Risk Assessment of Underbalanced and Managed Pressure Drilling Operations

Transcription

1 Risk Assessment of Underbalanced and anaged Pressure Drilling Operations ari Oma Engevik ay, 007

2 of Faculty of Engineering Science and Technology Department of Production and Quality Engineering Date Our reference AR/S ASTER TESIS Spring 007 for stud. techn. ari Oma Engevik RISK ASSESSENT OF UNDERBAANCED AND ANAGED PRESSURE DRIING OPERATIONS (Risikovurdering av underbalansert boring og boring med styrt trykk ( managed pressure drilling )) In recent years, underbalanced drilling (UBD) and managed pressure drilling (PD) have been developed as alternatives to the traditional overbalanced drilling technique. The new techniques have several advantages, but the blowout risk is yet not fully understood. The main objective of the current master thesis is to develop a blowout risk model for UBD and PD that is compatible with the blowout frequency assessment model (BlowFA) that has been developed by Scandpower. As part of this thesis, the candidate shall:. Give a detailed presentation of the technology and procedures that are used for UBD and PD. The presentation shall be based on a detailed literature survey and contacts with drilling operators and their consultants.. Identify, describe and document hazardous events during the various steps of a UBD and an PD operation. The hazard identification shall be carried out by using analytical tools and supplemented by interviews with relevant personnel and analyses of available field performance data.. Extract descriptions of relevant well control incidents from available data and identify and describe root causes and causal distributions. 4. Establish formulas for relations between the causes in para. and formation characteristics. 5. Establish a generic blowout frequency model that is compatible with BlowFA. Following agreement with the supervisor, the various items may be given different weights.

3 aster Thesis Spring 007 for stud. techn. ari Oma Engevik Date Our reference AR/S of Within three weeks after the date of the task handout, a pre-study report shall be prepared. The report shall cover the following: An analysis of the work task's content with specific emphasis of the areas where new knowledge has to be gained. A description of the work packages that shall be performed. This description shall lead to a clear definition of the scope and extent of the total task to be performed. A time schedule for the project. The plan shall comprise a Gantt diagram with specification of the individual work packages, their scheduled start and end dates and a specification of project milestones. The pre-study report is a part of the total task reporting. It shall be included in the final report. Progress reports made during the project period shall also be included in the final report. The report should be edited as a research report with a summary, table of contents, conclusion, list of reference, list of literature etc. The text should be clear and concise, and include the necessary references to figures, tables, and diagrams. It is also important that exact references are given to any external source used in the text. Equipment and software developed during the project is a part of the fulfilment of the task. Unless outside parties have exclusive property rights or the equipment is physically non-moveable, it should be handed in along with the final report. Suitable documentation for the correct use of such material is also required as part of the final report. The student must cover travel expenses, telecommunication, and copying unless otherwise agreed. If the candidate encounters unforeseen difficulties in the work, and if these difficulties warrant a reformulation of the task, these problems should immediately be addressed to the Department. Two bound copies of the final report and one electronic version are required.

4 aster Thesis Spring 007 for stud. techn. ari Oma Engevik Date Our reference AR/S of Responsible professor/supervisor at NTNU ocal supervisor at Scandpower Risk anagement AS offices will be Professor arvin Rausand Telephone: marvin.rausand@ntnu.no Aexander Solberg, senior consultant Scandpower Risk anagement AS P.O.Box NO 07 Kjeller Telephone: als@scandpower.com DEPARTENT OF PRODUCTION AND QUAITY ENGINEERING Asbjørn Rolstadås Professor/ead of Department arvin Rausand Responsible Professor

5 Preface This master thesis was has been written during the spring semester 007, at the Norwegian University of Science and Technology, NTNU. The main objective of the master project was to developed a generic blowout frequency model for underbalanced and managed pressure drilling operations. The work was performed in cooperation with Scandpower, and the model developed was supposed to be compatible with their blowout frequency assessment model for conventional overbalanced drilling operations. According to the consulted companies, only two blowouts during PD operations have occurred. Because of lack of data, it was not possible to develop a blowout frequency model. The focus of the thesis was therefore shifted toward a description of underbalanced and managed pressure drilling technology, and various risk assessment methods and their use during these operations. It is assumed that the readers of this report have basic knowledge in drilling technology. I would like to thank my supervisors Professor arvin Rausand at NTNU and Senior Consultant Alexander Solberg at Scandpower for their assistance during the preparation of this report. I would also like to thank ichael Golan, Dave Samuelson, Per oland, Arild Rødland, Alf Breivik, arald Tveit, Johan Eck-Olsen for their contributions to this thesis. ari Oma Engevik Trondheim June 8, 007

6 anagement summary 5% to % of all remaining undeveloped oil and gas reasources can not be utilized by means of conventional overbalanced drilling. In addition, there are wells still containing oil and gas which could have produced more if alternative technologies to overbalanced drilling technology where utilized.since 990 underbalanced and managed pressure drilling has become increasingly used alternative technologies to conventional overbalanced drilling technology. With proper use these technologies may; eliminate or minimize formation damage, minimize costs related to the well, and increase safety during the drilling operations. owever, the risk during these operations are yet not known. During overbalanced drilling operations fluid from the reservoir is prevented from flowing into the well by a static mud pressure. This pressure is a result of the mud which is used during a drilling operation to carry cuttings from the formation to the surface. The pressure at surface is at atmospheric pressure. In underbalanced and managed pressure drilling, a lighter drill fluid can be used because a surface pressure is imposed. The main difference between overbalanced drilling and the alternative drilling technologies, is the use of a surface pressure during the drilling operation. Numerous accidents have been documented with use of overbalanced drilling technology. By evaluating earlier accidents and their cause, the risk these operations exposed to human, environment and assets, are fairly well known. In order to learn more about the risk during underbalanced and managed pressure drilling operations, earlier incidents should be collected and analyzed in a proper way. To collect data of well incidents during underbalanced and managed pressure drilling operations, authorities and companies in th U.S., Canada, and Norway were contacted. Only two incidents have occurred, both with use of managed pressure drilling technology. No reports were found on the well incidents. A hazard analysis was performed on a managed pressure drilling operation. This operation is at the moment performed on Kvitebjørn. Kvitebjørn is a field operated by Staoil, located in the North-Sea. The purpose was to identify hazards, and evaluate the most risk contributing factors during the operation. The analysis was made on a procedure the personnel follows during the connections of pipes operation. Connections of pipes are made in order to drill to further depths. With new technology it is important to train personnel involved in the operation, and make sure that the level of competence is high. During the operation, external managed pressure drilling personnel will be involved. The communication will be in English. The internal personnel usually communicates in Norwegian. Extra focus on the communication is needed. In addition, it is important that the personnel, the internal as well as the external, have clear responsibilities and that the procedures they follow are sufficient. In order to state causes leading to incidents, and prevent future accidents from occurring during drilling operations, a numerous of accident investigation methods has been developed. Four different methods were evaluated on behalf of their; scope, user friendliness, and resource need. One of the methods were utilized on an accident to evaluate the course of events, and to develop a set of precautions to prevent similar accident form occurring. The accident occurred on a well drilled overbalanced. During the drilling operation, the pressure of the mud column became lower than the pressure from an unexpected gas containing pocket in the formation, and unwanted gas flowed into the well. The crew managed to regain and maintain control over the well the following days. The accident may have been prevented if; better equipment were utilized to detect gas pockets in the formation, analysis of the formation had been better, or if alternative

7 drilling technologies were utilized. In overbalanced drilling operations, the probability of having an uncontrolled release of formation fluid is known. This is not the case for underbalanced and managed pressure drilling operations. By gathering information of the fluids flow rate through critical equipment during underbalanced and managed pressure drilling operations, the probability of release of formation fluids can be calculated. An uncontrolled release of formation fluids may occur if more than one of the well safety equipment should fail to function properly. The probability of uncontrolled release of formation fluid, can be calculated by combining the critical equipments probability. 4

8 Part Introduction 5

9 Introduction During the last 7 years underbalanced drilling, UBD, and managed pressure drilling, PD, have become increasingly used alternatives to conventional overbalanced drilling, OBD, technology. The new techniques provide several advantages, but the blowout risk during these operations is yet not fully understood. Since the rotary drilling technology was introduced early in the last century, it has been the most used drilling technology in the oil and gas industry [, 5]. The technique is well-established, and a number of well incidents have been documented. This has made the risk picture during OBD operations fairly well known. As for UBD and PD operations the well incident data is limited, and the risk picture is not complete. Scandpower has developed a blowout frequency assessment model, BlowFA. The model is a data tool for qualitative and quantitative safety evaluation of blowouts during OBD and well operations. BlowFA reflects the actual elements; the technical, the operational and the organisational as well as reservoir conditions, that play an important role for the blowout risk. The program does not include UBD and PD operations, and it is of interest to implement these techniques into the program. Few well incidents have occurred during UBD and PD operations. azard analysis and risk evaluations of well projects that utilize these technologies have been performed, but there has not been developed any worldwide accident investigation to state causal distributions and blowout statistics. Because there has been an increasingly use of UBD and PD technology world wide, it is important to understand the risk during these operations. On the Norwegian continental shelf one UBD operation, and five PD operations have been performed. In 004, Statoil successfully performed an UBD operation on Gullfaks well C-05. One PD operation was made by British Petroleum (BP) in the late 90 s by use of coiled tubing. ConocoPhillips used PD on Tommeliten, and Statoil has performed operations on Gullfaks and is at the moment using the technology on Kvitebjørn. All of the wells were drilled successfully. In addition, Statoil is planning to use PD on Kristin [4]. In order to collect well incident data during UBD and PD operations, different people were contacted, working for; inerals anagement Service (S), Canadian Association of Oilwell Drilling Contractors (CAODC), British Columbia Oil and Gas Commission (OGC), Weatherford Canada, ENFOR the petroleum industry s commitment to training and safety, Alberta energy & utilities board (EUB), and Exprosoft. Two well incidents with use of PD were revealed in Alberta. The objectives of this paper is to; learn and describe technology and procedures used for UBD and PD operations, identify and describe hazardous events during various steps of UBD and PD operations, perform accident investigations of relevant well control incidents, and establish formulas between incident causes and formation characteristics. The lack of data limited the possibility to develop a causal distribution and relations between causes and formation characteristics. In addition, no detailed UBD or PD well incident was found. The accident investigation performed is on a well incident during an OBD operation. Deviations from the master thesis main objectives, has been settled in co-operation with supervisor, arvin Rausand. This report consists of four parts; ) Introduction to the master thesis, ) An article on risk assessment of UBD and PD operations, ) Description of the data gathering, and a quantitative approach of blowout frequencies during UBD and PD operations, and 4) Conclusion and recommendations for further work. The preparatory report and progress report can be found in 6

10 appendix... The main objectives of the article in part two, are to a) give a technical description of UBD and PD operations, b) identify hazardous events during a PD operation, and c) perform an accident investigation with use of addon s matrix and the 0 strategies on an OBD well incident. A literature study has been carried out covered by relevant books, articles, Internet cites and by attending a PD course held by Statoil. Data collection has mainly been gathered by contacting relevant companies, authorities and persons. In addition to this, searches on the Intrenet has been made. The master thesis has been performed over a period of 0 weeks. The main limitations during this thesis has been; the availability of relevant data, and finding relevant literature. 7

11 Part azard identification and SAFOP analysis of a PD connection 8

12 Risk Assessment of Underbalanced and anaged Pressure Drilling Operations ari Oma Engevik ay, 007 Abstract Since 990 underbalanced and managed pressure drilling have become increasingly used alternatives to conventional overbalanced drilling. The new techniques provide several advantages, but the blowout risk during these operations is yet not fully understood. The main objective of this article is to evaluate the risk during underbalanced and managed pressure drilling operations. With use of a continuous circulation system during a managed pressure drilling connection, the safe operability analysis revealed the blind ram as the most critical component. The continuous circulation system is a fairly new, and the operation requires special personnel. Communication, clear responsibilities, and good procedures are of great importance in order to prevent unwanted situations or to mitigate the consequences. addon s matrix in combination with addon s ten strategies, gives a detailed accident description and provides risk reducing measures to prevent future accidents. The method covers all socio-technical aspects, and does not require hands-on experience. In formations containing potential gas pockets; detailed pre-hazard analysis of the geotechnical properties of the specific area should be performed, equipment capable of detecting the gas pockets as early as possible should be utilized, and alternative drilling technologies should be considered. Introduction According to studies made by the American Petroleum Institute (API) and the inerals anagement Service (S), 5% to % of all remaining undeveloped reservoirs are not drillable using conventional overbalanced drilling, OBD, methods. This is due to increased likelihood of well control problems such as differential sticking, lost circulation, kicks, and blowouts []. In addition, many depleted wells which still contain petroleum reserves could be utilized with alternative technologies to OBD. The challenge to the industry is to seek an efficient method to drill and develop these reservoirs in a manner that is no less safe than the overbalanced drilling method. With the right use, UBD and PD may [4]; eliminate or minimize formation damage minimize well costs by; - increasing the rate of penetration - extending the bit life - drilling in formations with small drilling windows - avoiding fluid loss - minimizing differential sticking - reducing the drill time

13 increase safety during drilling operations The Underbalanced Drilling Sub-Committee [9] did in 994 define UBD; "When the hydrostatic head of a drilling fluid is intentionally designed to be lower than the pressure of the formation being drilled, the operation will be considered underbalanced drilling. The hydrostatic head of the drilling fluid may be naturally less than the formation pressure or it can be induced. The induced state may be created by adding natural gas, nitrogen, or air to the liquid phase of the drilling fluid. Whether induced or natural, this may result in an influx of formation fluids which must be circulated from the well and controlled at surface." [] The International Association of Drilling Contractors, IADC, subcommittee define managed pressure drilling, PD, as; "An adaptive drilling process used to precisely control the annular pressure profile throughout the wellbore. The objectives are to ascertain the downhole pressure environment limits and to manage the annular hydraulic pressure profile accordingly" [7, ]. UBD and PD are used globally to drill new wells and to deepen or side-track from existing well bores [44]. UBD is as much a completion technology as it is a drilling technology []. During UBD and PD the bottom hole pressure is lower than during OBD. In conventional OBD, well control is performed by controlling the density of the drill-fluid. Because of the significant difference in friction and static pressure during OBD operations, friction pressure does not specifically influence the bottom hole pressure. The pressure at the top of the mud columns is at atmospheric pressure and does not contribute to regulate the bottom hole pressure. As opposed to conventional rotary drilling, UBD and PD utilize surface pressure during the operations. The bottom hole pressure is controlled by a back-pressure choke which allows the use of lighter drill fluids. In UBD and PD there are three ways to control the bottom hole pressure. It is done by controlling; the top pressure, the friction pressure (when fluid is circulated), and the static mud weight pressure. UBD and PD utilize relatively light fluids with low static pressure and the circulated flow friction will have a greater impact during these operations. The two main differences between UBD and PD operations are the bottomhole pressure and the influx of formation fluid. In UBD operations, the bottomhole pressure is below the reservoir pore pressure as in contrast to PD operations where the bottom hole pressure is slightly above or equal to the reservoir pore pressure. Because the bottom hole pressure during UBD operations are lower than the pore pressure, influx of formation fluid is induced into the wellbore. In PD operations influx of formation fluid is an unwanted situation. It is important to understand the risk during operations and be aware of potential dangers in order to prevent unwanted events from occurring and mitigate potential consequences. UBD and PD technologies are utilized on a world wide basis. This makes it important to understand the risk these operations contribute to human, environment, and assets. Safe operability, SAFOP, analysis evaluates procedures and operational sequences in order to identify hazards and causes of existing or planned operations. The method has its origin in the hazard and operability, AZOP, analysis developed in 96. SAFOP is suitable for detailed assessment and preliminary assessment. During examination of the operation, the operation procedures are divided into various steps. Relevant guide-words are further applied to the steps in order to reveal deviations from the design intent. The result of the analysis is usually a list of preventive actions in order to improve operations and procedures. By analyzing accidents that have occurred during UBD and PD operations, the risk during these operations can be better understood and precautions can be taken. The main objective of this article is to evaluate the risk during UBD and PD operations. This is accomplished by collecting possible accident data during UBD and PD operations, identify hazards related to a PD operation, and by performing an accident investigation based on an accident investigation report of a well incident. The hazard analysis is made on a connection with use of PD. The method used is a SAFOP analysis. The system consists of a continuous circulation system, CCS. The main focus of the analysis has been on the pressure chamber utilized during the operation. To collect information of accidents related to UBD and PD operations, authorities in the U.S., Norway, and Canada were contacted. Two accidents has been revealed related to PD operations, but

14 no reports of the accidents were found. The accident investigation is performed on a well drilled with use of OBD technology. This paper consists of three different parts. The first gives a technical description of UBD and PD operations. In the second part a SAFOP is performed on a PD connection operation, performed with use of CCS. The last part concerns accident investigation methods of UBD and PD operations. An accident investigation is performed on a well incident during an OBD operation. The accident investigation is performed with use of addon s matrix and addon s 0 strategies to prevent harmful energy of getting in contact with individuals or objects. Underbalanced Drilling Figure illustrates the different bottom hole pressures with use of a low or high density drill fluid, and with use of a low density drill fluid with top side pressure. We note that the top side pressure makes it possible to use light density drill fluids to achieve the wanted bottom hole pressure. By utilizing lighter density fluids, it is possible to drill sections with narrower drilling windows. Figure : Illustration of bottom hole pressure during OBD and UBD operations During OBD operations, the bottom hole pressure should be below the formations fracture pressure and above the pore pressure, see figure. If the pressure exceeds the fracture pressure the formation will start cracking and drill fluid will be lost to the formation. In a worst case scenario the loss of drill fluid can lead to a kick or even a blowout. If the pressure goes below the pore pressure, influx of formation fluid to the wellbore will occur. In UBD operations the bottom hole pressure is below the pore pressure and influx of formation fluid is a normal situation. owever if the bottom hole pressure drops too much the invasion of formation fluid may exceed the platforms capacity to handle it, or the hole may even collapse, see figure. Because the bottom hole pressure in UBD operations is below the pore pressure the probability of exceeding the fracture pressure is of a lower probability than in an OBD operation. In UBD operations influx of formation fluid is a normal situations and kicks are therefor defined different for OBD and UBD operations. According to the American Petroleum Institute (API) a kick during UBD operations are defined when the system is designed in a manner where it is not capable of handling the formation pressure or flow rate that is experienced. This can be a result of engineering errors, poor choke control or formation characteristics [6]. There are basically 4 different methods to drill UB related to the drill fluids used [];. Drilling mud (flow drilling); uses liquid mud where no gas is added. The mud can either be water based mud or oil based mud. It is a homogeneous liquid and incompressible with constant den-

15 Figure : Pressure margins in OBD and UBD operations adapted from [] sity. The liquid may however become compressible if it is mixed with formation hydrocarbon in the annulus of the well. With use of drilling mud, mud is pumped through the drill string as in conventional drilling. This kind of technology is limited to few particular cases of high formation pressure. It is used in formation where the pressure is rather high and the liquid is light enough to provide the desired UB conditions [].. Gaseated fluid; can either consist of a mixture of liquid and gas, or gas with liquid mist. - ixture of liquid and gas. Gas is entrained in liquid mud which makes it lighter. The gas used can be; nitrogen, natural gas, air, and exhaust gas. The liquid can be water or oil based. Gasified mud can be introduced in two manners; surface mixing (introduced into the top of the drill string) or downhole mixing (introduced through parasite pipe string or parasite casing). This technology is used to drill in formations with low hydrostatic pressure. - Gas with liquid mist (wet gas). Basically gas drilling with injection of very small quantities of liquid in the gas stream. Typical mist systems have <,5% liquid content. ist flow is injected in the drill string and runs down the drill pipe and up the annulus. iquid mist is introduced to assist in; cleaning the face of the drill bit, and lift very small and powered particles, like cutting surrounding the bit, through the annulus.. Stable foam; uses a homogeneous emulsion generated by mixing liquid gas and surfactant, an emulsifying agent. The gas used in this process is normally nitrogen, but other gases might also be utilized. Typical foams systems range from 55% to 97,5% gas. With use of stable foam, foam is generated at the surface and introduced to the top of the drill string. 4. Gas-air drilling system; uses dry gas. The use of air and natural gas for drilling in tight sandstone began over 0 years ago in the Arkoma Basin of western Arkansas and eastern Oklahoma []. In an gas-air drilling system dry gas is used as a medium. The gas utilized might be air, nitrogen, natural gas, and exhaust gas. When drilling with air or gas, the gas is compressed downhole through the drill string. When formation fluids are mixed with the dry gas at the bottom of the well gas returns through annulus as a mist flow where small liquid droplets are suspended in the gas like a spry. Gas drilling is probably the most used UBD method world wide []. The introduction and circulation of light fluids during an UBD operation can be done in three different ways; Drill string injection; the medium is run through the drill string and up the annulus. Parasite pipe string; during casing a separate injection string is implemented in the cement. In these cases the drill fluid is introduced through the parasite string and flows up the annulus. Parasite casing (only in vertical wells); separate " injection-annulus" which makes is possible to insert fluid into the annulus while drilling. The fluid runs down the " injection-annulus" and up the annulus. 4

16 . UBD Equipment UBD operation can be conducted using a conventional drilling rig, or as a rig-less operation []. UBD operations may vary in equipment, fluid, procedures and purpose. Common for all UBD operations are; the drilling operations are performed with an UB pressure ratio, the wellbore at the top of the well is sealed around the drill string while drilling and tripping, and the surface equipment is designed to remove formation fluid from the well and working area. UBD equipment systems are composed of all systems required to safely allow drilling ahead in geological formations with pressure at surface and under varying rig and well conditions. These systems include: the rig circulating equipment, the drill string, drill string non return valves, surface blowout preventer (BOP), control devices (rotating or non-rotating) independent of the BOP, choke and kill lines, UBD flow lines, choke manifolds, hydraulic control systems, UBD separators, flare lines, flare stacks and flare pits and other auxiliary equipment. The primary functions of these systems are to contain well fluids and pressures within a design envelope in a closed loop system, provide means to add fluid to the wellbore, and allow controlled volumes to be withdrawn from the wellbore [44]. There are different layouts and equipment used depending of fluid in use and the drilling site. Figure an example of a UBD systems flow loop is given. The system can be divided into a well system and a surface separation package system. Figure : Illustration of a UBD system The surface separation package includes separators, pumps, mud processing area and rig pits. The amount of separators may vary some. In this example the system is designed with one st stage and a nd stage separator, able to handle four phase fluid. In the st stage separator high pressure gas is separated. ow pressure gas is extracted in the nd stage separator. From the nd stage separator oil and gas goes to a test separator where they are separated. The mud and solid is separated in the mud processing area. ud returns to the mud pit, before it once again is circulated into the well. In the well system drill fluid is introduced either through the drill string, a parasite string or a parasite casing. Drill fluid is mixed with formation fluid and flows back through the BOP stack to the ESD valve, the flow spool, the choke manifold before it enters the SSP system. 5

17 In UBD operations the top of the well is continuously pressurized and the drillstring has to rotate and move axially through the seal at the top of the well. A rotating diverter is used as a seal element in the annulus to allow rotation and movement of the drillstring. The rotating diverter is basically an annular BOP where the seal element is in constant contact with the rotating drill string and rotates together with the string [, 6, 44]. There are basically two different rotating diverters [, 6]; Rotating Control ead, RC; uses the elasticity of the rubber element with added energy from the well pressure, to maintain the seal around the drill string. It is a low pressure diverter, designed to rotate with drill pipe and used mainly in air drilling. Rotating Blowout Preventer, RBOP; rotating annular preventer designed to rotate with pipe and seal on both pipe and kelly while allowing upward and downward movement of the pipe. It is energized by hydraulic pressure. Emergency Shutdown Valve refers to a remotely controlled, full opening valve that is installed on the flow line usually as near the BOP stack as possible [44]... UBD surface equipment The surface equipment during UBD operations may vary from use of simple rotating control device with a combination of all or some of the UBD equipment listed below [5,, 0, 4]; Rotating Control Device RCD; maintains a dynamic seal on the annulus enabling chokes to control the annular pressure at the surface while drilling proceeds. Downstream choke-manifold system; choke and choke manifold Atmospheric or pressurized separation system including downstream fluid-separation package -phase or 4-phase separation system Geological sampler Emergency shutdown system Alarm system Chemical injection unit; added to the circulation system. ay include corrosion inhibitors, hydrate suppressors, foam inhibitors, emulsion breakers, inhibitors of S embitterment [] Evacuation of gas, oil, water and mud cuttings Pressure relief systems and unloading, and hydrocarbon disposal facilities in cases of emergency ud pits in order to re-use mud ud pumps etering devices Flowlines The surface part of the circulation system treats the evacuated fluid, separate and disposes the drill cuttings, separate the produced formation fluids and drilling fluids, and pumps the drilling fluid to the top of the injection system and into the well. 6

18 .. UBD subsurface equipment As mentioned earlier in section, there are three ways to inject fluid during UBD operations; through the drill string, a parasite string or a parasite casing. The downhole equipment in UBD consists of the following elements []; Drill string Bottom hole assembly of the drill string String and wellbore isolation valves particular to the UB operations Drill string There exist two categories of UBD drill strings which are; A conventional jointed drill string which has a full drilling rig scale, or A small sized drill string or coiled tubing which respectively is methods for slim hole drilling and through tubing drilling. Bottom hole assembly The bottomhole assembly with use of liquid based drilling mud is the same as in OBD, consisting of; drill bit, steer-able motors in cases with direction drilling, measure while dilling and logging while drilling packages. With use of other medium in the drill fluid special logging and measuring equipment needs to be used because of difficulties transmitting information as incompressible mud pulses through the drill string. A possible solution to this problem is to use low frequency electromagnetic signals which runs through the geological formations. String and wellbore isolation valves particular to UB operations particular to UB operations are; String and wellbore isolation valves Downhole check valves in the drill string prevent backflow into the drill string, enable light fluids to be pumped through the drill string, and prevents gas from blowing back to the drill floor when pipe connections are made. Formation Isolation valves are designed to allow tripping in and tripping out of the wellbore. The wellbore is isolated from the formation pressure, and there is no pressure at the top of the string. ower Kelly cock is a manually operated quick closing block valve. It is normally used at the Kelly or below the top drive.. UBD Barriers According to NORSOK standard D-00, which regulates the minimum requirements to safety barriers during drilling and well operations on the Norwegian continental shelf, there should be two well barriers available during all well activities and operations [5]. This is a specialized drilling technique used where conditions are well known, predictable and risks can be managed. In UBD, the primary well control function of the mud column, is replaced by a combination of flow and pressure control. Bottom-hole pressure and return well flow are continuously measured and controlled by means of respectively, pressure while drilling (PWD) measurements and a closed-loop system. The complete UBD system comprises of the DP circulating system, a rotating control device (RCD), a UBD choke manifold (not the rig s well control choke manifold), a four-phase separator and a flare stack or flare pit. In addition, non-return valves (NRV s) are installed in the BA and drill string to prevent flow up the DP. The rig s BOP s are still considered secondary well control equipment and contingency plans to return to an overbalanced condition must be in place under certain predefined conditions or operational problems. Automated systems are also available that allow a fairly constant bottom hole pressure to be maintained while drilling and making up connections [44]. During conventional drilling the primary barrier is the mud column, and the secondary barrier is the BOP. In UBD operations the hydrostatic pressure is lower than the formation pressure, and thus not 7

19 working as a barrier. The primary barrier during UBD operations is made by a combination of flow and pressure control [5, 7]. The flow control system consists of; rotating control device, choke manifold, flowline, emergency shutdown valve (ESDV), and the surface separation system. In addition to this non-return valves (NRV) are installed in the bottom hole assembly and drill string to prevent flow up the drill pipe when a work string is run UB [5]. The secondary barrier during UBD operations is made by the BOP consisting of the wellhead connector and drilling BOP with kill/choke line valves.. Pro and Cons with use of UBD technology Reservoir criteria which favor an UBD process: Easily damaged reservoirs Fractured reservoirs Pressure Depleted reservoirs Poorly understood complex geological formations Prone to damage [4] ard rock [4] Drilling criteria which favor an UBD process: oss circulation potential. Severe pressure depletion. Poor ROP. echanical drilling problems. Potential for fluid trapping. Known fluid sensitivity issues. Contra-indications to an UBD process: Technical issues. Safety issues. ogistics. Depth/ocation constraints. Borehole stability issues. UBD provides advantages as to reduced formation damage, reduced lost circulation, increased rate of penetration, reduced drilling time, reduced differential sticking, extended bit life, get a rapid indication of productive reservoir zones, and it has the potential for dynamic flow testing while drilling which might make it a safer operation [5, 0, 4,, 4, ]. Under balanced drilling is however not appropriate in all formations e.g. in a lot of shale formations, salt formations, shattered coal sections, unconsolidated sections, in wellbore that are not stable or in wellbores with risk of high levels of sour gas on surface [4, 4, ]. Potential downsides and damage mechanisms associated with UBD are increased cost and safety concerns, mechanically induced wellbore damage, and difficulties in maintaining a continuously UB condition Bennion et al., 998 cited in [0] 8

20 4 anaged Pressure Drilling PD has evolved since the mid-sixties [], and is according to IADC subcommittee defined as; "adaptive drilling process used to precisely control the annular pressure profile throughout the wellbore. The objectives are to ascertain the downhole pressure environment limits and to manage the annular hydraulic pressure profile accordingly".[7, ] The primary difference between conventional drilling and PD is that in general PD relies upon a closed circulating system whereby flow and pressure in the wellbore can be controlled [44]. The level of planning and actual equipment requirements for PD depends on the specific technique, whether the application of the technology is for drilling enabling, reservoir damage reduction or reservoir characterization; whether hydrocarbons are present in the section being drilled, and in the case of drilling in the reservoir section, whether the intent is to produce hydrocarbons or not, the complexity and risk level associated with the section being drilled and finally, whether the well is onshore or offshore and deepwater or shallow water [44]. PD is a form of drilling which allows greater and more precise wellbore pressure control than conventional drilling. The technology is suitable for wells with narrow margins. [7,, 5] The fluids used are non-compressible and as opposed to UBD, PD does not invite influx of hydrocarbons. The technology exploits the opportunity to drill in a effective overbalanced state and makes it possible to join pipes without interrupting circulation. [5, 4] The mud weight used will be lower than for the conventional mud weight and a secondary choke or frictional pressure will be applied on surface to create a combined annular pressure profile withing the well. [8] Compared with UBD PD is better suited for drilling operations in severely depleted reservoirs where there is a small margin between formation fracture and hole stability. [8] PD provides advantages as to [, 8, 4]; Deeper open holes Deeper, fewer, or smaller casings Fewer ud Density Changes to TD ess NPT Enhanced control of the well Control of formation gas flow rates Improved well control procedures inimized risk of circulation losses and stuck pipe Increased ROP Avoid fluid invasion and fraction Reduced drilling time as potential to be a more reliable operation No influx of formation fluids Reduced chances of hydrate plugs forming at seabed Extended bit life 9

21 4. PD Technology There two categories of PD;. Reactive when PD technology is used on a well with conventional casing set points and fluid programs.. Proactive the well is special designed for the PD operation. Casing, fluids and open-hole program takes fully advantage of the PD opportunities In addition to these two categories there exist variations of the PD technology. In arine environments there are said to be four main variations of PD. The four variants each containing several under groups representing some differences e.g. variations in equipment [5,, 7]; Constant Bottomhole ole Pressure - e.g.continuous circulation system (CCS), dynamic annular pressure control (DAPC), low density drilling fluid (with choke valve for back pressure control), and Secondary annulus circulation using a mud with varying density. Pressurized ud Cap Drilling (PCD) - e.g. ow riser return system (RRS), and Dual Gradient (DG) - e.g. Gas lift in riser (GIR), equivalent circulating density reduction tool (ECDRT), and secondary annulus circulation. SE or Returns Flow Control Where constant bottom hole pressure, PCD and SE are the most commonly applied methods. The dual gradient drilling (DGD) technique used in deepwater drilling is the result of a joint industry project s effort to develop a practical solution to the problems associated with dynamic overpressure on the formations due to the long column of mud in the riser between seafloor and rig floor. In a conventional offshore drilling operation, mud is circulated down the drill string, through the bit and back up to the rig floor through a riser. The exposed formations see an equivalent circulating pressure that includes frictional pressure and the hydrostatic pressure equal to the entire mud column from bit to surface. In a normally pressured formation, its pore pressure is generally equal to a column of seawater and therefore, the pressure it sees during drilling operations is the difference between the hydrostatic pressure of the mud column and a column of seawater. While this may not be a problem in shallow water, it is a real concern in deep water and often prevents reaching target reservoirs. The use of DGD may enable reaching targeted TD with fewer, larger-diameter casing strings. The equipment required to create a dual-gradient condition is a pump with intake for the mud at the seabed and discharges it to the rig s mud handling system at surface. The pump mechanically isolates the mud return line from the intake line (wellbore annulus) and maintains the annulus pressure equal to the seawater s hydrostatic pressure, thereby creating the dual (seawater/mud) pressure gradient on the annulus side of the well. Note: the technique can be applied with or without a riser [44]. ud Cap Drilling This is a drilling technique that can be applied when a well is experiencing total dynamic mud losses to a thief zone at or near the bottom of a section and it is not safe and/or practical to drill completely blind. owever, no reservoir fluid flow to surface is intended. Drilling fluid (usually water), is pumped down the drill pipe. A higher density fluid is also pumped down the annulus at a controlled rate to overcome hydrocarbon migration. All of the pumped fluid, produced fluid and the cuttings are pumped into the fractures. It is the safest method for drilling sour reservoirs with a loss zone above, because there are no returns to surface. There are two types of mud cap drilling techniques: Floating mud cap - Annular fluid density is high enough to force fluid and cuttings into loss zone. This requires large volume of mud materials and is generally used in an open system, when a rotating control device is not available. Pressurized mud cap - Utilizes annular pressure and fluid column, to divert drill fluid and drilled cuttings into the 0

22 loss zone. This allows lower density annular fluid (nitrogen gas can also be used in highly depleted sour gas zones) to be used and annular injection rate to be optimized. Annular pressure provides direct indication of what is happening down-hole; therefore, less fluid is lost to formation. Viscosifiers can be added to slow gas migration up the annulus. A rotating control device is a minimum requirement for pressurized mud cap drilling. Continuous Circulation Systems The fluid circulation system is designed such that the dynamic pressure profile in the wellbore is maintained during the drilling phase, including connections. ow ead Drilling The low head drilling (D) technique is where the hydrostatic head of the wellbore fluid column is reduced to be either in balance or slightly greater than the formation pressure thus not planning to induce hydrocarbons or formation fluids into the wellbore. This can be accomplished using either a non-weighted low-density fluid or a gasified fluid. In addition, techniques (manual and automatic) are also available that allow drilling with an UB equivalent mud weight while maintaining balance or predetermined overbalance by use of flow control devices. [44] 4. PD Equipment The surface equipment used in PD operations may vary from just a rotating control device tied into the flowlines, to include one or more of the equipment mentioned below; Choke which controls the back-pressure during the drilling operation, may be manually or automatically controlled Surface separation package able to handle unwanted influx The Rotating Control Device RCD; maintains a dynamic seal on the annulus enabling chokes to control the annular pressure at the surface while drilling proceeds [0]. There exist three types of RCD systems [7];. Passive systems; depends on the friction fit between the drill pipe and the rotating pack-off and well bore pressure to affect the seal. Active systems; uses a hydraulic system to seal around the drill pipe. ybrid system; uses a combination of passive elements and active elements and hydraulic closing system. RCD usually consist of three components [5]; - Body with flow line outlet flange - Bearing assembly with a Stripper Rubber able to stripping drill pipe and tool joints - Clamp or latch in order to connect and secure the bearing assembly and stripper rubber assembly to the bowl In addition to this the PD system consists of auxiliary components as ESD system, pumps, data systems etc. 4. PD Safety Because of PD uses a closed pressure-controlled system it has a more sensitive kick detection and is better suited to control kicks [7, 4, 7]. The pressure differential across the RCD s Bearing and Stripper Rubber Assembly are modest making PD operations with use of RCD an operation with good reliability. [] training seal failures mud in system

23 ballooning effects Access to chromium [7] Should have a technological control device during PD in PT it is not a demand, but for a human to be intensed focus for several days is hard. PD will likely improve the well control capabilities, combined with predictive modeling. PD will probably require a smaller team and be done more quickly and to a lower cost than an UBD operation [7]. ud cannot be considered as a barrier during PD operations [7]. On installations consisting of subsea BOP with marine riser and telescoping slip-joints, the slip-joint with typically be the weakest link in the riser system relative to pressure containment [5]. Better prepared for invasion of influx than conventional drilling technology. [5] If the the riser and choke system in a "closed loop" PD operation is filled with gas, a fast and efficient down hole response is challenging. This problem is handled by CC PD operations [8] 5 anaged Pressure Drilling PD has evolved since the mid-sixties [], and is according to IADC subcommittee defined as; "adaptive drilling process used to precisely control the annular pressure profile throughout the wellbore. The objectives are to ascertain the downhole pressure environment limits and to manage the annular hydraulic pressure profile accordingly".[7, ] PD is a form of drilling which allows greater and more precise wellbore pressure control than conventional drilling. The technology is suitable for wells with narrow margins. [7,, 5] The fluids used are non-compressible and as opposed to UBD, PD does not invite influx of hydrocarbons. The technology exploits the opportunity to drill in a effective overbalanced state and makes it possible to join pipes without interrupting circulation. [5, 4] The mud weight used will be lower than for the conventional mud weight and a secondary choke or frictional pressure will be applied on surface to create a combined annular pressure profile withing the well. [8] Compared with UBD PD is better suited for drilling operations in severely depleted reservoirs where there is a small margin between formation fracture and hole stability. [8] PD provides advantages as to [, 8, 4]; Deeper open holes Deeper, fewer, or smaller casings Fewer ud Density Changes to TD ess NPT Enhanced control of the well Control of formation gas flow rates Improved well control procedures inimized risk of circulation losses and stuck pipe Increased ROP Avoid fluid invasion and fraction Reduced drilling time as potential to be a more reliable operation