The success of recent applications in underbalanced drilling (UBD) and managed pressure drilling (MPD) has accelerated the development of technology in order to optimize drilling operations. The increased number of depleted reservoirs and the necessity for reducing formation damage has also increased the need to apply UBD/MPD to such candidate fields. Several methods used the latest mechanistic multiphase flow models in order to predict bottomhole circulation pressure when performing UBD/MPD operations. A new model is developed that utilizes the latest mechanistic multiphase flow models; the developed model calculates the bottomhole circulation pressure as a function of surface injection rates, choke pressure and time.
The developed model can be used in designing and optimizing UBD/MPD operations in terms of determining the correct injection rate and/or choke pressure. In addition, the developed model is used to utilize the reservoir energy to attain correct bottomhole conditions. The developed model in addition to utilizing the latest mechanistic models also reduce the error in calculating the bottom hole pressure by incorporating an algorithm in which the injection rates are calculated in-situ rather than assuming constant injection rates.
The model is validated against data from literature and against a commercial simulator. Results show that the developed algorithm has increased the accuracy in predicting bottomhole pressure by incorporating the changes in new gas and liquid injection rates.
Wang, Cynthia (Keppel Offshore & Marine Technology Centre) | Quah, Matthew (Keppel Offshore & Marine Technology Centre) | Noble, Peter G. (ConocoPhillips) | Shafer, Randall (ConocoPhillips) | Soofi, Khalid A. (ConocoPhillips) | Alvord, Chip (ConocoPhillips Alaska Inc.) | Brassfield, Tom (ConocoPhillips Alaska Inc.)
Jack-up drilling units have been used in Arctic open water seasons and areaswith icebergs. They have not been used in areas where significant sea ice canmove in with high concentrations. These areas have typically been drilled usinga floating mobile offshore drilling unit (MODU) although the water depths aretypically less than 50 meters. Floating MODUs in shallow water depths can havesignificant downtime due to the limited offset in shallow water and typicallyrequire placing the well control equipment in a seabed cellar. In these areas,jack-ups can improve both operational safety and efficiency as they havelimited weather related downtime.
Several studies were carried out to determine the feasibility of using amodern high capacity jack-up MODUs for exploratory drilling in these areas.This paper will review the studies including structural analysis, icemanagement approaches, and well control considerations. It will also review thefurther potential of jack-ups in the Arctic.
Studies showed that using a jack-up drilling unit is feasible in shallowArctic seas such as the Chukchi Sea when coupled with an effective icemanagement system. The jack-up unit has sufficient ice resistance to withstandinteraction with thin early winter ice. Specific designs of jack-ups arecapable of taking impact forces from thicker ice floes that may occur during anice incursion event during the open water season. The maximum floe size duringan ice incursion is limited and controlled by the associated icemanagement system.
An ice management system was developed using a combination of satelliteimagery, ice management vessels, and ice alert procedures. This system wasdetermined as effective in managing ice to allow the jack-up to operate in theChukchi Sea area.
Environmental and personnel safety is enhanced by the use of aPre-positioned Capping Device, an in place source control device. The device isindependent from the rig's well control system and provides another level ofprotection in additional to the jack-up's BOP.
The conclusion, based on structural and ice management studies, is thatmodern high capacity jack-up drilling units can be an effective way to drillwells during the open water season in shallow waters of Arctic seas includingareas in to which sea ice can move. The studies also show that there ispotential for use in other areas.
Saleem, Saad (Pakistan Petroleum Limited) | Sattar, Suhail (Pakistan Petroleum Limited) | Shahzad, Atif (Weatherford Oil Tools M.E. Limited) | Ziadat, Wael (Weatherford Oil Tools M.E. Limited) | Sabir, Shahid Majeed (Weatherford Oil Tools M.E. Limited)
The name "Sui?? has become synonymous with natural gas in Pakistan. Sui is Pakistan Petroleum Limited's (PPL) flagship gas field. Commercial exploitation of this field began in 1955.
Two major reservoirs of this field are Sui Main Limestone (SML) and Sui Upper Limestone (SUL). Both the reservoirs have become highly depleted by time. Conventional drilling technologies in these formations result in complete loss of drilling fluid, stuck pipe and severe formation damage issues.
Pakistan Petroleum Limited (PPL) planned to drill a horizontal well Sui-93(M), where target reservoir was Sui Main Limestone (SML). Drilling a horizontal well with conventional drilling techniques can cause a complete loss of drilling fluid. Underbalanced Drilling integrated with electromagnetic telemetry transmission was successfully used to drill this well to a target depth of 2200m MD with complete directional controls. Electromagnetic transmission modeling was performed on the resistivity data of offset wells to determine signal attenuation for Sui-93(M) Well. Based on modeling results it was decided to run an extended range set-up with a downhole antenna.
The main reason for using EM-MWD was to provide real time data for annular pressure (APWD sensor) and directional controls in UBD environment. The APWD (annular pressure while drilling-real time ECD) sensor was considered mandatory to monitor and ensure underbalanced condition while drilling, thereby avoiding significant problems such as lost circulation and stuck pipe.
This paper discusses the planning, results, problems and lessons learned during the first application of the Extended Range EM-MWD (Electromagnetic-Measurement while drilling) technology in Sui-93(M) well.
The application of EM-MWD along with UB technology represents a stepwise progression for improving PPL's ability to exploit mature reservoirs, especially those that are severely depleted like in Sui Gas Field, Pakistan.
Sherwani, Waseem Akhtar (Eastern Testing Service (Pvt) Limited) | Qureshi, Imran (Eastern Testing Service (Pvt) Limited) | Khattak, Kifayatullah (Eastern Testing Service (Pvt) Limited) | Ali, Abdul Salam (Eastern Testing Service (Pvt) Limited) | Ali, Syed Dost (Pakistan Petroleum Limited)
Well control is the management of the hazardous effects caused by the unexpected well release. In a production well, downhole safety valve and X-mass tree are considered the main barriers against the well release in the event of a worst case scenario surface disaster. Inadequate risk management and improperly managed well control situations cause blowouts, potentially resulting in a fire hazard.
This paper describes a case history of a production well where a tubing string was eroded severely during production phase. The problem was detected while attempting to retrieve the separation sleeve in the long string which was not accessible at the required depth. Downhole camera indicated that 90% of the long string had been eroded and remaining 10% is connected with the flow coupling. Thus, full workover job was required to replace tubing strings. However, the lack of well control barrier in the tubing to prevent uncontrolled flow of hydrocarbons prior to blowout preventer (BOP) installation for the workover was a serious safety concern.
Introduction of Nippleless Tubing-Stop Plug technology provide an effective, safe and economical remedial solution to the problem.
As part of well control standard, double barrier policy is always maintained on the well to avoid unwanted and uncontrolled flow from the well. Before any work over, the well must first be killed as a first well control barrier. A second barrier is required to prevent communication from the wellbore to surface once the wellhead is removed. Tubing plug is an effective second barrier used to isolate the wellbore pressure from tubing.
NIPPLELESS PLUG TECHNOLOGY DEPLOYMENT
In the past, the tubing plug's lock systems have been designed in which landing nipples or profiles are provided along the tubing string's interior surface, and wherein a lock/ plug will be placed in the nipple or profile. However, placement of a lock of this type is limited to those points along the string at which an appropriate nipple or profile is located. In cases where tubing string is damaged or eroded where nipple or profile is no longer usable, the common tubing plug can no longer be a barrier device.
Introduction of "Nippleless?? plugs addressed this issue because they do not require the presence of a nipple or profile to be set within a string. Nippleless plug offer the capability to set plugs at any depth or point within well.
Crespo, Freddy E. (University of Oklahoma) | Ahmed, Ramadan Mohammed (University of Oklahoma) | Saasen, Arild (Det norske oljeselskap ASA) | Enfis, Majed (University of Oklahoma) | Amani, Mahmood (Texas A&M University at Qatar)
Surge and swab pressures have been known to cause formation fracture, lost circulation, and well-control problems. Accurate prediction of these pressures is crucially important in estimating the maximum tripping speeds to keep the wellbore pressure within specified limits of the pore and fracture pressures. It also plays a major role in running casings, particularly with narrow annular clearances. Existing surge/swab models are based on Bingham plastic (BP) and power-law (PL) fluid rheology models. However, in most cases, these models cannot adequately describe the flow behavior of drilling fluids. This paper presents a new steady-state model that can account for fluid and formation compressibility and pipe elasticity. For the closed-ended pipe, the model is cast into a simplified model to predict pressure surge in a more convenient way. The steady-state laminar-flow equation is solved for narrow slot geometry to approximate the flow in a concentric annulus with inner-pipe axial movement considering yield-PL (YPL) fluid. The YPL rheology model is usually preferred because it provides a better description of the flow behavior of most drilling fluids. The analytical solution yields accurate predictions, though not in convenient forms. Thus, a numerical scheme has been developed to obtain the solutions. After conducting an extensive parametric study, regression techniques were applied primarily to develop a simplified model (i.e., dimensionless correlation). The performance of the correlation has been tested by use of field and laboratory measurements. Comparisons of the model predictions with the measurements showed a satisfactory agreement. In most cases, the model makes better predictions in terms of closeness to the measurements because of the application of a more realistic rheology model. The correlation and model are useful for slimhole, deepwater, and extended-reach drilling applications.
This paper summarizes 10 years of experiences on pumping cement through bottomhole drilling assemblies - BHAs. Despite a lot of industrial skepticism, a total of 79 cement jobs have been performed through a variety of drilling assemblies, in 3 categories of job types:
i) Curing critical mud losses to restore well control
ii) Plugging back pilot holes
iii) Planned plug or squeeze jobs
The job objectives were met for all the cement jobs performed, and high risk well control situations were resolved. The cementing operations have been performed from different types of offshore installations, like fixed platforms, semi-submersible rigs, as well as from TLP's - Tension Leg Platforms.
Most significantly, critical mud losses have been cured by pumping totally 13 cement jobs through rotary steerable drilling assemblies. Losses were cured and well control restored by performing jobs mainly through 8 ½?? - and 12 ¼?? drilling assemblies. The most severe case handled HPHT conditions and cesium formate drilling fluid.
By taking a controlled risk, the total well risk is significantly reduced. Time and huge costs are saved by performing cement jobs that are instinctively considered as a threat to well control. By planning these cement jobs carefully, the total risk of performing the operation through the bottom hole assembly is reduced.
After gaining experience from some severe, un-planned lost circulation incidents, a best practice was developed and implemented in order to be better prepared, especially for the un-planned events. The same procedures have also been implemented in the planning phase of drilling operations and some cementing operations are planned and executed this way.
Martinez, Erik (Halliburton) | Ramirez, Silvestre (Pemex E&P) | Ramirez Lara, Ricardo (Pemex E&P) | Alvarez Lopez, Eduardo (Pemex E&P) | Bevilacqua, Simon (Halliburton) | Barrera, Guillermo (Halliburton)
The Bolontiku field is located offshore on the continental shelf of the Gulf of Mexico, adjacent to the coast of Tabasco state. This field is composed of dolomitized carbonates of the Upper Jurassic Kimmeridgian formations, which yields 39° API hydrocarbons. Exploitation has dropped the bottomhole pressures from 8,159 psi to 5,600 psi and has created an average operating drilling window of 0.07 g/cm3. Such a narrow operating window increases the technical difficulty for continued development in this mature field using conventional drilling techniques. The complexity of effectively controlling the wellbore pressure has resulted in an endless cycle of fluid loss to formation, kicks, and well control events that translate into non-productive time (NPT), which increased operating time and costs, potentially leading to well abandonment.
A managed pressure drilling (MPD) technique allows for effective control of the pressure profile throughout the wellbore, identifying the bottomhole pressure (BHP) limits and applying appropriate backpressure accordingly. Owing to its efficiency, this technique has evolved from an innovative technology to become a required application to mitigate the inherent wellbore pressure problems associated with conventional drilling. Therefore, as MPD evolves, different approaches for well control evolve for kick events.
This paper describes a well-control application simultaneous to the drilling operation using MPD with a closed-loop pressurized control system. This paper reviews a case history of two wells that were drilled with MPD and compares results against three wells that were conventionally drilled in the Bolontiku field. MPD and simultaneous well control allowed for drilling the Bolontiku 37 well, which consisted of compartmentalized pressure that historically lead to fluid losses and water influxes. Therefore, it was possible to drill through zones that before were not technically possible.
Towards the later part of the 20thcentury, the oil industry has been looking for more safer and beneficial drilling methods, especially in deep waters. The high well/field costs pushed the need for attractive technologies which would optimize drilling. Also ever since the catastrophic events of April 2010 in the Gulf of Mexico, the oil industry has been constantly scrutinized for the health and safety standards or rather the lack of it. The consequences of the blowout highlighted the need for improved kick detection and well control. In deepwater wells, there exists a narrow window between the fracture pressure and the pore pressure. This narrow margin poses a safety hazard both for the well and the crew operating on it. Drilling in these sort of fields require distinctive methodologies to achieve both objectives of safe and optimized drilling.
Thus one such method which would optimize drilling and improve well control is Managed Pressure Drilling (MPD). This has been defined as "an adaptive drilling process to accurately control the annular pressure profile throughout the well??. This technique would create a pressure profile in the well to be within tolerance and close to the boundaries or limits controlled by the pore and fracture pressure.
For the understanding of kick detection, well control and circulation when MPD is being employed, a hypothetical well data with a narrow pressure window is selected and a kick is simulated to be controlled using MPD. The pump rate & mud density is studied and kick detection, well control and circulation is analyzed and interpreted. Obviously with the usage of the MPD tools and equipments during drilling, there would be a difference from conventional kick detection, which could probably be enhanced well control. MPD would thus, be able to properly manage any influxes from the formations thereby protecting the system and structure above and have a telling effect on the Non Productive Time (NPT).
Foam-assisted underbalanced drilling technique is advantageous over the traditional overbalanced drilling near the productive water-sensitive formations due to its reduced formation damage, improved rate of penetration, higher cutting-transport capacity, and lower circulation losses. However, the complicated nature of foam rheology has been a major impediment to the optimal design of field applications.
Earlier studies with surfactant foams without oils and polymers show that foam flow in pipe can be represented by two different flow regimes: the low-quality regime showing either plug-flow or segregated-flow pattern, and the high-quality regime showing slug-flow pattern. The objective of this study is to investigate foam flow characteristics in horizontal pipes at different injection conditions, with or without oils, by using polymer-free and polymer-added surfactant foams.
The results of this study were presented in two different ways: (i) steady-state pressure drops (or, apparent foam viscosity, equivalently) measured by multiple pressure taps and (ii) visualization of bubble size, size distribution and flow patterns in transparent pipes. The results with surfactant foams and oil showed that (i) oil reduced the stability of foams in pipes, hence, decreasing the steady-state pressure drops and foam viscosities, and (ii) the presence of oil tended to lower the transition between the high-quality and the low-quality regimes (i.e., lower foam quality at the boundary, or lower fg* equivalently). In addition, the results with surfactant foams with polymer showed that (i) polymer thickened the liquid phase and, if enough agitation was supplied, could make foams long-lived and improve foam viscosities, and (ii) the system sometimes did not reach the steady state readily, showing systematic oscillations. In both cases, though, the experiments carried out in this study showed the presence of two distinct high-quality and low-quality flow regimes.
BP's intent is to maintain well control from spud to abandonment. However, if for any reason well control is lost, we are designing our wells with the capability to stop or minimize the flow of oil into the water column using a capping system. The cap can stop the flow completely or we can minimize the flow where a collection system or plan could be required.
As part of BP's commitment to enhance deepwater safety and response preparation, BP has developed a comprehensive Global Deepwater Well Cap and Tooling Package. The system can be rapidly deployed to any of BP's operational regions in response to a well control event.
The system includes an Upper and a Lower capping stack, flow-back assembly, flex joint riser adapters, flex joint stiffeners, a comprehensive remote operated vehicle (ROV) tooling package, debris removal tools, dispersant distribution system, subsea hydraulic power unit with a launch and recovery system, subsea accumulator and 60-inch pipe shears for shearing a drilling riser. In total, the system contains over 250 components, 65 lifts, and weighs approximately 500 mT. The Global Deepwater Well Cap and Tooling Package is rate at 10,000 ft. water depth, 15,000pso and is fully air transportable onboard Antonov AN-124 and Boeing B747 200, 400 and 800 series heavy-lift aircraft. No disassembly is required to airfreight the system.