OWA conference examines expanding frontiers
A torrent of E&P dollars is pouring into West Africa. Analysts agree that the region will not only see the lion’s share of deepwater investment in 2005, but that it will see a large increase in capital expenditure over the next four years.
As fields in the Gulf of Guinea and offshore Angola move into production, new exploration is taking off in areas such as São Tomé & Príncipe. Exploration drilling is planned offshore Morocco, and the first exploration wells have been drilled offshore Tanzania.
The ninth annual Offshore West Africa conference, which will take place in Abuja, Nigeria, March 21-23, provides a forum for information and technology exchange in a region that is at the forefront of deepwater development. The conference theme this year is “Expanding Frontiers.”
The conference includes more than 45 presentations that address subjects germane to the region. Topics range from lessons learned in field development to early production techniques, from production optimization and field architecture to flow assurance, and from project financing to maximizing local content.
The papers summarized here are a sample of the technology mix that will be presented at this year’s conference.
Early production in deep waters
Mats Rosengren
Frontier Drilling do Brasil Vitoria
Early production in deep and ultra-deep waters could employ a dynamically positioned (DP) FPSO as an alternative to conventional turret moored and spread moored FPSOs. Today’s technology for early production has proven DP FPSO production methods offshore Brazil in 2,500-m water depth.
An early production system (EPS) can reduce the time from discovery to first production. An EPS can also determine well stream evidence and reservoir characteristics to handle challenging crude properties of low API grade and high viscosities to declare a field commercial and to plan for a life-of-field production system. In the early production phase, attractive cash flow can contribute to field development funding.
The DP FPSOSeillean has been operating offshore Brazil since 1998.
There are challenges associated with converting a tanker to a DP FPSO for deployment in deep and ultra-deep waters. The analysis presented here is based on six years of proven deepwater early production experience from the DP FPSOSeillean, operating offshore Brazil since 1998.
The concept examined, converting a tanker to an early production DP FPSO, has been namedSeillean 2. It is a second-generation Seillean for early production with the option to outfit the FPSO to perform light well intervention and workover services. The proven and unparalleled concept is applicable to West Africa among several other deepwater areas worldwide.
Discoveries in deep and ultra-deep waters historically take several years from discovery to first production. An early production system can reduce the time frame from discovery to production. Converting an existing tanker vessel to a DP FPSO can provide a fast-track solution to early production in deep waters.
Recent heavy crude discoveries in deepwater demand solutions for handling low API grade crude, high viscosities, and contents as sulfur and acids. Uncertainties of well stream evidence and reservoir characteristics make it difficult to design and optimize a life-of-field production system without first deploying a test and early production phase to obtain the required data.
Since 2002, experience offshore Brazil has proven that heavy crude can be produced in deepwater, and new ventures are underway to make efficient production of crude with difficult properties in deepwater.
TheSeillean is a DP 2 redundant FPSO equipped for test and early production operations to 2,000 m of water.
The vessel is self-contained with a full-size derrick to handle the rigid production riser and subsea equipment, resulting in very fast mobilization and demobilization times.
Crude offloads to a shuttle tanker via a flexible hose between the two vessels. With a few modifications, the FPSO can be upgraded to operate in 2,500 m of water.
TheSeillean 2 concept is built on operating experience from the operating DP FPSO Seillean and is based on a conversion of an Aframax size tanker with 1 MMbbl crude oil storage capacity when trading as a tanker. The concept Seillean 2 also takes into consideration the ability for the FPSO to be equipped to perform other services than test and early production.
The analysis carried out to evaluate the DP FPSO deepwater early production concept indicates that a DP FPSO is a viable option.
New plugging techniques used in Mexico to save wells and obtain a successful kickoff
Francisco Cázares Robles,
Victor Arreola Morales
Pemex
Hank Rogers,
Raúl Bonifacio, Jorge Rivera
Halliburton
The bottomhole kickoff assembly is being related from the workstring.
A new bottom hole kickoff assembly (BHKA) tool has resulted from a combination of many studies and best practices applied to plug-placement techniques. The tool places cement through a diverter, which allows the placement of a fast-curing slurry, a key element of kickoff success. The BHKA tool has worked in several wells, enabling a successful kickoff when abandoning the well seemed to be the only option. In every case, failed kickoff attempts using conventional techniques preceded the successful use of the BHKA.
As drilling techniques advance and wellbores become more complex, placing a successful kickoff plug on the first attempt becomes more challenging. Well conditions can have a negative influence on the performance of the cement plug, which can significantly impact drilling time and increase costs.
In highly deviated wells, mud and cement stratify, and the heavier fluid falls to the low side of the hole, creating well conditions that negatively impact plug performance. Other factors that can cause issues are lost circulation problems caused by a narrow mud-weight window between fracture gradient and pore pressure. High concentrations of lost-circulation materials in the mud systems impede pumping at the desired rates for optimum displacement efficiency.
Another factor is shorter length available to kickoff since re-entries are becoming more popular in mature fields as an alternate way to look for different production zones. Windows of 65 ft and less open in the intermediate casings to create new holes.
Wellbore geometry is also a determining factor because of the additional difficulty of effectively placing small volumes of cement slurry under deep high pressure/high temperature conditions and washed-hole sections.
The six case histories in this presentation illustrate how using a BHKA tool to place competent cement plugs can help overcome challenging well conditions. All of the jobs were executed for Pemex Offshore and South Region at an average depth of 14,607 ft with 252º F bottomhole temperature.
The technical challenges of bringing EA surface facilities to steady state operations
Tony Offor, Timi Shodunke
Shell Nigeria Exploration & Production Co.
Project and asset managers must recognize the challenges in managing an asset during start-up and plan for the resources required. Failure to do so increases the risk of low overall facility availability and loss of production.
Shell’s shallow-water EA development came onstream in December 2002 ahead of schedule and within budget. Benchmarked against industry FPSO developments, the project is a success.
EA facilities comprise a manned FPSO with 1.4 MMbbl storage capacity. The FPSO design allows it to weather vane around a soft yoke mooring platform (SYMP). EA has three unmanned minimum intervention facility wellhead platforms to which the FPSO supplies power. The FPSO supplies power to the SYMP and the offshore gas gathering system (OGGS) riser platform RPA as well. The development includes an interconnecting system of subsea pipelines for production and gas lift to/from the wellhead platforms and the FPSO. Umbilicals carry power, control, and ESD signals between the FPSO and wellhead platforms. Gas disposal is via the OGGS riser platform to the NLNG faciolity at Bonny Island.
The facilities management team overcame challenges to bring the facilities to steady state operations. During the run in period, several equipment failures occurred, and a number of latent design defects came to light. The team contended with these developments and managed to achieve production in line as planned.
Following a successful start-up, a catastrophic sand erosion failure of the choke valve on well 35 caused a loss of containment. The valve had been in service for only 62 hours before the failure. This failure led to the shut-in of the EA facilities for 23 days while extensive investigations were carried out to determine the cause of failure.
Investigations showed failure characteristics that are more typical of sand entrained by gas than by oil. Analysis concluded that Well 35 experienced gas breakthrough from the overlying gas cap. Hardware and operational changes addressed this problem.
The next problem involved the SYMP. Friction caused damage to the wheels and the U channels guiding the wheels on one of the components, and the bolts at the gangway/trailer bearing failed because loads were underestimated.
There was also high friction between the spherical bearing and the corresponding socket due to error of materials. The specifications called for a polyethylene socket, but a polyurethane socket, which has a much higher coefficient of friction, was installed.
The next issue concerned the gas compressor. During performance testing, the compressor tripped on high radial vibration. An investigation concluded that enhancing rotor stability and replacing a suction scrubber is required to meet design conditions.
Subsequent failures in a number of systems led an asset manager on the project to remark, “Almost every kit on the facility except piping posed a challenge during the run in period.”
This experience points to the need to recognize the challenges inherent to the run in process and to establish ways to contend with failures. Embarking on this process without taking the challenges into account creates the possibility of lost production and lost revenue. Snepco recognizes that having a plan in place and dealing with EA’s simple facilities design contributed to successfully bringing EA surface facilities to steady state operations.
