DRILLING TECHNOLOGY Refining kick detection in HPHT drilling projects
Low margin between pore pressure and formation
strength requires ability to detect one bbl loss or gain
Frank Frazer
Contributing Editor - Scotland
Research supported by Shell has shown that advanced kick detection systems can be adapted for use offshore, offering cost benefits in exploration and production from high pressure and high temperature (HPHT) formations.
There is an increasing need for proven equipment to provide drillers with early warning of gas influx as more HPHT wells are planned in the Gulf of Mexico, the North Sea and other areas with deep-lying oil and gas prospects.
Reliable systems, able to detect threats from the sudden intrusion into the mud column of gas volumes with an energy equivalent as low as one bbl of oil, can mean significant savings in planning well configurations without compromising on safety.
Details of the latest research findings were outlined by engineers from Shell's exploration and production laboratory at Rijswijk in The Netherlands in a paper at the 9th Annual Offshore Drilling Technology Conference in Aberdeen organized by the energy division of IBC Technical Services in association with Offshore Magazine and Oil & Gas Journal.
Tim Harris, who prepared the paper with co-authors P. Hendriks and J. H. G. Surewaard, said many HPHT wells - defined as those in which shut-in pressure can exceed 10,000 psi and bottom hole temperature above 150 C - had a low margin between pore pressure and formation strength.
Low margin
Pointing out that one of the most vulnerable periods was when making a connection, he added: "At such a time, the subsequent reduction in well bore pressure generated by reverting from circulating to static mud gradient may be sufficiently large to allow a formation previously controlled to produce a concentrated gas kick."
Studies have shown a need to detect gas influx in the range from less than 1-5 BOE to reduce the risk of an internal blowout - not only in slimhole wells but also with conventional sizes up to 8.5 in. in diameter.
"It is therefore prudent to specify that advanced kick detection systems have the capability to reliably detect less than one bbl of formation fluid influx for HPHT wells in order to minimize well control safety risk and maximize possible well operations/design cost benefits," Harris said.
Conventional kick detection methods - including standard pit volume totalizers, paddle flow-out devices and physical checks during drilling breaks - are thought to be effective in detecting influxes of about 10 bbl. But because the dynamics of drilling operations can complicate the interpretation of raw data, the methods can lead to numerous time-consuming and costly false alarms.
In an attempt to overcome the deficiencies, Shell researchers worked with Baker Hughes Inteq on the development of an advanced kick detection system (KDS) using a combination of accurate instrumentation and software to monitor normal drilling operations.
Instruments, software
The hardware part of the configuration uses three meters to measure delta flow - one on the flow-out line, another on the standpipe flow-in line, and the third on the flow line from the trip tank to annulus. Signals are fed to a Sun Sparc computer for real-time processing using dedicated software which models the dynamics of the mud in the hole.
The KDS also features a hook-load transducer, a hook position sensor and a stand-pipe pressure transducer. Because of the need to limit the number of false alarms while still detecting the slightest change in well conditions, considerable efforts have been made to develop reliable predictive software which will provide proper flow dynamics compensation.
The need for heave compensation represents a special challenge in using the system in an offshore environment. In particular, vessel motion can induce flow-out variations of sufficient size to reduce detection sensitivities and give erroneous alarms.
Flow compensation
Among solutions studied by Shell is a flow compensation system (FCS) developed by Thule Rigtech to remove the main effects of rig heave from the flow measurements. Testing of a prototype in rough North Sea conditions showed it was feasible to dampen flow-out fluctuations caused by heave. Harris said Thule Rigtech had used experience from the successful field trials to design a modified FCS for easier deployment and operation.
He added that cheaper software-based solutions were also available, using real-time sensor measurements of either fluid level in the riser or heave measurements.
"Successful field experience with such software-based heave modeling techniques has already been obtained on a drill ship where the KDS provided one bbl detection of various simulated influxes at kick drills," he said.
As an example of the economic spinoff from successful application of KDS techniques, Harris quoted an onshore slim hole operation where savings of around $200,000 per well were achieved by eliminating an intermediate casing string in the knowledge that monitoring of reservoir conditions by the KDS justified safe reduction in design kick tolerances.
"Extrapolating such economics for the deeper, more cost-intensive offshore HPHT operations, the use of the KDS may in some cases generate the potential for well cost savings of several million dollars per well," Harris said.
Studies have also shown that present acoustic systems and signal processing techniques can be programmed to detect kicks of about one-three bbl with minimal false alarms. But this method does not work when mud circulation is cut off during tripping and making connections.
Sonar detection
To overcome the shortfall, Shell and Statoil are working with IKU Petroleum Research on a sonar gas kick detection system which will function regardless of whether or not mud is being pumped. It works on the same principle as an echo sounder by monitoring feedback from sound pulses to determine changes in downhole conditions.
Harris said that further system development would aim at refining real-time signal processing and ensuring that pressure integrity of the wellhead was maintained after fitting the equipment.
"This having been achieved, the wellhead sonar also has the potential to improve both HPHT well kill practice and research understanding by providing beneficial information relating to the position of the top of the free gas influx in the well whilst performing well control operations," he claimed.
Looking ahead, Harris believed that there would be well-site integration of the various kick detection techniques to enhance the reliability of alarms and response procedures. Fail-safe combination of methods should ensure quick closure of blow-out preventers with sonar detection remaining operational to track movement in real time of the top of free gas while well control operations were mounted, he suggested.
"Well cost reduction, whilst still maintaining a high level of safety, is a vital ingredient for the successful economic development of the large reserves held in HPHT areas. The future, therefore, truly belongs to those parties who, individually or in combination, can prove they possess the understanding, tools and techniques necessary to manage and control the inherent risks," he said.
