OTC 17657

Flow Assurance and Production Chemistry for the Na Kika Development A. Carroll and J. Clemens, BP; K. Stevens, Shell Intl. E&P, Inc.; and R. Berger, Manatee Inc.

Copyright 2005, Offshore Technology Conference This paper was prepared for presentation at the 2005 Offshore Technology Conference held in Houston, TX, U.S.A., 2–5 May 2005. This paper was selected for presentation by an OTC Program Committee following review of information contained in a proposal submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Offshore Technology Conference, its officers, or members. Papers presented at OTC are subject to publication review by Sponsor Society Committees of the Offshore Technology Conference. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to a proposal of not more than 300 words; illustrations may not be copied. The proposal must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, OTC, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435. Abstract. The Na Kika base development consists of five oil and gas fields in the Mississippi Canyon area of the Gulf of Mexico tied-back to a central floating oil and gas processing facility. The water depths for each of the fields range from 5800 to 7000 ft and are offset between 6 to 13 miles from the facility. The individual fields have been developed as subsea production systems. The development of the fields had a number of unique features that were challenges for the development project.

• Extreme water depths. • Downward sloping flow path for the fields north of the host (Ariel & Kepler). • Relatively low reservoir temperatures. • Complex reservoirs, leading to uncertainty regarding reserves and rates, and in some cases, the nature of expected hydrocarbons. • Subsea flowline design using flow loops and daisy chained wells vs. dual parallel flowlines from a central manifold. • Gas lifting of large diameter risers for production enhancement and slug control.

Within these unique features and challenges were a

variety of flow assurance concerns. These concerns were addressed by understanding the related production chemistry problems, applying an operating strategy and specialized equipment for mitigation of those problems, and then validating those plans with extensive steady state and transient simulations and testing.

The key production chemistry issues anticipated on Na Kika included asphaltene precipitation in the well bore as a result of down hole commingling, paraffin deposition in the flowlines, and hydrate control. Lessons learned during the first year of operation address work-a-rounds because of

equipment start-up issues, and differences in production chemistry characteristics from those originally assumed.

The operating strategies and equipment employed for mitigation of the production chemistry issues included a combination a various conventional and non-conventional methods such as continuous hydrate inhibition for the gas systems, and heat retention in the oil systems combined with flowline blowdown and oil circulation procedures during unplanned facility outages. Production chemicals would be used for management of corrosion, asphaltene and paraffin deposition. Lessons learned during the first year of operation include subsea equipment performance and associated operating constraints, benchmarking, and results of latest production chemistry analysis.

Extensive steady state and transient analyses were performed during the development project to validate operating temperatures and pressures, cool-down times, slugging characteristics, gas lift requirements, and operating parameters, as well as success of transient events (i.e. blow-down, start-ups, etc.). Lessons learned and actual field data for these analyses will be presented. Overview of Na Kika Development. The Na Kika base unit consists of five oil and gas fields in the Mississippi Canyon area of the Gulf of Mexico, developed with 10 production subsea wells and associated subsea facilities that are centrally located to the area. The individual fields are named Ariel, Kepler, Fourier, Herschel, and East Anstey. The five fields are located in water depths ranging from 5800 to 7000 ft depending on the specific well location. The fields are developed utilizing three unique gathering flowloops with their produced fluids routed back to the floating production facility:

• Ariel and Kepler oil fields are developed with a 10” x 16” pipe-in-pipe (PIP), 25-mile flowloop to the northwest of the production facility. These fields are developed with five subsea oil wells, each which are daisy chained within the norther loop route. The north loop was unique that the flowline route is generally downhill towards the host. The water depths along the route range from approximately 5800 ft (shallowest) at the well locations to 6340 ft at the host. • The Fourier oil play and the Herschel field are developed with an 8” x 12” pipe-in-pipe, 26-mile flowloop to the south of the production facility. Only two subsea oil wells produce within the south oil loop route. The south oil loop flowline route is generally uphill

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towards the host. The water depths range from approximately 6930 ft (deepest) at the well sites to 6340 ft at the host. • The Fourier gas plays and the East Anstey field are developed with an uninsulated, 8”, 31 mile flowloop, also located to the south of the production facility. Three subsea gas wells are daisy chained within the loop route. The south gas loop flowline route is also uphill towards the host with water depths similar to the southern oil loop.

The general arrangements for the northern and the southern flowloops are illustrated in Figures 1 and 2.

Na Kika Production Chemistry Concerns. The production chemistry concerns are both field specific and general to the development. These concerns are:

• Hydrates – these concerns are general to the overall area development. The unique characteristics of each flowloop drove different operating strategies for control of hydrates within each loop. Because the southern loops go uphill (towards host), and one of them transports gas, conventional hydrate management strategies were effective. Because the northern loop goes downhill naturally, a non-conventional strategy was necessary to maintain hydrate control. • Paraffin – these concerns are general for the oil field developments. Paraffin deposition in the uninsulated gas flow loop was not anticipated to be a problem during the life of any of the fields although pigging capability was provided within each flowloop. • Asphaltenes – multiple reservoirs, commingling in a common low-pressure flowline, some with a gas lifted production riser, drove an extensive study scope during the project phase to understand asphaltene stability and deposition. Ultimately it was concluded that asphaltenes were only an issue for the Fourier oil well (F3) that was tied-into the southern oil loop. • Scale - Na Kika salinities were expected to be low to moderate range (6-13%). Limited scaling studies were conducted on the water samples taken during the appraisal drilling. These studies did not indicate any scaling concerns.

Production Fluids and Operating Strategies. Northern Oil Loop. This oil loop had a range of various fluid properties because of the different commingling possibilities of the 12 reservoir zones that were being produced in that area. Oil properties could be generalized, with a few exceptions, to an API gravity of approximately 28 deg, and a gas-oil ratio (GOR) of approximately 1100 scf/bbl (without gas lift). Refer to Table 1 for a more complete description of the fluid properties for the each of the five wells producing within this system.

With respect to operating strategy, insulating the north loop provided sufficient heat retention for management of both hydrates and paraffin during steady state conditions for most of the field life. Later life conditions become more of a concern for both hydrates and paraffin because of the low flow

rates, and the need for continuous gas lift and potential continuous hot oil circulation. The overall heat transfer coefficient, or “U value”, for the insulation was sufficient to provide a minimum of 12 hours of cool-down time.

During start-ups, hydrate inhibitor is utilized to control hydrates until the system is sufficiently warm to achieve the standard Na Kika oil field cool-down requirements. Methanol is the primary inhibitor, but it is provided the flexibility to utilize Low Dosage Hydrate Inhibitors (LDHI) in the future. As well, hot oil circulation could be utilized to pre-heat the flowloop to help minimize methanol requirementsduring flowline warm-up. The standard cool-down requirements for the Na Kika oil fields are:

• 3 hours “no-touch” period immediately following any platform shutdown so that no operator intervention was required for hydrate mitigation. • 8 hours total cool-down time for the subsea well systems including trees and jumpers. All hydrate mitigating procedures must be completed by the expiration of this cool-down time. • 12 hours total cool-down time for the flowlines and riser systems. All hydrate mitigating procedures must be completed by the expiration of this cool-down time.

Response to host shutdowns depended on the length of

the shutdown. Equipment is generally displaced with methanol beginning at 3 hours following expiration of the “no-touch” period, and to be completed before the end of the 8-hour well system cool-down time. If the shutdown persisted beyond 6 hours, then the flowloop had to be dead oil displaced prior to start-up, or fully treated with a hydrate inhibitor prior to the shutdown.

Because of the unique downhill flowline route, severe slugging, and relatively high abandonment pressures, was anticipated to be a processing and reserves’ issue. Riser base gas lift was installed to mitigate those areas of concern. Southern Oil Loop. The southern oil loop also had a range of various fluid properties because of the different commingling possibilities, but was limited compared to the northern area because there were only 4 reservoir zones to consider. The average oil properties were similar to the north fields with an API gravity of approximately 28 deg, and a GOR of approximately 1100-1200 scf/bbl, depending on the well. Refer to Table 2 for a more complete description of the fluid properties for the each of the five wells producing within this system.

With respect to operating strategy, insulating the south loop also provided sufficient heat retention for management of both hydrates and paraffin during steady state conditions for most of the field life. Similar to the north, late life conditions were a concern again for both hydrates and paraffin because of the low flow rates, and the potential need for continuous gas lift and continuous hot oil circulation. The “U value” for the insulation was sufficient to provide a minimum cool-down time of 12 hours.

Hydrate inhibitor is utilized during start-ups to manage hydrates until the system is sufficiently warm to achieve the

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standard Na Kika oil field cool-down requirements. Hot oil circulation can also be utilized to pre-heat the flowloop to minimize the methanol required during flowline warm-up.

Responses to host shutdowns are similar to the north with one exception; blowdown for the purpose of reducing the flowline pressure below hydrate formation pressure was predicted to be effective during most of the field life. If the shutdown persisted beyond 6 hours, then the flowloop had to be blown down, and then dead oil displaced prior to start-up, or completely treated with a hydrate inhibitor prior to the shutdown. Terrain and high frequency hydrodynamic slugging were not anticipated to be an issue for the topside processing except at relatively low flowrates, thus gas lift injection was not provided. Southern Gas Loop. The southern gas loop fluid properties could be characterized as rich or dry gas depending on the field. The Fourier gas wells are the rich gas wells and their production is isolated to one side of the flowloop. The condensate yield for these wells is approximately 35 bbl / MMscf. The East Anstey well is a dry gas well with a condensate yield of less than 2 bbl / MMscf. Refer to Table 3 for a more complete description of the fluid properties for the each of the three wells producing within this system.

The operating strategy for the gas loop is very simple for start-up and shutdown because the gas wells are continuously inhibited with a hydrate inhibitor (i.e. Mono-Ethylene Glycol - MEG); no additional action is required for hydrate mitigation.

Development Hydraulic Analyses. The thermal hydraulic modeling for Na Kika started in late 1996 with work continuing through 2003. The relatively high reservoir complexity resulted in numerous potential outcomes that needed to be considered in the design. Although this is not atypical for a subsea system, the potential permutations in a multi-field development like Na Kika were enormous.

The steady state modeling strategy was to model the three loops thermal hydraulic performance at key conditions to be able to define the operating envelope. This was carried out using the HYSYS simulation package. The robustness of the design, in terms of hydrate control, wax management, slugging, blowdown, etc, was then tested against the various scenarios and changing conditions – reservoir performance, well routing, updated drilling data and samples, to ensure the design continued to be operable, and where necessary the flow assurance strategies updated.

The detailed transient modeling was carried out using the OLGA simulation package. Due to the complexity of the system, a significant number of key conditions had to be considered, modeled and the results incorporated into the design. This included start-up, shutdown, blowdown, and dead oil circulation.

For an example of the complexity, one could consider the shutdown and subsequent start-up of the North oil loop.

• Shutdown and the associated cooldown of the various sections, with the complexity increased due to the distributed nature of the wells • Dead oil circulation for hydrate management,

recognizing the increased hydrates risk from the dead leg sections. The north oil loop could not be depressurized due to the downward sloping nature of the flowline • Start-up sequence for production, and recognizing when the riser gaslift should be used to minimize the pressure surges during start-up, as well as retaining the flexibility in the sequence of starting up the wells

The transient modeling was also used to evaluate the

start-up procedures developed, with the results identifying some initial limitations that had to be revised for the final procedures.

Wherever possible the accuracy of the models used was tested against field data, or where that did not exist laboratory modeling, e.g. gaslift of the large diameter risers.

Post Start-Up Learnings. Several learnings have been experienced since the Na Kika first gas date on November 26, 2003. The learnings are a combination of work-arounds necessitated from equipment issues, benchmarking of actual field data with predicted analyses results, and general operational experiences as they pertain to flow assurance. Gas Riser Low Arrival Temperatures. Gas arrival temperatures were experienced to be lower than predicted by the original steady state modeling. This resulted in an early production limitation for the riser because of a low temperature restriction in the riser flex joint temperature design.

A Root Cause Failure Analysis was conducted and the results yielded a thermo-plastic coating on the upper 2000 ft of riser pipe in lieu of Fusion Bonded Epoxy (FBE). The purpose of the thermo-plastic coating was to serve as heavy-duty corrosion and abrasion layer underneath the Steel Cantenary Riser (SCR) Vortex Induced Vibration (VIV) system. The original steady state modeling only included the normal FBE coating. When included into the steady state model, the heavy-duty corrosion layer was seen to act as an insulating barrier in the water column, preventing the warmer gulf water from heating the cooling gas as it traveled up the riser. Figures 3 to 7 show a comparison of the significance of this detail in the steady state model along with actual field data.

Once the corrected temperatures were known for the desired gas rates, a remediation plan was necessary to mitigate the effects of the colder arrival temperatures. The impacts of the reduced temperature could be summarized as follows:

• Resulted in a higher demand for hydrate inhibitor (MEG) because 1) the colder temperatures resulted in higher water dropout than originally anticipated, and 2) the subcooling was greater thus requiring a higher concentration of inhibitor for adequate protection. • Impacted the mechanical properties of the flex joint’s flex-element, thus necessitating a review of the fatigue life of the SCR at reduced temperatures, as well as a requalification of the flex-joint at the reduced temperatures.

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• Ice formation external to the pipe both subsea beneath the VIV system and at the surface were a concern on equipment performance. Higher-level inspection plans were necessary to ensure problems from ice formation were not arising.

PIP Flowline Arrival Temperatures. Assessment of the product arrival temperatures versus the original predicted arrival temperatures was viewed as necessary to ensure that the 12 hour cool-down times were available consistent with the operating strategy that was used to develop procedures for the flowline system. Figure 8 illustrates the predicted product temperature profiles with the observed field arrival temperatures while circulating oil in the North Oil Loop. The results indicate that the minimum 12-hour of cool-down time is available as predicted in the design. PIP Flooded Section Benchmarking. During installation of the Southern Oil Loop, seawater was discovered in the PIP annulus. A flooded member detection evaluation confirmed that the flooded annulus section was approximately 1800 ft in length, contained between the water stops designed into the PIP system. The flooded section is located approximately 10,000 ft from the host and consequently is at the higher end of the flowline.

Thermal analysis performed indicated that remediation had to be performed to ensure that the 12 hour cool-down time, design premise remained. Additional analyses showed that burying the flowline with as little as 12” of soil could restore or even increase the cool-down time. The project covered the flooded segment with 8’ x 20’, 9” thick concrete mattresses in an effort to depress the affected length into soil to acquire the burial needed.

Post start-up of the oil loop, the arrival temperatures were benchmarked against those calculated. The results indicated that the covered section was underperforming buried calculations. However, it is difficult to understand that actual root cause because of the lack of visibility underneath the concrete mattresses. Based on measured topsides temperatures it is suspected that the pipe is only about half buried compared with the desired during the remediation. A preliminary comparison of the thermal performance is shown in Figure 9.

The existing operating strategy remains for the loop despite the expected reduction of cool-down in that section. That section is at the upper end of the “uphill” flowline and thus liquids are anticipated to travel out of the buried section for the most part. However, since the project did attempt to bury this section, a slight dip is also expected forming a small water trap, but the accumulation is not significant enough to create concern for a hydrate plug risk.

VIT. Vaccuum insulated tubing (VIT) is installed in all the Na Kika oil wells down to the surface controlled, subsurface, safety valve (SCSSV) located approximately 3,000 ft below mudline. The VIT was installed to mitigate annular pressure build-up (APB) concerns in the well casing annuli, and it provided warmer flowing tubing temperatures in late-life conditions, when paraffin in the wellbore would be more of a concern.

An opportunity was investigated to determine if the oil wells could be operated without VIT from a flow assurance perspective. The analyses show that it is feasible to operate the oil wells without VIT (assuming APB issues are resolved) given that the reservoir temperatures are close to 135-140 ºF or higher. Operating wells without VIT were characterized as follows:

• Steady state flowing temperatures will be slightly lower than with VIT, but wax deposition can still be avoided if flowrates are higher than 2000-3000 bopd. In late life, even a small increase of watercut will help to keep higher flowing temperatures in the wellbore. Therefore the wells should be capable of flowing at even lower rates. • Cold earth start-ups may require the use of more inhibitor volume due to the slower ramp-up of temperatures. Implementation of LDHIs could potentially reduce the start-up costs for these limited situations. • Once the wells achieve steady state rates, the well bore around the top of the well will warm-up (i.e. warm earth). This helps to increase the well cool down time to hydrate dissociation temperatures from just a few hours to several days (up to two weeks). • Warm earth start-ups will likely use less quantity of inhibitors, or may not even require inhibition at all, depending on shut-in length, as the surrounding earth will maintain heat longer. Post start-up of the oil wells, the flowing tubing

temperatures were benchmarked against those predicted for validation of the existing operating strategy. The results indicated that it is difficult to actually access the performance of the VIT because of the small differences in flowing tubing temperature versus predicted without VIT. Comparison of predicted temperature profiles with flowing tubing temperature data points are shown in Figure 10.

Slugging Benchmarking. Production was started through the North side flowline loop early in 2004, and slugging was found to be a problem from the start. This contrasted with the expectation (from flow assurance work completed during design [4]) that slugging would only become a significant issue later in field life. This was because the topsides facilities were expected to manage any hydrodynamic slugging, with mitigation only necessary for severe (i.e. terrain) type slugging. Gas lift capability provided the mitigation for the severe slugging

Steady state operation of the north side flowline loop was then assessed post start-up using the OLGA 2000 (v4.10) multiphase pipeline simulator with the SLUGTRACKING option enabled. The results have been found to be consistent with the slugging behaviour experienced for the Kepler field during May – June 2004. Similarly the results are consistent with the absence of slugging on the Ariel field at this time. Regime maps were prepared which characterise the slugging and quantify its severity, Figures 11 to 14.

For the Kepler flowline it is found that whereas riser base gas lift is required in order to avoid terrain slugs at low

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production rates, the riser base gas lift propagates hydrodynamic slugs up the riser to the topsides process if riser based gas lift continues to be used when the production rates are higher. The hydrodynamic slugs could even be large enough to trip inlet vessels, or if stacked together with slugs from other risers, trip the larger, common, downstream vessels.

The regime map therefore focuses on the balance between production flowrate (at fixed gas-oil-ratio) and riser base gas lift flowrate. Regime maps have been prepared for a relevant range of separator pressures and opening positions of the platform arrival choke valve. For the Ariel flowline, the gas-oil ratio can be varied according to the flowrate of gas and oil wells flowing into the flowline. The flow stability regime map has therefore been prepared based on total gas and total oil flowrate (regardless of the origin of the gas and oil). South Oil Blowdown Benchmarking. In June of 2004, the facility went into a planned shutdown to conduct topside related maintenance activities. The shutdown was anticipated to be less than 12 hours so an operational decision was made not to pre-inhibit the line with methanol to minimize methanol contamination in the sales crude post start-up from the shutdown. This decision was made because blowdown was predicted to be viable and could be conducted during the shutdown if required as a contingency for a longer than expected shutdown. Unfortunately, the shutdown extended longer than desired, and blowdown was initiated on June 13 at 22:00. Upon completion of blowdown (on June 14, 2004), subsea pressures yielded 304 psia subsea on Herschel line, and 230 psia on Fourier line. This data was compared against the predicted and resulted in fairly close agreement. Blowdown transient analysis predicted that flowline blowdown would be a success by achieving subsea pressures of 300 psia and lower. Methanol in Sales Crude. The Na Kika development includes 7 subsea oil wells. The hydrate mitigation procedures for these oil wells are summarized as follows:

• When the platform shutdowns are longer than 3 hours, enough methanol is pumped to displace the subsea tree and well jumper for each of the wells. • When the platform shutdowns are longer than 6 hours, additional methanol displaces some of the fluids in the well's production tubing. • When the platform shutdowns are longer than 48 hours, more methanol displaces the fluids in the well's production tubing down to the sub-surface safety valve. • At start-ups, the methanol pumped into the system during the shutdown will be displaced out with fresh production as the wells come online. However, the fresh production will be continuously inhibited with methanol until the subsea system is classified as warm. At low water volumes (< 1% BS&W), a minimal injection rate will continue for approximately 3-6 hours.

Methanol concentrations peak in the sales oil when the

static methanol in the subsea system is purged out. The methanol concentration will then reduce to the continuous

inhibition levels and then to zero when the system is warm and methanol injection is terminated.

Since start-up, coordination with oil pipeline owners has been necessary through all planned shutdowns, and active communication has been necessary during unplanned shutdowns for management of methanol ppm in the crude oil sales stream. However, with the exception of Hurricane preparation and restart, the coordination with the pipeline has worked well. This is generally because the increased communication with the pipeline operators allows the pipeline owners to ensure proper blending with methanol free oil that comes into the trunkline so that the blended crude oil stream has methanol concentrations sufficiently low so it will not adversely impact downstream refineries.

Hurricanes however, continue to be a challenge for the asset (including pipeline owners). Before and after each Hurricane, methanol is used by a majority of the operators offshore as a hydrate inhibitor. As a consequence, the pipeline owners are forced to control the start-up scheduling of all fields using the trunckline so the influx of the methanol treated oil in truckline is controlled to reasonable limits. This is necessary because the methanol free blend-stock (oil) is severely limited because of the hurricane passage. Na Kika Operations continues to evaluate the usage of LDHI and other procedures to eliminate these operational challenges. Asphaltene on Fourier. The appraisal well at Fourier gave important new insights with respect to asphaltene stability and blending. Early project testing suggested that the primary oils at Fourier would have stability problems. This conflicted with even earlier studies that the primary oils were thought to be stable. However, samples were not previously available to do parametric blending of the various oils that would ultimately be produced. Parametric blending was later done, in part, in 2000. The results suggest that the blending of various Fourier oils and oil/condensate mixtures could destabilize the crude so that asphaltenes precipitate might occur at well or flowline conditions.

To offset the risk of asphaltene precipitation in the tubing, downhole chemical injection systems were installed above the packer by the project. The initial strategy was to initiate injection only when two downhole zones were commingled. This particular well was equipped with smart systems, and thus this type of discrete control on the commingling of these two zones was possible.

Unfortunately, complications with the umbilical system led to the inability to inject asphaltene inhibitor downhole. Because of this inability to inhibit continuously, an additional post start-up study was performed to more accurately understand the probability of asphaltene formation to ensure a correct decision was made regarding the management of the two zones: produce each zone individually until depletion, or commingle and produce until depletion. Reservoir studies have indicated that commingling the two zones early in field life yield greater net present value and more reserves could be delivered.

The new asphaltene study focused on the depressurization and commingling of the fluids from the two zones utilizing the actual shut-in pressures and zone contribution rates expected in the field at the time of commingling. The primary concern

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was for possible asphaltene drop out at shut-in conditions during cross flow from the upper zone to the lower zone and thus possible formation damage as a result of asphaltene deposits.

The test results indicated that very little asphaltene formation would actually occur. This result coupled with the retained ability to perform solvent remedial interventions on the tubing from the platform ultimately led to the successful commingling of the two zones. Continued surveillance on the completions still yields no indications of deposition. Paraffin in Fourier Gas Leg. Paraffin was found topsides near the discharge of the Fourier gas riser upon entry of the equipment. The paraffin find immediately led to an examination to determine if the current flowing conditions of the subsea flowline riser system could ultimately lead to a waxy layer that would need mitigation. Any mitigation that would require pigging was viewed as risky for two reasons: 1) the pig would have to pass through a 31-mile up-hill flowline and 2) the uncertainty to successfully pass a pig through a waxy system only propelled by dry gas (i.e. no oil to act as solvent for cuttings). Chemical treatment (i.e. paraffin inhibitor) was considered as the only practical mitigation but complications to the subsea umbilical infrastructure made initiation of the chemical a risked based decision trade-off.

To assess the wax deposition tendencies within the flowline system, laboratory flowloop testing and a separate waxy crude prediction model were performed. This was done so an informed decision on the mitigation plan could be made. A pressurized separator sample was utilized for the flowloop testing and analysis of oil sample was compared to a down-hole sample to determine if any loss of paraffin could have potentially occurred within the actual flowline. The latter was done to assure that the pressurized separator sample would yield reliable results during the testing. The flowloop testing results with the separator sample indicated that wax deposition would not be a problem. The comparison of the paraffin components of the oil for the separation sample with the down-hole sample indicated only relatively small differences in total paraffin content.

The waxy crude model was developed using high temperature gas cromatography oil compositional analysis. The model was tuned to laboratory measurements for recombined live Na Kika condensate sample, with a wax appearance temperature (WAT) at a pressure of 2700 psi, and dead Na Kika condensate sample WAT to model deposition of paraffin in the line. The tuned model results also indicated that no wax deposition would occur.

Actual field temperature performance of the Fourier gas riser was then used to corroborate the waxy crude model predictions. This was done by examining the potential affect of an internal diameter wax coated riser with the field observed arrival temperatures. If any wax were expected to drop out it would be in the riser as a result of the already cold arrival temperatures resulting from Joule Thompson (JT) cooling. The wax would then act as an additional insulating barrier, and would result in even further decrease in gas arrival temperatures. This was not observed in the field and thus corroborates the model prediction.

Conclusions. 1. Technical assurance of the model detail used within

steady state and transient simulations is crucial to the results of the simulation. Visibility of the model details to the development team is necessary to ensure the model is fit for purpose.

2. PIP systems on the Northern flowloop appear to be returning product temperatures consistent with those predicted.

3. Utilization of concrete mattresses to induce a buried flowline does not appear to be effective, at least in the early stages of field life, with the assumption that the product is arriving to the affected section at calculated temperatures.

4. Hydrodynamic slugging can be significant in volume for deep water, large diameter (8” - 10”) risers, and when coupled together can be burdensome for the process facility to accommodate. Special computational methods are required to characterize hydrodynamic slugging.

5. VIT is generally viewed as negative with respect to hydrate mitigation because of the adverse affect it has on cool-down time. VIT does assist with faster heat-up of flowing tubing temperatures on cold earth start-ups. Actual benchmarking of VIT is difficult because of the small changes predicted in flowing tubing temperatures between wells with VIT and without VIT.

6. Methanol is a quality issue in sales oil that can impact start-up of subsea wells, especially after hurricane passage when almost all subsea producers are also utilizing methanol to come online. Pipeline owners are working with operators to manage methanol contamination on a daily basis. However, with the continued development in the Gulf of Mexico using subsea wells, and the continued reliance on methanol, it is conceivable that the ability to manage this issue may decline in the future.

7. Asphaltene prediction technology continues to improve even through the short duration of a development project.

8. Existing wax deposition prediction techniques and flowloop testing can provide the assurance necessary to determine if pigging a potentially wax gas system is necessary.

Acknowledgements. Both BP and Shell based a large portion of this work upon the results of work from various contractors and internal studies. The authors would like to personally recognize the Operations team members and technical support staff of the Na Kika Asset and the members of the Na Kika Subsea System Engineering Team (i.e. NSSET) from the development team for their contributions, as well as the managers and partnership point of contacts who supported all the efforts that were necessary to work through the issues that arose from this complex field development. Nomenclature. APB = annular pressure buildup in B+ casing

annuli bbl = barrel bml = below mud line

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bopd = barrels of oil per day bwpd = barrels of water per day BS&W = Basic Sediment and Water BTU = British Thermal Unit Cool-down time = the minimum time it takes any portion of a

system to reach hydrate formation conditions

°F = Degrees Fahrenheit ft = foot GOR = Gas-Oil-Ratio (standard cubic feet per barrel) JT = Joule Thompson ID = Internal Diameter LDHI = Low Dosage Hydrate Inhibitor mbopd = thousands of barrels of oil per day mbwpd = thousands of barrels of water per day MEG = Mono-Ethylene Glycol NPV = Net Present Value ppm = parts per million psi = pounds per square inch psia = pounds per square inch absolute psig = pounds per square inch, gauge RCFA = Root Cause Failure Analysis SCR = Steel Catenary Riser scf = standard cubic feet

SCSSV = Surface Controlled Subsurface Safety Valve

sec = second TVD =True Vertical Depth U-value =Overall Heat Transfer Coefficient VIT = Vacuum Insulated Tubing vs = versus References. 1. Hudson, John: Na Kika project report “Flow Assurance for Na

Kika System Selection”, Oct. 2002. 2. J. D. Hudson, et al.: “An Overview of Na Kika Flow Assurance

Design,” OTC paper 14186 presented at the 2002 Offshore Technology Conference and Exhibition, Houston, May 6-9.

3. Lawson, Christa: Presentation for “Na Kika Operability Review”, October 2002.

4. Brockman, Anna: Na Kika project report “Na Kika Flow Assurance Surveillance”, January 2004.

5. Makogon, Taras: “Modeling Wax Deposition in Fourier Gas Flowline”, September 2004.

6. Lockett, Tim: “Na Kika North Oil Loop – Slugging during Steady State Operation”, September 2004.

7. Makogon, Taras: “Evaluation of Monoethylene Glycol (MEG) Injection Requirements for Na Kika East Anstey and Fourier”, January 2004.

Table 1 Fluid Properties for the North Loop Oil Wells

MDT Samples Kepler MC 383 OCS-G-7939-003 K-2 Well Asphaltene Data Sample MD (ft) GOR

(cssf/bbl) API OBM% Dead N2 in Gas (mole%) Asphaltene %

1 12381 1171.6 28.5 2.6 0.08 0.18 3 12381 1155.9 28.5 2.5 0.09 0.29 6 12381 1176.9 28.3 2.8 0.00 0.25 7 12381 1179.9 28.6 2.6 0.09 0.18 9 12381 1180.8 28.4 2.7 0.07 0.17

12 12381 1177.0 28.4 2.9 0.00 0.15 13 12381 1166.4 28.4 2.5 0.00 0.14 14 12381 1164.9 28.4 2.9 0.00 0.14

Wax Properties for Kepler fluids

Sample Well Depth (ft) Pay HTGC Cloud Pt. (F)

Coldfinger Cloud Pt. (F)

CPM (F) HTGC Pour Pt. (F)

NG-O3268A #3ST001BP01 12381 K1 81 94 82 <0 PNC-O-5 #1 12848 K1 88 95 NA <0

MDT Samples Ariel A4 MC429 OSC-G-7794 #3 Ariel Well Asphaltene Data

Sample # Pay MD (ft) GOR (cssf/bbl) API Asphaltene % N2 in Gas (mole%) 1 12720 901 25.4 0.29 0.07 4 12720 915 25.4 0.23 0.03 6 12720 909 25.5 0.33 0 7 K1 12720 909 25.4 0.46 0 8 12720 898 25.6 0.48 0 10 12720 831 25.5 0.32 0.09 11 12720 835 25.5 0.40 0 12 12960 1077 25.9 0.14 0 15 12960 1088 26.2 0.14 0 18 A1 12960 1103 25.9 0.17 0.04 19 12960 1117 26.1 0.20 0.06 20 12960 1054 26.2 0.21 0 21 12960 1030 26.1 0.28 0.02 22 13120 1111 26.5 0.24 0 25 13120 1143 26.2 0.20 0.5 27 13120 1103 26.4 0.26 0.09 28 A2 Upper 13120 1121 26.5 0.15 0 29 13120 1139 26.3 0.17 0 30 13120 1033 26.3 0.16 0.07 31 13120 1052 26.4 0.14 0 32 13197 1095 26.1 0.15 0 35 13197 1077 26.0 0.17 0 37 13197 1070 25.9 0.14 0 38 A2 Lower 13197 1096 26.0 0.16 0 39 13197 1096 25.9 0.16 0 40 13197 1014 26.0 0.17 0.07 41 13197 973 26.1 0.26 0

OTC 17657 9

Wax Properties for Ariel fluids

Well Zone Depth (ft) Measured CPM (F)

Coldfinger Cloud Pt.

(F)

HTGC Cloud Pt. (F)

HTGC Pour Pt. (F)

Ariel 4 K1 12720 84 93 77 <0 Ariel 3 K1 12723 90 109 95 <0 Ariel 4 A1 12960 95 99 83 <0 Ariel 1 A1 N/A 98 92 <0 Ariel 3 A1 13174 48 48 48 <0 Ariel 4 A2 Upper 13120 107 107 91 <0 Ariel 1 A2 Upper 98 98 91 <0 Ariel 4 A2 Lower 13197 103 103 87 <0 Ariel 1 A2 Lower 101 101 100 12

10 OTC 17657

Table 2

Fluid Properties for the South Loop Oil Wells

Basic Properties for the Fourier #3 Well

NG-O-3538A MPSR 0293 n/a 38811 44.89 4.20 0.12NG-O-3539A MPSR 0933 n/a 41843 44.47 3.36 0.00NG-O-3542A SSB 8047-MA 30100 46.47 16.01 0.00NG-O-3543A CSB 4915-IANG-O-3544A CSB 7166-MANG-O-3545A CSB 7160-MANG-O-3546A CSB 4837-IANG-O-3547A CSB 6221-MANG-O-3548A CSB 6144-MA 32233 44.89 15.55 0.04NG-O-3549A CSB 5595-IANG-O-3550A CSB 5809-MANG-O-3551A CSB 7170-MANG-O-3552A CSB 5524-IANG-O-3553A SSB 10116-MANG-O-3554A SSB 3864-MA 30354 44.91 13.65 0.00NG-O-3555A SSB 10128-MANG-O-3537A MPSR 0954 n/a 33999 43.71 8.55 0.01NG-O-3540A MPSR 0888 n/a 29262 43.17 11.73 0.13NG-O-3541A MPSR 0961 n/a 26450 46.71 10.64 0.09NG-O-3525A CSB 6977-MA 13718 46.15 0.93 0.11NG-O-3526A CSB 4879-IANG-O-3527A CSB 5464-IANG-O-3528A CSB 7156-MANG-O-3529A CSB 5999-MANG-O-3530A CSB 6896-MA 13133 44.60 0.50 0.15NG-O-3531A CSB 7148-MANG-O-3532A CSB 5972-MANG-O-3533A CSB 6276-MANG-O-3534A CSB 6559-MANG-O-3535A CSB 6272-MANG-O-3536A SSB 9923-MA 12265 46.69 1.11 0.13NG-O-3556A MPSR 0618 n/a 17162 43.43 0.99 0.00NG-O-3557A MPSR 0021 n/a 12707 43.88 0.82 0.00NG-O-3558A MPSR 0953 n/a 12747 44.21 0.43 0.09NG-O-3559A MPSR 0385 n/a 13223 43.88 0.60 0.15NG-O-3560A MPSR 0831 n/a 11188 43.97 1.44 0.12NG-O-3561A MPSR 0824 n/a 11957 43.43 0.83 0.07NG-O-3562A SSB 9635-MA 1251 27.53 0.47 0.07NG-O-3563A SSB 9637-MANG-O-3564A SSB 9918-MA 1264 27.45 0.61 0.05NG-O-3565A SSB 3267-MANG-O-3566A SSB 3855-MANG-O-3567A SSB 9952-MA 1251 27.45 0.75 0.03NG-O-3568A SPMC 034 & 035 SSB 8482-MA 1255 27.75 0.37 0.09NG-O-3569A SPMC 055 & 030 SSB 10130-MA 1276 27.35 0.78 0.12NG-O-3570A MPSR 1242 n/a 1202 26.77 0.73 0.12

F8 UPPER (gas) 16,412.0 NG-O-3571A MPSR 1143 n/a 7544 41.76 8.84 0.17

NG-O-3572A SPMC 086 & 085 SSB 10049-MA 1643 29.33 1.65 0.22NG-O-3573A MPSR 1172 n/a 1446 29.28 0.67 0.08NG-O-3574A SSB 8417-MA 1155 28.35 4.95 0.06NG-O-3575A SSB 1845-IANG-O-3576A SSB 10047-MA 1130 28.42 4.24 0.15NG-O-3577A SSB 8220-MANG-O-3578A SSB 10113-MANG-O-3579A SSB 10046-MA 1103 28.33 3.93 0.12NG-O-3580A SPMC 091 SSB 9924-MA 1195 28.26 4.73 0.08

Pay MD [ft] SAM # MDT Origin Transfer Cylinder GOR [ssf/bbl] API OBM%

Dead

N2 in Gas

(mole

F5 Upper 14,002.0

F5 Upper 14,063.0 MRSC 004

F5 Lower 14,139.0

F7.0 15,156.0

MRSC 077

F7.5 UPPER 15,250.0

F7.5 (OIL) 15,377.0MRSC 213

MRSC 227

F8 UPPER (oil) 16,464.0

F8 LOWER 16,605.0

OTC 17657 11

Table 3

East Anstey Flash Gas Analysis

Reservoir Zero Flash PENCOR ID No. 20703 Sample Depth 16,890 Feet

Reservoir Fluid Flashed from 11,500 psig and 130°F to 15.025 psia and 60°F Gas-Liquid Ratio 159,741 ft3 of Stock Tank Vapors / bbl Stock Tank Liquid API Gravity of Liquid 45.9 @ 60°F Color of Stock Tank Liquid: Dark Straw Gas-liquid ratio is cubic feet of gas at 15.025 psia and 60 °F per barrel of stock tank liquid at 60 °F.

Chromatograph Analysis of Flash Gas

Component Mole % GPM @

15.025 Psia Wt % Mole Weight Nitrogen 0.183 0.000 0.317 28.013 Carbon Dioxide 0.100 0.000 0.271 44.010 Hydrogen Sulfide 0.000 0.000 0.000 34.076 Methane 99.458 0.000 98.636 16.043 Ethane 0.151 0.041 0.280 30.070 Propane 0.026 0.007 0.071 44.097 Iso-Butane 0.018 0.006 0.064 58.123 N-Butane 0.007 0.002 0.026 58.123 Iso-Pentane 0.010 0.004 0.045 72.150 N-Pentane 0.004 0.002 0.018 72.150 Hexanes 0.012 0.005 0.064 85.755 Heptanes 0.014 0.006 0.078 96.958 Octanes 0.010 0.005 0.068 108.099 Nonanes 0.005 0.002 0.036 123.706 Decane Plus 0.002 0.002 0.026 142.285 Totals 100.000 0.082 100.000 Calculated Properties of Gas Gas Specific Gravity (Air = 1.00) = 0.5595 Net Heat of Combustion (Btu/Cu.Ft. @ 15.025 Psia @ 60 °F) Dry= 933.4 Real Gross Heat of Combustion (Btu/Cu.Ft. @ 15.025 Psia @ 60 °F) Dry= 1,036.5 Real Gross Heat of Combustion - Sat. (Btu/Cu.Ft. @ 15.025 Psia @ 60 °F) Wet= 1,018.4

Water Sat.

Gas Compressibility (@ 1 Atm. @ 60 °F) z= 0.9978

12 OTC 17657

FIGURE 1: NA KIKA NORTHERN SIDE SUBSEA LAYOUT FIGURE 2: NA KIKA SOUTHERN SIDE SUBSEA LAYOUT

OTC 17657 13

Fluid Temperature Along Flowline F-2 to Hostassuming bare pipe

30

40

50

60

70

80

90

0 10000 20000 30000 40000 50000 60000 70000 80000Pipeline Length (ft)

Tem

pera

ture

(F)

25 MMscfd 75 MMscfd

FIGURE 3: CALCULATED FLUID TEMPERATURE ALONG FOURIER GAS FLOWLINE (ASSUMING BARE PIPE TO HOST)

Temperature Along Flowline East Anstey to Hostassuming bare pipe

30

40

50

60

70

80

90

0 10000 20000 30000 40000 50000 60000Pipeline Length (ft)

Tem

pera

ture

(F)

50 MMscfd 100 MMscfd

FIGURE 4: CALCULATED FLUID TEMPERATURE ALONG FOURIER GAS FLOWLINE (ASSUMING BARE PIPE TO HOST)

14 OTC 17657

Gas Flowrate vs. Temperature

35

40

45

50

55

60

65

70

75

0 10000 20000 30000 40000 50000 60000 70000 80000 90000Gas Flowrate (Mscf/d)

Tem

pera

ture

(F)

38.2 oF

Topsides temperaturesassuming bare pipe

New results with U value =15 BTU/hr/ft2/F in the riser

FIGURE 5: EAST ANSTEY MEASURED VS. CALCULATED TOPSIDES TEMPERATURES – DECEMBER 2003

East Anstey Gas Flowrate vs. Temperature

20.0

25.0

30.0

35.0

40.0

45.0

50.0

25000 50000 75000 100000 125000 150000 175000 200000Gas Flowrate (Mscf/d)

Tops

ides

Tem

pera

ture

(F)

Gas temperatures topsides(measured at TSIT-2005A)

Calculated Temperatures(assuming insulation in upper

2000 ft of riser)U=9 to 12 BTU/hr-ft2-F Max. production rate

based on 25 oF~ 180 MMscf/d

Min. temperaturesbased on 190 MMscf/d

~ 21 - 24oF

FIGURE 6: EAST ANSTEY GAS FLOWRATE VS. GAS TOPSIDES TEMPERATURE (DEC. 2003 THROUGH FEBRUARY 2004)

OTC 17657 15

Fourier Gas Flowrate vs. Temperature

20.0

25.0

30.0

35.0

40.0

45.0

50.0

20000 40000 60000 80000 100000 120000 140000Gas Flowrate (Mscf/d)

Tem

pera

ture

(F)

Gas temperatures topsides(measured at TSIT-2004A)

Calculated Temperatures(assuming insulation inupper 2000 ft of riser)U=9 to12 BTU/hr-ft2-F

FIGURE 7: FOURIER GAS FLOWRATE VS. TOPSIDES TEMPERATURE (DEC. 2003 THROUGH FEBRUARY 2004)

North Oil Loop Temperature ValidationOil Circulation Cases - Dec. 2003

80

90

100

110

120

130

140

150

160

170

0 20000 40000 60000 80000 100000 120000 140000Total Distance (ft)

Tem

pera

ture

(F)

-7000

-6000

-5000

-4000

-3000

-2000

-1000

0

Dep

th (f

t)

Solid lines = calculated temps.22.5 mbopd15.010.0

Dotted lines = measured temps.~22.5 mbopd~10.0 to 15.0

Elevationprofile

FIGURE 8: SYSTEM TEMPERATURE DROP USING 22.5 MB/D AND 10-15 MB/D OIL CIRCULATION RESPECTIVELY. 0’ AND 135098’ ARE LOCATED AT NA KIKA’S PLATFORM

16 OTC 17657

Herschel Flowline and RiserFluid Temperature vs. Total DistanceFlowrate = ~15 mb/d (May-Aug. 2004)

80

90

100

110

120

130

140

150

160

0 5000 10000 15000 20000 25000 30000 35000 40000 45000 50000Total Distance (ft)

Tem

pera

ture

(deg

F)

Non-flooded Section

12" burial depth in flooded section

Half-buried flooded section

Topsides Temperatures May-Aug. 2004

FIGURE 9: HERSCHEL FLOWLINE TEMPERATURE AS PER DESIGN VS. 12” BURIAL DEPTH AND HALF BURIED FLOODED SECTION

A4 WHT at 0% WCBare Tubing vs. VIT from SCSSV to Wellhead

80

90

100

110

120

130

140

1.5 2.5 3.5 4.5 5.5 6.5 7.5 8.5 9.5Flowrate (mbd)

Tem

pera

ture

(F)

Calculated steady-state temperatures in early-life: VIT (solid line) vs. bare tubing (dashed line)

Calculated WAT Range

Measured wellhead temperatures during intial start-up

FIGURE 10: A4 EARLY-LIFE SCENARIO STEADY-STATE FLOWING TEMPERATURES WITH AND WITHOUT VIT AT 0% WC

OTC 17657 17

FIGURE 11: KEPLER FLOWLINE/RISER OPERATING HISTORY (WITH PROCESS TRIPS REMOVED) FOR THE FIVE WEEK PERIOD (25 MAY 04 – 29 JUNE 04) SUPER-IMPOSED ONTO THE FLOW STABILITY MAP

FIGURE 12: QUANTITATIVE ASSESSMENT OF FLOW STABILITY IN THE KEPLER FLOWLINE

18 OTC 17657

FIGURE 13: ARIEL FLOWLINE/RISER OPERATING HISTORY (WITH PROCESS TRIPS REMOVED) FOR THE FIVE WEEK PERIOD (25 MAY 04 – 29 JUNE 04) SUPER-IMPOSED ONTO THE FLOW STABILITY MAP

FIGURE 14: QUANTITATIVE ASSESSMENT OF FLOW STABILITY IN THE ARIEL FLOWLINE