National Project Manager, Petroleum Technology Transfer Council (PTTC)
With higher and stabilized (?) oil and gas prices, producers are exploring project opportunities for improving oil and gas recovery. In a recent conference, producers and technology providers alike shared their experiences. Applications varied from proven, widely accepted technologies, such as gel polymers, to more leading-edge technologies like seismic stimulation.
Those participants looking for opportunities in the reservoirs/fields they manage received broad exposure, sufficient for determining which technologies might be a match for their opportunities. Of significance, the expert speakers themselves learned from the experience, both about processes outside their normal realm of expertise and from penetrating questions from other experts.
Maximizing profitability through rapid field development, East Texas tight gas. Historically, conventional wisdom has led to staged developments of tight-gas discoveries in East Texas. These developments have characteristically used a series approach, where waves of development activity progressively down-spacing the field are separated by periods of monitoring, testing and evaluation. Using this approach, optimum well spacing is not achieved until late in the field life, and performance of later infill wells is often lower.
In East Texas tight gas sands, Anadarko Petroleum Corp. has found that a parallel approach to evaluation and development not only increases the asset’s present value, it can improve recovery as well. These improvements are primarily associated with one thing–developing at the optimum spacing early in the field’s life. As with conventional development, initial well spacing is greater than optimum, but the parallel approach allows further development to occur (with confidence regarding optimal spacing) during the conventional monitoring, testing and evaluation period.
To manage risk, Anadarko combines early data acquisition (cores, logs, samples and daily well performance information) and advanced performance evaluation techniques, to identify optimum field spacing and the development plan. Program success depends on understanding these risks early in the field life. Considering data acquisition and evaluation costs as a field-wide investment rather than justifying on an individual well-by-well basis facilitates getting management approval.
With parallel development, it is critical that ultimate performance of new wells be determined quickly. Since conventional decline curve analysis can typically take years of production history to be applicable, Anadarko employs new, type-curve matching techniques to provide early estimates of well performance (contacted gas in place, connected pore volume and drainage area). Applying these methods, together with other advanced reservoir characterization techniques, the operator has demonstrated the ability to proceed rapidly to full field development on optimum spacing.
Optimal well siting in basin-centered gas reservoirs. Such reservoirs are different than normal structural or stratigraphic traps. Gas is widely distributed throughout the section, and exploration requires finding the “sweet spots.” Best production is not as closely related to closure or sand thickness. Fortunately, where gas replaces water, there are slow acoustic velocity anomalies, regardless of whether pressures are abnormally high or low. Identification of anomalous velocity zones has proven predictive for identifying “sweet spots.” Building on prior R&D and field results, Innovative Discovery Technologies LLC (IDT), a subsidiary of GTI (formerly GRI), has been successfully using this approach.
Data was presented for Muddy production from Riverton Dome in Wyoming. There, the field had normal-pressure production from the crest of the anticline. A regional seal crossed reservoir facies on the flank of the structure. Facies maps are available. Wells located in reservoir facies and having anomalous velocity profiles are commercial, whereas wells drilled on structure have not been economic. In another example, a comparison between predrill and postdrill estimates of ultimate reserves (in the range of 2-10 Bcf), considering 20 wells sited using the exploration technique, is quite positive. The last Tcf of reserves in this field was developed with 20% fewer wells due to using this approach.
Independent takes over Wyoming [CO.sub.2] flood and increases value. Merit Energy Co. purchased the Lost Soldier and Wertz [CO.sub.2] flood operations in Wyoming from BP Amoco in December 1999. In those fields, BP had been [CO.sub.2] flooding since 1986. The Tensleep and Darwin-Madison reservoirs, the primary formations, are separately flooded. Since assuming operations, Merit has: 1) reactivated/ recompleted 80 wells; 2) increased [CO.sub.2] purchases for injection to 40 MMcfd from 22.5 MMcfd; 3) changed WAG cycles and patterns; and 4) upgraded facilities to handle additional production. Production has increased over 1,000 bopd, with an increase in ultimate reserves of 5.5 MMbbl.
When analyzing data, Merit recognized that upside potential existed in Lost Soldier. On a percent of oil-in-place basis, tertiary recovery in the Darwin-Madison was only one-third of that experienced in the Tensleep, and peak response was not as prominent as that experienced in the Tensleep. Although there were other factors, further study revealed that lower recovery in the Darwin-Madison could be attributed to insufficient [CO.sub.2] injection. Using existing data, sound engineering and new water-oil ratio forecasting techniques, but without simulation using a sophisticated geological model, Merit estimated the upside potential, developed a production/economic forecast, and began aggressive development. Experience to date has confirmed the production forecast’s reliability.
Immiscible nitrogen displacement, southern Oklahoma. The Quintin Little Co., Inc. operates Southwest Homer Goodwin Sand Units I and II in Carter County in the Ardmore basin, south-central Oklahoma. The Upper and Lower Goodwin sands–at depths ranging from 2,200 to 4,700 ft–were originally produced by a combination of fluid expansion, solution gas and gravity drainage. Developed in the 1950s and 1960s on 10-acre spacing, most wells were completed in the Upper and Lower sands and were fracture stimulated. Porosity is in the 17-23% range, and permeability exhibits wide variation in this very laminated, shaly siltstone. Dip ranges from 15 to 29%.
When unitized in the 1980s, reservoir pressure in both units had declined to less than 150 psi from 750 psi. Although larger in Unit I, both Units had a secondary gas cap at unitization. Quintin considered waterflooding, but offset waterfloods only averaged 0.22 secondary/primary recovery ratio, and updip water injection prematurely watered-out wells. The operator also recognized that the secondary gas cap had to be repressurized to prevent resaturation with oil. Both natural gas and carbon dioxide injection were considered, but economic and operational factors led to use of immiscible (updip) nitrogen injection combined with downdip water injection.
Injection began in Unit I in the mid-1980s, followed by injection in Unit II in the early 1990s. The process has been effective and economical. Secondary/primary ratios above 0.6 are more than double offset waterfloods, and further economic reserves exist.
With immiscible nitrogen displacement, there are special considerations/problems which must be addressed. Nitrogen breakthrough is inevitable. Temperature or production logs, Thermal Decay Neutron logs, packer or packer/plug tests, and trial and error methods (set RBP and produce) were all used to identify and isolate intervals producing excessive nitrogen. Mechanical methods of isolation included installation of RBPs and casing patchs (long vented packer). Permanent methods of isolation included squeeze cementing the entire perforated interval and recompleting in productive intervals (has not proven a long-term solution) and cementing the entire perforated interval to P&A to prevent crossflow.
A propane refrigeration unit installed in 1999 to strip liquids from the produced nitrogen stream has proven profitable, recovering more than 26,000 bbl of liquids from June 1999 through April 2001. Paraffin problems, which were always a problem, worsened with nitrogen production. Methods most effective for paraffin control include: 1) batch treating with condensate mixed with paraffin chemicals; 2) wellhead magnetic fluid conditioners for reducing flowline chemical/hot oiling costs; and 3) down-hole direct chemical injection through stainless steel tubing. Of these, direct downhole injection has been the most effective. wo
ACKNOWLEDGMENT
Case studics were presented during “Maximizing Recovery 2001,” a conference organized by Marcus Evans (www.marcusevanstx.com), June 25-26, 2001, Houston, Texas.
Important basic facts regarding riser tension and mud weight
Jack Bayless
Over the years, riser tension required to support weight of the mud in a drilling riser has been somewhat misinterpreted. Most people in the field think that mud weight is supported by the top tension. This is only partly true and, now, even some riser analysts think that the vertical component of mud weight is directly supported. The following illustration and discussion of basic hydrostatics shows that the vertical component of mud weight cannot be supported by a riser tube. Its vertical component is, instead, primarily supported by the bottom of the hole.
This is important because correct application of hydrostatic pressure must be done as a basis of all drilling riser analyses, i.e., the basics must be correct, or all of the riser analysis is incorrect. When it is realized that top tension to support horizontal components of mud weight is transmitted to the flex joint, then correct analysis can be done. When the bending moments on the stack are correct, then correct risk analysis can be done, and operational variables can be tightened to result in safer deepwater drilling.
Basic hydrostatics. Fig. 1 illustrates that pipe weight and liquid weight are independent Only unbalanced forces are shown on the schematic scales (weighing devices). Thus, a riser pipe at an angle cannot lift or support liquid in a vertical direction, except for a very minor part, which amounts to (1-cosine) of the angle. If the pipe angle is 10[degrees], then (1-cosine 10) is 1.5%, and 98.5% of the mud weight is supported by unbalanced projections (diameter reductions such as casing hangers in the subsea wellhead) and the bottom of the hole.
A major oil company’s drilling manual recognizes this fact and makes the point that mud weight does not affect actual riser tension; thus, tension at any point along the riser will be the same, regardless of internal mud weight. It notes, further, that because of this, a riser could have a large actual tension at the emergency disconnect above the BOP when using a heavy mud, and both of these factors should be recognized and corrected before disconnecting the riser.
How does tension work. From Shortley and Williams (Basic Physics, 1950), we note that tension applied to a horizontal string will support a perpendicular load/2 according to the sine of the angle created by that load, Fig. 2. Note that the tension supports half the load because each end of the string shares 50% of that load–this becomes obvious as the angle approaches 90[degrees]. For example, calculate the tension required to support 10 lb of weight if Angle A is 10[degrees], and the pulley is 10 ft from the wall. Answer: 10/(sine 10)/2 = 28.8 lb. For 1[degrees], the answer is 286 lb. This example illustrates the fact that large tensions are required to support small perpendicular loads, especially at low angles.
Now turn the diagram 90[degrees] so that the wall is at the bottom and a perpendicular load is horizontal. This represents a riser system where an internally generated horizontal load is supported by tension in the riser wall.
The horizontal component of the weight of mud in a riser tube can be approximated by the sine of the riser angle times the summation of mud weight (others may prefer to use equations presented in API 16Q). Thus, if the riser has a net mud weight of 1 million lb, and the riser is at 4[degrees] at the flex joint, the horizontal load is about 70,000 lb. To support this horizontal load, the riser must be tensioned by 70,000/(sine 4) = 1,000,000 lb. Thus, the tension approximates the mud weight, not because it is lifting the vertical component, but because the tension is supporting the horizontal component. Since basic tension equations divide the result by two, further refinements may reduce tension requirements somewhat in the real case.
Why is this important. The above discussion illustrates that top tension in a riser is transmitted to the flex joint and, thus, must be considered by vector analysis to calculate the horizontal load at the flex joint, and to calculate bending moment at the BOP stack connector. In the above example, the bending moment at the connector of a 60-ft-high BOP stack is 70,000 X 60 = 4,200,000 ft lb. The pressure capacity of the BOP can be estimated from API Technical Report 6AE. This report indicates that the pressure rating of the BOP is reduced by more than 50%. Other loads may reduce the rating even more, such as the vertical component of the riser tension, less weight of the BOP stack. Also, internal pressure of the BOP is higher by the amount of the new mud weight at the water depth times the hydrostatic gradient.
In summary what must be considered?
1. Riser angles at the flex joint must be kept within 1[degrees] to 2[degrees] when carrying high mud weights (thus high tension).
2. Consider eliminating over-pull when carrying high mud weights, because high tensions transmitted to the flex joint will lift the LMRP in emergency disconnect situations.
Further, wave action and currents at the top of the riser may generate additional tension requirements, but top tension already applied for high mud weights may be sufficient. And remember, riser analysis must be based on physical reality, not fiction.
Data storage system raises productivity
Implementing a network-attached storage system improved the productivity of geologists and geophysicists at Nuevo Energy Co. by providing consistently high performance without data loss or downtime. Previously, Nuevo outsourced all seismic-interpretation hardware. In 1998, the company decided to purchase its own hardware because its scientific IT was becoming increasingly strategic. The server Nuevo selected–the NS2000 from Auspex Systems, Inc., Santa Clara, California–provides data access with response times and reliability that were substantially better than the company’s former system. Jeremy Zimmerman, Senior Geophysicist for Nuevo in Houston, said the new servers have ensured that the data will be there when it is needed. The result is a substantial productivity improvement, which, in the long run, translates to improved property evaluation.
Nuevo produces about 54,000 boe per day. Despite a market capitalization of roughly $300 million, it has only about 100 employees. The company outsources certain accounting, financial, human resources and direct field-operation functions. Geological and geophysical software applications are another area in which the company makes extensive use of outsourcing. Although the company has its own G&G employees, software maintenance and support are contracted through Landmark Graphics Corp., giving Nuevo access to many popular seismic-interpretation and geologic-modeling packages.
Analyzing well and seismic data.
Nuevo has one office in Texas and two in California. “In our California offices, the focus is on well data,” Zimmerman said. “For instance, when we have hundreds of wells in a mature field, the objective is to optimize production. With so many closely spaced wells, the issue is handling large amounts of information in a short timeframe. The primary task is loading and interpreting new well data so we can update our maps and build new cross-sections to guide future efforts.”
Conversely, geoscientists in Houston work primarily on large-scale international projects that carry both high risks and high potential rewards. “Some of these projects have less than a dozen wells covering a million-acre permit. In this context, seismic data plays a larger role, so data accessibility and reliability are required,” said Zimmerman.
Given the varied nature and locations of assets, as well as their effect on data requirements, Nuevo concluded that response time and reliability provided to its technical staff was essential to its business. Only by performing the scientific IT function in-house could the company prevent bottlenecks in the exploration process.
Selecting the data server.
Sun Ultra 60 workstations with 500 MB to 2 GB of memory were chosen as the principal hardware platform for desktops. Seismic data provides special data storage and access challenges. Most of the seismic data used by Nuevo’s Houston office ranges from 20 to 30 GB. Geophysicists frequently have to work with multiple data sets, so they read and reread data off the discs on a regular basis–and they need to do so quickly. Because people often work in teams analyzing data, they need to have access to large, varied data sets in one location (see figure).
“These factors mean that local storage can only be a small part of the solution,” Zimmerman said, “We first looked at one of the high-end enterprise storage-system providers. Their solution was well regarded for dependability as a server for business applications, but they had little experience with handling seismic data, and their solution came at a higher cost than our budget allowed. We also examined server-attached storage systems that simply hang RAID from a workstation. We selected the NS2000 because of the strong track record that this machine has achieved in delivering high performance and reliability to the oil and gas industry at a reasonable cost.”
The key to the high I/O performance of the server system is its dedicated processor architecture that is optimized for the purpose of moving file data as efficiently as possible from disk to network and vice versa. The I/O node is the fundamental building block of the machine’s architecture. Each node contains a dual-Intel processor motherboard that has different and logically separate processing functions. The network processor handles network protocols and manages associated caches. The file and storage processor is dedicated to managing the file systems and associated storage hardware. The result is a dramatic improvement in performance.
Access for Unix and Windows users.
Another advantage of the new server is that it can serve both Unix and Windows NT machines. “This feature eliminates the need to provide a separate Windows NT-based storage system for the production accounting applications used by our engineers,” Zimmerman said. “It will become even more important in the future as we begin to migrate some of our geophysical applications to the NT world.”
The data server consolidates UNIX and Windows NT on the same platform using NeTservices, which is NS2000 compatible. NeTservices concurrently delivers native file services to thousands of UNIX and Windows clients, while being fully integrated into both environments from a user access and administrative standpoint. It is fully compatible with Microsoft’s Common Internet File System file-sharing protocol and NT Server 4.0 directory, data security and remote administration services, so no additional software is required on any Windows clients.
“Performance of the new data servers has been outstanding,” Zimmerman concluded. “Our high-end users work simultaneously on the system and we have had few complaints about slow performance. Even more important, since the systems were installed in 1998, we have had no downtime attributable to new system. The combination of faster performance and zero downtime has significantly increased productivity of our users, although it’s impossible to measure by how much. In my opinion, this device provides an ideal platform for high-performance data storage for geological and geophysical data analysis.”
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