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Well Drilling
Abstract Effective blowout preventer (BOP) requirements and well control policies are crucial in maintaining safe drilling and workover operations. These requirements/policies generally are tailored to the individual oil and gas operator's specific drilling environment. Changes in well profile, depth, temperature, pressure, hydrogen sulfide concentration, and safety margin may require changes in BOP equipment and well control. Saudi Aramco has recently revised their equipment requirements and well control policies in an effort to further optimize drilling safety and efficiency in the Kingdom of Saudi Arabia. This paper discusses changes in BOP stack arrangements, kill/ choke line requirements, replacement part criteria, elastomer application limits, and use of variable bore rams and shear blind rams. Also included are requirements for number of isolation barriers, pressure testing/maintenance, and minimum overbalance. A new tripping policy and shut-in procedure are also discussed, with the introduction of a new trip sheet and kill sheets. Specific well control policies are provided. Background and Introduction In 1994, Saudi Aramco resumed the Khuff gas development and Pre-Khuff exploration programs, which had been discontinued in the late 1980s. The associated activity level increased from one deep drilling rig in 1994 to twenty-two deep gas rigs at present. These gas wells range in total depth from 14,000' to 19,600' with bottom-hole temperatures of 300 to 350 degrees F. Bottom-hole pressures in some formations require as high as 162 pcf mud weight, while 90 to 100 pcf is typically needed to control the gas reservoirs. Shut-in wellhead pressure is approximately 6,000 psi. Hydrogen sulfide (H2S) concentrations in Khuff wells can reach 20% in some areas. The first Khuff gas horizontal well was drilled and completed in 1997. Thereafter, both horizontal and vertical wells have comprised the deep gas program. In 1998, two well control incidents occurred and prompted an in-depth operational review. As a result of this study and the continued emphasis on drilling deep gas, BOP and well control policies were revised. Additional revisions were also made as part of an ongoing optimization effort. BOP Stack All standard BOP stacks were reviewed to ensure the equipment complied with accepted industry practices and provided proper well control safety for all drilling/workover applications. Major stack design considerations were evaluated. Among these were pressure rating, component selection and arrangement. 1) Pressure Rating Pressure ratings of the standard BOP stacks are 10,000 psi (high pressure), 5000 psi (medium pressure), and 3000 psi (low pressure) as shown in Figures 1 through 5. Selection of the proper stack is determined by the ‘worst case’ pressure containment, which occurs when all the drilling fluid has been evacuated from the annulus and only low-density formation fluid remains. Working pressure rating of the BOP and burst rating of the casing strings (with a 1.33 minimum design factor) were re-verified for all pressure applications to ensure a shut-in capacity greater than the worst pressure condition that could be imposed during a well control incident. No changes were required in the BOP pressure ratings or pressure applications. 2) Component Selection Main components of the standard BOP stacks include the annular preventer, fixed pipe rams, variable bore rams (VBR), blind rams, shear blind rams (SBR) and drilling spool. Components are selected by the maximum anticipated surface pressure, wellhead temperature, and H2S concentration.
- Government > Regional Government > Asia Government > Middle East Government > Saudi Arabia Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Asia > Middle East > Qatar > Khuff Formation (0.99)
- Asia > Middle East > Qatar > Block 4 > Khuff Field > Khuff Formation (0.98)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Equipment > Well control equipment (1.00)
Abstract Well control has always been a very important issue in the oil and gas exploitation business, since it involves money savings, people safety and environment threatening. The advancement of the exploration frontiers from onshore to offshore fields, particularly, deep and ultra-deep waters, has increased even more the relevance of kick control and blowout prevention during drilling operations. Widely used drilling practices have been optimized and re-evaluated, so have new technologies been developed to handle specific issues related to deep water drilling operations, such as reliable and efficient well control practices. This effort has great importance to some countries like Brazil, which have most part of their oil and gas production (close to 75%)concentrated on offshore wells, about 70% of those reserves are located in deep waters. Regarding such scenario, this article presents a comprehensive and discussed literature review about well control in deep and ultra-deep waters, covering the evolution of the analytical and numerical kick models. A mathematical model has been developed to predict the pressure behavior insidethe annulus during a gas-kick circulation out of the well in deep water scenarios. Considerations regarding the effects of wellbore geometry, frictional pressure losses, influx expansion, and two-phase flow models havebeen implemented in the present model. The analysis of the effect of some important parameters in well control in the surface pressure, such as the pitgain, water depth, mud density and pump flow rate are presented. Introduction The exploitation in deepwater and the development of concepts related tothis activity has been changing a lot throughout the years. In the sixties, for example, the exploitation and the development of offshore fields used to berestricted to 150 ft water depth. Nowadays, depths up to 1,300 ft areconsidered as deep water and above 3,300 ft are considered as ultra-deepwater. Particularly in Brazil, about 75% from the national production come from theCampos basin, in the north coast of Rio de Janeiro, with more than 70% of thosereserves located in deep and ultra-deep waters. Deep water drilling in Brazil was stimulated by the discovery of the Albacora field, in1984, in a water depth that varies from 1,000 to 6,500 ft. In 1985, Marlimfield was discovered with the well RJS-219, in 2,750 ft water depth. In 1994, the Marlin-4 well (3,400 ft water depth) was completed and its production was started. In 1996, the giant field of Roncador was discovered, with water depths varying between 5000 and 10,000 ft. The brazilian record of water depth is the1-RJS-543 well, located at Roncador field, reached in November 1999 in a9,300ft water depth. In deep water drilling operations, an accurate control of all the drilling parameters, added to a detailed project and program are factors of extreme importance in the environmental, economic and security aspects. A permanent concern in these operations is the control of kicks and the prevention of blowouts. Literature Review The first mathematical model of kick circulation was proposed in1968. The model disregarded the friction pressure losses in theannulus, the slippage speed between the gas and the mud, with a uniform annulus capacity and the gas insolvable in the mud. The model of Ref. 4 incorporated the effect of friction pressure losses in the flow inside the annulus. Even though there was an improvement regarding the previous model, it presented results that did not match field data, properly.
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Marlim Field > Macae Formation (0.99)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Marlim Field > Lago Feia Formation (0.99)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Block P-36 > Roncador Field > Maastrichtian Formation (0.99)
- (2 more...)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Operations (1.00)
Abstract Designing a development drilling program for the Legendre Field required a systematic approach that incorporated the lessons learned during the exploration and appraisal drilling phase. A significant part of the planning endeavor focused on arriving at a geomechanical solution that would prevent many of the instabilities and lost circulation events from being repeated. Detailed image analysis for wellbore failure, and a systematic stress and rock strength analysis was performed to identify the optimal well trajectories and mud weights to successfully drill and complete the production wells. The results of this geomechanical analysis indicated that the stress state in the Legendre Field area is associated with a strike-slip stress regime. Horizontal wells drilled sub-parallel to the maximum principal stress are optimally oriented to ensure wellbore stability in the overburden, while using a lower mud weight within the reservoir reduces the risk of massive lost circulation. Introduction Developing a production program for any hydrocarbon field is a complicated process. In many cases, the most successful execution of a development plan involves an integrated approach between geologists, geophysicists, reservoir engineers and drilling/completion engineers, with each discipline contributing information that hopefully generates an accurate description of the reservoir to design a sound development program. There will always be risks; however, by integrating information from a multi-disciplinary team it is possible to assess these risks and build into the development program a mechanism for managing these risks. An important component of this multi-disciplinary approach to field development design involves constructing a geomechanical model for the asset. In the case of the Legendre Field, a geomechanical model was constructed to provide valuable information for identifying appropriate wellbore trajectories and to design an optimal mud program in order to reach the reservoir target and minimize drilling problems. The anticipated risks associated with drilling these development wells are wellbore stability and lost circulation through natural fractures and possibly faults. Quantifying the mechanical behavior of the natural fractures seen in the wells can be accomplished using the same geomechanical model. The objective of this paper is to illustrate how the analysis of geologic and engineering information from the exploration and appraisal wells in the Legendre field was used to build a geomechanical model, which was then used to design four development wells and one injection well. Geologic Setting and Structural Framework The Legendre Field is compartmentalized into the Legendre North and Legendre South Fields which are situated in the southeastern part of the Dampier Sub-basin of the offshore Carnarvon Basin of Western Australia, about 100 km north of Dampier (Fig. 1). Located on the continental shelf in water depths of 50 to 60 metres, the Legendre Field represents the most significant hydrocarbon accumulation along the Legendre Trend adjacent to the Rosemary Fault System. The Rosemary Fault System is one member of many NE-SW trending fault systems, presumed active up until the Early Cretaceous, which are predominately responsible for the hydrocarbon-bearing basins in the area. A more detailed description of the depositional and structural framework, depositional setting, and hydrocarbon generation of the Dampier Sub-basin can be found in Refs. 1–3.
- Geophysics > Seismic Surveying (0.68)
- Geophysics > Borehole Geophysics (0.68)
- Oceania > Australia > Western Australia > North West Shelf > Muderong Shale Formation (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Dampier Basin > WA-20-L > Legendre Field > Legendre South 2H Well (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Dampier Basin > WA-20-L > Legendre Field > Legendre North 3H Well (0.99)
- (12 more...)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- (2 more...)
Abstract In directional drilling, MWD technology is applied to transmit directional and petrophysical data from downhole. In combination with modern directional drilling tools such as rotary steerable systems, MWD technology has enabled the drilling of complex 3D well profiles precisely placed in the reservoir. However, even on these high-tech wells the drilling process itself is still controlled mainly using traditional surface acquired data such as hook load, ROP, RPM etc. The transmission and utilization of downhole drilling process data in addition to the surface logging data offer a not yet fully explored potential for drilling process optimization, since modern data acquisition technology close to the bit can provide not only more accurate data but also important additional parameters not available at the surface. Examples of value-adding downhole drilling process data are annulus pressure, weight-on-bit, drillstring bending, RPM, bit torque and dynamics diagnostics. Additional drilling process information on drilling hydraulics or drillstring friction can be obtained by feeding drilling engineering algorithms with downhole and surface acquired data. The paper provides an overview of the available downhole drilling process data and demonstrates with numerous case studies the value that these parameters add. Furthermore, the paper discusses factors constraining the use of the technology and gives an outlook on future developments in drilling process optimization utilizing real-time downhole data. Introduction Drilling optimization remains a key issue in the drilling industry due to the high drilling costs in today's challenging applications such as Extended Reach Drilling (ERD), designer profile wells, deepwater wells, drilling in depleted reservoirs etc. Over the past years, the drilling rig industry has made significant progress in introducing computer-based instrumentation, power-handling tools and automated equipment on the rigs to improve rigsite safety and to optimize the drilling process. The introduction of Local area networks (LAN) on the rig has improved the acquisition of data from surface sensors and information sharing on the rig. In parallel, downhole MWD technology has made progress in miniaturization of electronics, quality, range, and reliability of sensors, and the development of specific diagnostic techniques to describe the downhole environment. These sensors provide new sources of downhole information for the driller, previously trained on controlling the drilling process using only his rig dials. The purpose of this paper is to demonstrate how real-time downhole drilling process data, along with surface acquired data, can support the decision making progress on the rig to optimize the drilling process. Downhole Drilling Process Measurements and Applications The following provides a comprehensive overview of the drilling process measurements available in today's downhole Measurement-While-Drilling (MWD) systems. Case studies describe how the data are utilized at surface to overcome drilling related problems.
- Europe (1.00)
- North America > United States > Texas (0.47)
- Well Drilling > Drilling Operations > Drilling optimization (1.00)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Information Technology > Architecture > Real Time Systems (0.82)
- Information Technology > Artificial Intelligence (0.69)
- Information Technology > Communications > Networks (0.54)
Abstract Hardbanding materials are used to protect tool joint drillpipe against wearin drilling operations. Hardbanding shall resist wear in openhole conditions with a minimum damage to upper casing. Laying down drillpipe for hardbanding repair can significantly increase rig time and tubular costs. All hardbanding products applied for Sincor were wearing out completely after drilling 15,000ft in 50 hours in the reservoir. It was necessary to search for new hardbanding alternatives with an extended lifetime. A field evaluation program was designed to compare wear resistance of different commercial hardbanding materials and toevaluate new techniques for welding tungsten carbide pellets with alloyingwires and for testing of tungsten carbide spheres being laser applied. Hardbanding products were selected upon analysis of wear mechanisms occurring in drillpipe while drilling horizontal wells in Sincor. Wear resistance was monitored in terms of cumulative drilled footage until gauging complete wear ofhardbanding on tooljoints. One of the newly developed hardbanding products wasfinally selected as the best option after considering its superior wear resistance, minimum expected casing damage, and moderate cost. This is thefirst reported successful application of tungsten carbide pellets welded withina hard matrix provided by an alloy wire for hardbanding purposes. Introduction Wear of drillpipe is an important issue for drilling operations in Sincorarea. Wear increases operational cost due to repair of components, rig time tochange out worn down components, and lost of valuable tools. Wear of components has been reported in the tool joint drillpipes since start of operations.Hardbanding and repair cost for a 5,000-ft string can reach up to US$ 150,000 over the string lifetime. With this amount of money and time invested in wear control, high consideration was given to develop material specifications for requesting wear resistant materials. Other solutions implemented in Sincor toreduce drillstring wear are the following:Use of down-hole tools, i.e. Hydroclean drillpipe, for better hole cleaning and a consequently reduction of the backreaming while drilling horizontal sections. Optimization of drilling practices such as mud circulation, use of Hi-Vispills, and backreaming parameters. Use of mud additives, i.e. Ecolane solvent, and heating the mud to reducedrillstring friction. Use of several types of hardbanding materials. This work is aimed to find the most appropriated hardbanding material forprotecting drillpipes in openhole conditions. Minimum casing wear and environmental pollution due to chromium discharge within the drilling fluidswere identified as special concerns. Background Sincor is an operating oil company created in 1997 and it is comprised by Total Venezuela S.A., PDVSA Sincor S.A., and Statoil Sincor A.S. The company started operations in 1998 to exploit the Zuata reservoir located in the Orinoco Belt in Southeastern Venezuela. Reservoir is characterized by an 8-°APIheavy crude oil in unconsolidated sand with extensive shale bedding. Wells are drilled in clusters to minimize environmental impact. Each cluster has an average of 12 extended reach wells having an average horizontal section of 4,450-ft in length. Frequent backreaming is required for hole cleaning purposes. This combination of unconsolidated sand and repeated backreaming as depicted in Figure 1, are the primary causes for wear of drillstring components. Drillpipe is laid down when tooljoint outside diameter is lower than 6–3/8".
- North America > United States (0.69)
- South America > Venezuela > Orinoco Oil Belt (0.24)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.54)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.41)
- Well Drilling > Drillstring Design > Drill pipe selection (1.00)
- Well Drilling > Drilling Operations (1.00)
Abstract The complexity of petroleum wells has increased significantly during the past decade. Both inclination and horizontal departure are greater than before, leading to additional demands on well operations. Buckling of drillpipe and completion string is seen as a critical parameter. In this paper we review available buckling models and show applicable theory for practical well operations. Introduction During the last few years, well lengths are more than doubled. The consequence is often that offshore oil and gas fields can be drained from a small number of platforms. This demonstrates the significance directional drilling has on the recovery of hydrocarbons. To reach the desired targets, well friction is an important parameter to control. This has several practical consequences, such as the maximum wellbore inclination for drilling and completing a well and maximum bit force to avoid buckling of a slender bottomhole assembly. The extended use of coiled tubing in drilling, completion and well intervention, has led to the conclusion that pipe buckling is a critical parameter. The presented paper aims at addressing aspects of this. Reachable depth, force and torque are controlled by buoyed weight, curved-well effects and corkscrewing of the pipe. Helical buckling of drillpipe or workstring may eventually lead to lockup or excessive pipe stresses. Theory is presented that describe wellbore friction caused by helical buckling, pipe weight and wellbore curvature. An example well is analyzed.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
- Well Drilling > Drillstring Design (1.00)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
Abstract The bulk of Nigeria's oil and gas production come from the Niger Delta area of the country. The environment is generally susceptible to high salinity, which influences quick set in of external corrosion on metallic products. The surface casing of wells located mostly in the swamps of the Niger Delta are prone to external corrosion attack at the splash zone around the wellhead region. The effect of this corrosion ultimately results in loss of load bearing capacity of the wellhead when the severity is very high. At rig based well re-entry, collapse of the surface casing had occurred under the weight of the Blow Out Preventer (BOP) during its installation. Repair of such failure at the wellhead is mostly unplanned and can be expensive. The external corrosion at the wellhead region is influenced by the oxygenation of rainwater retained in the annular space between the conductor pipe and the surface casing. Similarly, the cement micro annulus that emanates behind the surface casing tend to retain some relatively small amount of water which invariably do cause an invisible, slow but steady development of corrosion on the surface casing. The proposed paper will proffer solutions to incidence of external corrosion on the surface casing with a view to enhancing production life, safety and reducing operating cost. Introduction Various degrees of surface casing pipe-body integrity loss occurring at the wellhead splash zone caused by external corrosion had often resulted in worst cases to:Wellhead collapse during the installation of the BOPs at Rig well re-entries. Exposure of the inner casing or the production casing, which could lead to escape of hydrocarbon. External corrosion phenomenon around the wellhead started manifesting during the decade of the 80's as a result of rainwater settling in the annulus of the conductor pipe and the surface casing. The oxygenated water then formed a ring of corrosion around the surface casing and in some bad cases the corrosion penetrated invisibly to 5ft below surface of micro annulus space in the casing/cement annulus (Fig. 1). Following the anomaly of surface casing loss of body integrity of 10–20% and disintegration, expensive remedial actions had been embarked upon to secure and reinstate the casing integrity of such affected wells. Early Years Solution The procedure adopted for remedial action involved:Engaging a rig on site. Securing the well by killing, recovery of the production tubing and safeguarding with cement plug prior to the repair job. Cutting off of the old wellhead. Exposure and removal of the corroded section of the surface casing. Welding on of a new pipe body and replacement of the wellhead. Re-cementing of the outer annulus. In order to stop the water retention in the annulus, a cement top-fill was done up to the top of the conductor. The top of the cement was built sloping outward to allow water to run off (Fig. 2). However, micro-annulus still develops behind the casing thereby letting in a relatively small amount of water that leads to invisible but slow corrosion. Causes due to collapse: With due recognition to all the good work put into casing design criteria especially on casing collapse, irregular external loss of body integrity as could be caused by corrosion has to be re-focused upon which this paper is not addressing.
Downhole Deployment Valve Addresses Problems Associated with Tripping Drill Pipe During Underbalanced Drilling Operations
Herbal, Steve (Pinnacle Operating Company, Inc.) | Grant, Rod (Pinnacle Operating Company, Inc.) | Grayson, Brian (Weatherford International Inc.) | Hosie, Dave (Weatherford International Inc.) | Cuthbertson, Bob (Weatherford International Inc.)
Abstract Underbalanced Drilling (UBD) is becoming more widely used and accepted because of the many benefits it provides such as:Limitations to the formation damage common in regular overbalanced drilling. Increased rates of penetration. Increased production rates and in some cases production while drilling which can provide early cash flow and enhance economics. However with these advantages come some drawbacks, the chief among which is the safety of the operation while tripping the drill pipe into and out of the well. Since the well is allowed to flow in traditional UBD operations a flowing or shut in pressure results in the well.Any significant pressure at surface requires that special precautions be taken during tripping operations to control formation pressure.Several techniques can be used among which are:Killing the well, this provides for safe tripping but can obviate the very reason for using UBD - formation damage can result. Flowing the well, this can lead to a dangerous situation if a sloughing formation forms a temporary bridge in the annulus. A Snubbing unit can be employed, this enhances safety but can add considerably to the operational cost. It is clear that a better and safer method is needed, since all the above carry disadvantages, and to this end a new method involving a downhole valve was conceived.In this approach a full opening valve which can be closed below the drill string while tripping, is deployed downhole below the "pipe light" depth and operated from surface by way of a hydraulic control bundle. This paper will review the concept of the Downhole Deployment Valve (DDV), its design and operation.The authors will go on to provide details of the first field trial of the a 7" 26lbs/ft full opening valve in a multilateral well which was drilled underbalanced in the James Lime play in East Texas/Northwest Louisiana. They will conclude that this device can provide major enhancement to a UBD operation without in any way compromising its advantages. Introduction Increased awareness of the degree of formation damage caused by fluid invasion into the reservoir during conventional overbalanced drilling techniques has resulted in a growing interest in the benefits offered by UBD.These techniques, though not necessarily suitable for all reservoirs, can have a considerable positive impact in such instances as:Depleted reservoirs where in-fill wells can be drilled with little or no damage. Highly permeable and fractured reservoirs where fluid invasion can be greatly limited and consequent degradation of permeability reduced or eliminated. Hard formations where greatly increased penetration rates can be achieved. However along with the many benefits offered by UBD techniques come some disadvantages, such as higher associated costs and increased perceived risk and safety issues.Perhaps the most significant such risk is during the normal process of tripping the drill string to change the bottomhole assembly (BHA).Since the formation is allowed to flow during UBD operations a surface pressure is ever present in the annulus which is controlled by a rotating control head.Once tripping begins and the pipe is being stripped through the wellhead, this pressure must be handled in some manner before a "pipe light" situation is reached.
- Well Drilling > Pressure Management > Underbalanced drilling (1.00)
- Well Drilling > Drilling Operations (1.00)
Abstract Underbalanced drilling (UBD) with jointed pipe has become routine in the UK sector of the southern North Sea and operators in the Norwegian sector are now introducing the same concept. Typically, the well is kept live during tripping and a rig-assist snubbing unit is employed to handle the drillpipe while pipe-light. Significant surface compressive loading is exerted on the pipe during the snubbing phase. The focus of this paper is two-fold. First we consider buckling of the drillpipe in the snubbing jack and on the drill floor when a static compressive load is applied. Thereafter, we analyze the behavior of ejected tubulars during well entry and exit under live well conditions. Introduction There are three tripping options available in UBD. If reservoir damage is not an issue, the well may be killed before pulling out of the hole and the drilling rig is used for tripping as in overbalanced drilling. A second option is to use a downhole deployment valve installed inside the drilling casing. With the drillpipe pulled above this valve, the device is closed and the pipe is tripped with the drilling rig in a conventional manner. The third option of rig-assist snubbing is currently the preferred method in the North Sea. Here the well is kept live at all times and the snubbing unit is used while tripping pipe-light. Refer to Appendix A for a review of terms that are relevant to rig-assist snubbing. Maximum compressive surface load on the drillstring is experienced when snubbing in the bottomhole assembly (BHA) and the first few joints of pipe. During normal operation of a rig-assist snubbing unit, the drillpipe may buckle in long unsupported intervals inside the jack unit itself. The greatest unsupported interval is between the snub slips on the traveling head and the active stripper blowout preventer (BOP). Typically, a telescoping tubing guide (buckling guide) is used to control the lateral deflection of the pipe should buckling occur. This paper presents useful equations for unsupported buckling and buckling inside the tubing guide. The theory is compared with the results from recent full-scale buckling tests. Also included in the paper is an analysis of the dynamic forces involved should the drillstring suddenly eject from the well. This situation may occur as a result of an operator error or equipment malfunction. Unsupported buckling In buckling we are concerned with the stability of the pipe. We need to ensure that the drillpipe is able to support the given compressive load without experiencing a sudden change in its configuration. Often the magnitude of compression associated with buckling is far below the yield load of the pipe. When the pipe is subjected to a compressive load in excess of its critical buckling load Fcr, the tubular suddenly becomes sharply curved instead of remaining straight.
- Europe > North Sea (0.74)
- North America > United States > Texas (0.46)
- Europe > United Kingdom > North Sea (0.44)
- (3 more...)
- Well Drilling > Pressure Management > Underbalanced drilling (1.00)
- Well Drilling > Drillstring Design > Drill pipe selection (1.00)
- Production and Well Operations > Well Intervention (1.00)
Abstract Underbalanced drilling (UBD) has gained strong momentum in recent years because of a number of advantages of the technology including reduced formation damage and minimized lost circulation. Due to the complex nature of water, oil, gas and solid multiphase flow in the UBD systems, numerous runs of sophisticated computer programs are required to draw the boundary of the safe gas-liquid rate envelope. It is highly desirable to have a simple and reliable procedure to perform optimum UBD designs. This paper describes an innovative procedure to delineate the boundary of the safe gas-liquid rate envelope for UBD flow rates. In developing the safe gas-liquid rate envelope, formation fluid pressure limits the upper bound of the flowing bottom hole pressure and wellbore collapse pressure serves the lower bound of the circulation-break bottom hole pressure. The envelope is closed with boundaries determined by fluid's cutting carrying capacity and wellbore washout criteria. Detailed procedure for the development of the safe gas-liquid rate envelope using a spreadsheet program is described in the paper. A successful field UBD case is reviewed and compared with the safe gas-liquid rate envelope. This work provides drilling engineers and drilling supervisors an easy-to-use approach to designing and modifying gas and liquid injection rates in UBD. The safe gas-liquid rate envelope can also be used for evaluating feasibility of UBD under given geological conditions. Introduction The drilling operations where the drilling fluid pressures in the borehole are intentionally maintained to be less than the pore pressure in the formation rock in the open-hole section is called Underbalanced drilling (UBD). The low borehole pressures are achieved by using lightened drilling fluids. The light fluids used in UBD are usually air, gas, foam, and aerated water. However, un-aerated oil, water, even weighted mud can be used for UBD in areas where formation pore pressure gradients are higher than hydrostatic pressure gradient of water. The advantages of UBD include increased penetration rate, minimized lost circulation, prolonged bit life, minimized differential sticking, improved formation evaluation, reduced formation damage (reduced stimulation requirements), earlier oil production, larger wellbore available to production in offshore, and environmental benefits. The disadvantages of UBD include personnel and equipment safety issues, handling of produced formation fluids, and wellbore damages (washout, collapse, and cuttings accumulation in the borehole). Good designs are the key to the successful UBD operations. Sever wellbore damages and failures can result from poor UBD designs and/or deviation of the actual drilling programs from the original designs. The combination of mud flow rate and gas injection rate plays a very important role in preventing failure of the UBD. If the combination is chosen such that it gives too high bottom hole pressures, the degree of underbalance is reduced and the benefit of the UBD will be marginal. On the other hand, if the combination is chosen such that it gives too low bottom hole pressures, wellbore damage problem will fail the UBD operation. Currently computer simulators have been used in drilling industry to design liquid and gas injection rate combinations for UBD. Both steady state and transient simulators are available. But the procedure is tedious and not transparent. It is difficult to make an optimum UBD design that balances all the aspects. A graphical method with methodology transparency is highly desirable for drilling engineers who are in charge of UBD designs and UBD field supervisions.
- Asia (0.93)
- North America > United States > Texas (0.28)
- Well Drilling > Pressure Management > Underbalanced drilling (1.00)
- Well Drilling > Drilling Operations (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- (2 more...)