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Collaborating Authors
Central North Sea
Dumbarton Field, UKCS: Rapid Redevelopment of a Complex, Mature North Sea Asset Using New Rotary-Steerable and Geosteering Technologies
John, Ukpe Jeremiah (Schlumberger) | Stewart, Andrew A. (Maersk Oil North Sea UK Ltd) | Tribe, Ian (Schlumberger) | Greiss, Rita (Schlumberger) | Bourgeois, Daniel Joseph (Schlumberger) | Melville, Kenneth (Schlumberger) | Ferguson, Emily (Maersk Oil North Sea UK Ltd)
Abstract The Dumbarton Field, operated by Maersk Oil North Sea in Block 15/20 has a number of drilling and well placement challenges, which hampered development during the 80's and 90's when operated by the previous owner. These include formation instability, directional-drilling control issues and thin complex reservoirs which are poorly imaged on seismic. Reservoir overburden is fast drilling formations with hard stringers. The field pore-pressure gradient is at 9.07ppg EMW but mud density needed for wellbore stability is greater than 11.6ppg. This resultant high overbalance and other issues such as hole cleaning, complex directional profile, ECD management at high ROPs, can lead to inefficient motor drilling. The soft formations also create limitations for push-the-bit rotary steerable systems to deliver the required directional performance to land wells. To overcome these drilling challenges a new point-the-bit, rotary steerable system with a high dogleg capability has been utilised for successful landing of these wells into reservoir sections without need for pilot holes or mechanical sidetracks. Additionally a new LWD tool that allows monitoring of the distance and direction to formation boundaries up to 15 ft away from the wellbore has been used to proactively guide the wells along the thin oil reservoir units/sands. These tools also enabled the wells to be placed as close to the reservoir roof shales as possible to maximize stand-off from the waterleg and hence increase overall oil recovery. Distance and direction to boundary data displays are intuitive to interpretation allowing better geosteering decisions without compromising ROP and drilling efficiency. Within six months six wells were delivered including three sidetracks (One top hole and two horizontal sections). All wells penetrated more reservoir sand than prognosed and all were drilled faster than prognosed. Initial production testing was higher than expectation. Introduction This paper uses a case study to highlight the benefits of using Point the bit RSS, the latest LWD tool technologies and process for redevelopment of an otherwise impossible matured field. The case is the Dumbarton development project, which is a redevelopement of the BP Donan field by Maersk Oil UK. The filed was discovered by 15/20a-4 well in 1987 and appraised by a 15/20a-6 well (a deviated well drilled from the 15/20a-4 surface loacation) in 1990. Production from these two wells commence in 1992 untill 1997; at this point a total of 15.3 mmstb oil was produced. In 1995 there was a planned Phase 2 development consisting of replacing the two producers, which were becoming increasing wet, with a drier, horizontal wells to be drilled to the west of 15/20a-6 well. Five attempts (wells 15/20b-12, 12Z, 12Y, 12X, 1W) were made, but all were understood to have been considered at that time to be disappointing. The previous operator then decided to abandon any further development enhancements and to continue producing the existing wells until it ceased to be profitable. As a result the field was abandoned in 1997 at this point the final water cut was 71%.
- Geology > Geological Subdiscipline > Stratigraphy (0.69)
- Geology > Geological Subdiscipline > Geomechanics (0.54)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.37)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Fladen Ground Spur > Block 15/20b > Donan Field > Dumbarton Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Fladen Ground Spur > Block 15/20a > Donan Field > Dumbarton Field (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > Block 2/8 > Valhall Field > Tor Formation (0.99)
- (13 more...)
Development, Testing, and Field Deployment of a Hydraulically Expanded Solid Liner Hanger in a Casing Directionally Drilled Well in Norway
Bourassa, Kevin Arthur (ConocoPhillips) | Husby, Tove (ConocoPhillips Co) | Watts, Rick Deuane (ConocoPhillips Co) | Hazel, Paul Roderic (Read Well Services Ltd.) | Nussbaum, Chris (Read Well Services Ltd.) | Wood, Peter (Read Well Services Ltd.)
Abstract When ConocoPhillips (COP) decided to conduct Casing Directional Drilling (CDD) operations from a platform in the Norwegian Sector of the North Sea, the well design required that the drilled in 7–3/4" production casing string be converted into a liner prior to completing the well. There was a challenge in identifying a liner hanger system that would be suitable for CDD operations; that did not require a running tool; would maintain a full internal diameter (ID) for running and retrieving bottom hole assemblies (BHA's) and would act as a barrier against gas migration over the service life of the well. Expandable technology(1) was identified as a potential solution. Once a service provider was identified, a basis of design was established and testing began. The end result after eighteen (18) months of work was a successful field deployment of a 7–3/4" liner hanger that was drilled in from surface; successfully expanded into 10–3/4" casing; had a load capability of over 440,000 lbs (200 metric tons or MT) and a 5,000 psi (345 bar) gas tight seal qualified to ISO 14310:V0. This paper will describe the development, testing and actual deployment that took place between December 2006 and January 2007. Introduction In the well under consideration, COP wanted to casing directionally drill a long string of 7–3/4" casing to the top of the reservoir, cement the casing shoe, then convert the long string into a liner and retrieve the upper section of 7–3/4" casing. This conversion was required for four main reasons: the completion & stimulation design; future sidetrack operations; concerns regarding Equivalent Circulating Density (ECD) while drilling the 6–1/2" reservoir section; and space constraints within the wellhead system. Conventional liner applications typically involve making up a liner with an integral liner top packer and a specific running tool; attaching the liner to the drill string; then running it into a pre-drilled hole section prior to cementing. However, it was planned to drill this well with casing as the drill string; with the casing string extending from Total Depth (TD) back to the rig floor. Bottom hole assemblies (BHA's) would have to be run through the liner hanger (LH) on wireline; the liner hanger would be picked up at surface and needed to be drilled in to approximately 4,800 ft after which it would need to be set and provide a gas tight seal. Therefore a conventional liner hanger assembly was not believed to be a viable solution. It was also important to ensure that the LH could be set at any depth in the well in the event the casing could not reach TD during CDD operations. As it happened, the casing did reach TD and although the LH was positioned across a 10–3/4" casing collar, this had no detrimental affect on the setting of the LH.
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/7 > Greater Ekofisk Field > Eldfisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/7 > Greater Ekofisk Field > Eldfisk Field > Hod Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/7 > Greater Ekofisk Field > Eldfisk Field > Ekofisk Formation (0.99)
- Well Drilling > Drillstring Design (1.00)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Casing and Cementing > Casing design (1.00)
- (3 more...)
A Case History of Casing Directional Drilling in the Norwegian Sector of the North Sea
Bourassa, Kevin Arthur (ConocoPhillips) | Husby, Tove (ConocoPhillips Co) | Watts, Rick Deuane (ConocoPhillips Co) | Oveson, Dale (TESCO Research & Development) | Warren, Tommy M. (Tesco Corporation) | Bjorneli, Hans Magnus (Schlumberger) | Lesso, William George (Schlumberger) | Sunde, Frode (Schlumberger)
Abstract In January 2007, ConocoPhillips completed what is believed to be the first well directionally drilled with casing using wireline retrievable bottom hole assemblies from an offshore installation. ConocoPhillips has considerable experience with this technology in reducing drilling days on predominately vertical land wells in South Texas. It was desired to determine if the same benefit could be realized in the offshore environment; where directional drilling is required. A candidate development well was identified in Norway on the ConocoPhillips operated Eldfisk Bravo platform that could benefit from advantages seen with Casing while Drilling. Two land based tests were conducted to confirm the ability to conduct casing directional drilling in wells similar to those expected in Norway. Simultaneously, a detailed plan for drilling the well in Norway was developed. Two production casing strings (10 ¾-in. and 7 ¾-in.) were successfully drilled directionally through the overburden section on the Eldfisk well. The well had a complex 3-dimensional well path with inclination up to 60°. All running and retrievals of the BHAs was planned to be done with wireline and a purpose-built traction winch system rated to a working load of 40,000 lbs. Once the 7 ¾-in. production casing was cemented, the casing string was converted to a production liner with an expandable liner hanger and the upper section of 7 ¾-in. was retrieved. In all, 10,968 ft of the 13,600 ft well was directionally drilled with casing. Introduction ConocoPhillips has actively used Casing while Drilling (CwD) technology in more than 150 wells in South Texas since 2001. This technology has contributed to solving downhole problems associated with lost circulation and sloughing shales. 1,2 It has been a factor in providing excellent hole conditions. From a well control standpoint, CwD technology is advantageous in that it provides the ability to circulate the entire time that the BHA is being pulled or run into the well with wireline. This leaves the pipe at or very near to bottom during the drilling process; even with the BHA out of the well. All of these factors have allowed COP to significantly reduce trouble time and overall days required to drill wells in areas of South Texas. While there have been some directional CwD applications on land, the technology was not proven in the offshore environment. An obvious question for COP was "Can the benefits seen using CwD technology on onshore vertical wells be realized in the offshore environment where directional drilling is required?" In reviewing the global portfolio of drilling operations, a candidate well, the 2/7B-16A well was identified in the Eldfisk Field on the Eldfisk Bravo platform (Figure 1) located in the Norwegian Sector of the North Sea. The Eldfisk Field produces from the Cretaceous Chalk and has been in production since 1979. Eldfisk Bravo is a relatively small, 20 slot production platform set in 1978 with an integral platform drilling rig. An almost constant re-development program is required to maintain the field production rate. Drilling issues related to this work include complicated slot recovery work, drilling problems such as lost returns near the top of the reservoir, high levels of drill gas while drilling the Miocene and Eocene intervals in the overburden and difficult hole conditions commonly experienced during tripping operations while drilling production wells.
- North America > United States > Texas (1.00)
- Europe > Norway > North Sea > Central North Sea (0.44)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/7 > Greater Ekofisk Field > Eldfisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/7 > Greater Ekofisk Field > Eldfisk Field > Hod Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/7 > Greater Ekofisk Field > Eldfisk Field > Ekofisk Formation (0.99)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Operations > Running and setting casing (1.00)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Drilling > Casing and Cementing > Casing design (1.00)
Automatic Real-Time Drilling Supervision, Simulation, 3D Visualization, and Diagnosis on Ekofisk
Rommetveit, Rolv (SINTEF Petroleum Research) | Bjorkevoll, Knut Steinar (SINTEF Petroleum Research) | Odegaard, Sven Inge (Hitech Drilling Services Ltd.) | Herbert, Mike C. (ConocoPhillips Norge) | Halsey, George Wesley (SINTEF Petroleum Research)
Abstract eDrilling is a new and innovative system for real time drilling simulation, 3D visualization and control from a remote drilling expert centre. The concept uses all available real time drilling data (surface and downhole) in combination with real time modeling to monitor and optimize the drilling process. This information is used to visualize the wellbore in 3D in real time. eDrilling has been implemented in an Onshore Drilling Center in Norway. The system is composed of the following elements, some of which are unique and ground-breaking:An advanced and fast Integrated Drilling Simulator which is capable to model the different drilling sub-processes dynamically, and also the interaction between these sub-processes in real time. Automatic quality check and corrections of drilling data; making them suitable for processing by computer models Real time supervision methodology for the drilling process using time based drilling data as well as drilling models / the integrated drilling simulator Methodology for diagnosis of the drilling state and conditions. This is obtained from comparing model predictions with measured data. Advisory technology for more optimal drilling. A Virtual Wellbore, with advanced visualization of the downhole process. Data flow and computer infrastructure eDrilling has been implemented in an Onshore Drilling Center on Ekofisk in Norway. The system has been used on several drilling operations. Experiences from its use will be summarized and presented. This paper has main focus on utilization of an advanced flow model for real time supervision and control of ECD and ECD related effects. Introduction The southwestern part of the Norwegian continental shelf, called the Ekofisk Area, contains eleven major chalk fields. The Ekofisk field is the first and main discovery, discovered in 1969 and put on production in 1972. The fractured chalk reservoir lies at a depth of 9500 - 10700 feet and is approximately 11.2 × 5.4 kilometers in area, with production coming from two zones Ekofisk and Tor. It is one of the North Sea Giants with a STOIIP of 7 MMBO! Currently there are 4 fields in production, 4 fields abandoned with current production around 325,000 bbls per day of oil and 350 scf of gas per day. Water injection is currently used to maintain reservoir pressure, and approximately 900,000 bbls of water are injected each day. There are over 150 wells that have been drilled on the Ekofisk, and due to the complexity of the field, with its numerous faults and fracture networks, location of injected water, and pressure uncertainties, all result in well placement challenges.
- North America > United States (1.00)
- Europe > Norway > North Sea > Central North Sea (0.54)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
Abstract The conventional drilling approach of employing a drillstring and bottomhole assembly with bit for drilling purposes and eventually running a casing string includes several tripping operations that leave the wellbore open for extended periods of time as an alternative to drilling-with-casing operations where the bottomhole assembly is attached to the casing. This eliminates additional drillstring tripping as drilling and running casing are performed simultaneously. This type of application reduces the number of string trips needed to complete a section, thus saving operational time and associated costs. As the diameter of a casing is larger than a drillstring, this method generally increases the Equivalent Circulating Density (ECD) as pressure losses increase owing to the reduction of the open hole and casing string annulus area. Casing directional drilling operations provide a much narrower drilling window with regards to restrictions in the annulus thus increasing the chances of reaching fracture pressure compared with conventional drillstring operations. To negate the resultant increase in ECD, the rheological profile of the drilling fluid must be designed appropriately. This paper discusses a unique oil-based drilling fluid system weighted with treated micronized barite slurry (TMBS) that has more recently been developed and used successfully in the Eldfisk field of the Greater Ekofisk area, Norway. The drilling fluid system provides low viscosity and a relatively low flat rheology, reduced torque values, and superior sag stability, thus delivering a fluid of low ECD contribution, low-pressure peaks, very effective hydraulics performance and static stability. These exceptional fluid characteristics make the system an excellent solution for drilling sections where the difference between pore pressure and fracture pressure is narrow. This was particularly so in this case where the stability of the fluid from sag potential was crucial for the improved success of the drilling-with-casing operation. Any solids sag onto the latching tools or bottomhole assembly (BHA) with the casing could have caused interference. The system had been used before for differing hole conditions including managed-pressure drilling and extended-reach wells, in high-temperature, high-pressure (HTHP) wells, and now with competence in a casing directional drilling operation. Introduction With this being the first offshore directional drilling work there is limited experience to draw from. To support the deviated drilling with casing operations comprehensive engineering studies were performed to qualify acceptable drilling parameters. This Eldfisk well on the 2/7B platform was the first offshore deviated drilling-with-casing operation ever performed (Fig. 1). The wellbore inclination was increased to a maximum of 69 degrees at the total depth of the second section while drilling with casing. The main purpose of drilling with casing operations is that drilling and casing running operations are conducted simultaneously. By operating in this manner the wellbore is secured at all times from less significant instabilities, and the drillstring tripping time and pipe handling time is dramatically reduced. This is because the BHA is being pulled on wireline for reconfiguration or bit change. The BHA latches into a purposefully designed sleeve in the casing shoe joint. When drilling with casing, the casing is rotated slowly, that is with a rotation per minute rate of less than 30. This rotation assists by "smearing" the drill cuttings into the formation of the wellbore. It helps provide an effective barrier that has been known to prevent the loss of drilling fluid into the formation. This can be quite contrary to conventional drilling operations with a drillstring where the drillstring can aggressively bounce at the wall resulting in the removal of the filter cake in permeable formations. As a consequence the formation could be exposed to the drilling fluid and its higher hydrostatic pressure causing fracturing or a reduction in the formation integrity.
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/7 > Greater Ekofisk Field > Eldfisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/7 > Greater Ekofisk Field > Eldfisk Field > Hod Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/7 > Greater Ekofisk Field > Eldfisk Field > Ekofisk Formation (0.99)
Abstract In areas with shallow water flow, additional casing strings are normally set to seal off the water-bearing zone. While drilling the first well in Fram East in the North Sea, the operator used a shallow 20-in. surface casing, but this measure increased well costs and caused a number of later limitations in the well construction process. To avoid these complications in other Fram East wells, the operator searched for alternative solutions. It selected a cement design with properties compensating for the loss of hydrostatic pressure and thereby preventing the water flowing. The service company carried out extensive designing and testing of the cement formulations. A major challenge was qualifying the final design for a full-scale field test. A third-party laboratory qualified the cement system, using a modified setup of the gas migration equipment. The results were promising. A dedicated cutting injection well was chosen for the field test. The successful test allowed planning the remaining wells using the new system with projected savings of more than USD 20 million. This paper will describe the development of the solution, the design, and testing of the cement formulation, and the full-scale field test performed. Introduction The main objective of the cement is to provide a hydraulic seal across the various permeable formations; zonal isolation is compromised when formation fluids such as water are allowed to enter the annulus. During and after the placement, the cement column and the other fluids in the wellbore or annulus exert a hydrostatic pressure that initially must be greater than the formation pore pressure to prevent invasion of formation fluids. However, as the cement hydrates, the cement slurry becomes self-supporting and the hydrostatic pressure exerted by the slurry decreases. When the hydrostatic pressure decreases below the formation pore pressure, formation fluids such as water can enter the annulus, potentially leading to water flow through the cement matrix, which leads to the loss of hydraulic isolation. Challenges identification Fluid migration after cement is placed downhole is a well known topic and has been studied for quite a while (Beirute and Chung, 1990; Stewart and Schouten, 1986; and Sutton and Ravi, 1989.) For water invasion to occur, the following conditions must be present: The pressure in the annulus drops below the formation pressure (which always occurs during the setting of the cement). Several mechanisms have been postulated to study this phenomenon. Dehydration of the cement: This phenomenon is caused by insufficient fluid-loss control. If it is severe enough, cement solids will bridge the annulus and prevent transmission of the hydrostatic pressure from the still-fluid cement column above the bridge. If the hydrostatic pressure falls below existing formation pressure below the bridge, formation fluids can enter the wellbore.
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Casing and Cementing > Cement formulation (chemistry, properties) (1.00)
- Well Drilling > Casing and Cementing > Casing design (1.00)
- Reservoir Description and Dynamics (1.00)
Abstract As an increasing number of 6000-ft plus deepwater developments come on stream in the Gulf of Mexico (GoM), project economics dictate that fewer subsurface drill centers be used to develop these fields. This in turn requires longer step-out wells, pushing kickoff points higher up the wellbore, often occurring within extensive salt bodies. Salt drilling is still a relatively new practice and presents operators with many drilling challenges that are still not totally understood. Adding a directional component to drilling through salt not only magnifies the issues of traditional salt drilling, but introduces new challenges that require different approaches to ensure successful delivery. This paper will discuss the challenges faced and the lessons learned by two major deepwater GoM operators along with the directional service company in drilling directionally through the salt. Together, these companies have drilled over 100,000-ft of salt in the GoM and are considered pioneers in deepwater salt drilling. They have encountered and managed many of the challenges that extend past the traditional predrill and real-time directional issues, into the post drilling phase with issues such as casing and cement design for managing salt loading and ensuring long term wellbore viability. This paper presents several case studies that investigate and discuss directional drilling through salt, comparing variables such as hole size, bottomhole assembly (BHA) configuration, under-reamer selection, wellbore trajectory and directional control. The importance of geomechanics in the predrill planning of these directional salt wells is also discussed, and its link to casing design and cementing issues will be examined. The paper concludes by identifying critical areas for success in drilling directionally through salt, and will attempt to identify current technical drilling limits for pushing this envelope even further. Introduction The Gulf of Mexico (GoM) is well known for its extensive subsurface salt structures that have aided in trapping much of the hydrocarbons found here. Figure 1 illustrates the extent of the salt coverage, in relation to multiple deepwater discovery wells. As deepwater exploration successes progress into the development drilling phase, and with the increasingly recognized potential of the GoM's Lower Tertiary trend, (much of the 33,000sq mi trend is covered by a thick salt canopy, Figure 2) the requirement for deepwater wells to penetrate salt have become almost mandatory. More information on GoM salt coverage is presented in the OCS Report 2007–021 Deepwater Gulf of Mexico (2007). Over the next several years, successful and efficient drilling of salt will play an increasingly major role in achieving many of the area's deepwater drilling objectives. In order to meet this challenge, the ability to directionally drill through salt and to understand and manage the issues this introduces will be a key factor for deepwater operators. This paper will explore in further detail, the drivers for directional drilling in salt, the challenges that it introduces and will discuss the enabling and emerging technology required to execute this relatively new aspect of deepwater drilling. Three case studies from different deepwater GoM operators will be reviewed, and the lessons and recommendations derived from these presented. The paper will draw upon these and other GoM salt drilling experiences to formulate a comprehensive package of the requirements for the planning and drilling directionally through salt.
- North America > Mexico (1.00)
- North America > United States > Texas (0.67)
- Geophysics > Borehole Geophysics (0.93)
- Geophysics > Seismic Surveying > Seismic Processing (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.67)
- Europe > Norway > North Sea > Central North Sea > Utsira High > PL 338C > Block 16/1 > Gemini Prospect > Hugin Formation (0.99)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Green Canyon > Block 727 > Tonga Field (0.98)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Green Canyon > Block 727 > Tahiti Field (0.98)
- (20 more...)
Abstract This paper describes some of the key drilling technologies used in the well construction of long reach and extended reach wells as part of initial field development of 6 reservoirs from the Ringhorne platform. Difficult drilling conditions exist due to extended drilling targets through highly reactive shales and require Non-Aqueous Fluid (NAF) drilling fluids at elevated mud weights. The Ringhorne development was made possible by using a combination of latest drilling technologies for extended reach drilling and an adequately designed rig to ensure success. In order to mitigate the resultant tight drilling margins, a number of optimizations impacting well designs and field operating practices were implemented. Among these have been latest applications of the newest Rotary Steerable tools, refined directional surveying and anti-collision practices, use of hole openers and underreamers to mitigate tight drilling margins, surveillance practices, use of low viscosity drilling muds, lost returns response practices, Logging While Drilling (LWD) advancements for geo-steering and casing installation techniques. The Ringhorne development is a project example where more of a project's risk is being carried in the well construction phase since the development is on the current outer edge of drilling technology. The structured well planning, design and review processes will be summarized and explained to illustrate how these were used both to balance technology application and communicate risks to stakeholders. Introduction Ringhorne field development represents a world class offshore field development. The field is located in the Norwegian part of North Sea and the platform location was selected such that multiple independent reservoirs could be developed. The platform is located 160 km offshore from Stavanger, Norway in 128.5 meters of water. Field development is utilizing the processing infrastructure currently available in the Greater Balder Area (Figure 1). The platform rig was designed to drill to multiple remote accumulations within 8 Kilometers (km) from the platform surface location with target True Vertical Depths (TVD) ranging from 1700 m to 2000 m (Figure 2). The separate reservoirs were insufficiently sized to support a stand-alone development by themselves. The reservoir targets from Ringhorne are Eocene, Paleocene and Jurassic aged (Figure 3). The Eocene Balder formation is shallowest at about 1700m TVD. Paleocene reservoir zones located between the Eocene and Cretaceous Chalk correspond to the Ty, Heimdal and Hermod formations. The depositional environment of both Paleocene and Eocene reservoirs are deepwater gravity flow deposits. Originally these were massive sand deposits but due to post depositional soft sediment deformations, these sands remobilized into overlying shales resulting in interbedded sands from centimeters to meters in thickness. Historically, these reservoirs have been very difficult to map. Below the Cretaceous Chalk, the Jurassic Statfjord reservoirs include marginal marine deposits near the top while lower parts are fluvial in nature. Statfjord sequences are characterized by coarse and medium grained sandstones overlain by gray mudstones with minor coals. The pressure and temperature gradient are normal. All reservoirs are of high quality with porosities of 25–35%, darcy-plus permeabilities and crude qualities of 23–24 deg API in Paleocene/Eocene and 39 deg API in Jurassic. The sands are unconsolidated requiring sand control. Ringhorne platform was installed in August, 2002; field development began October, 2002 and is currently ongoing. To date, 19 wells have been installed with the most challenging well being 25/8 C-12 (E5) reaching a total depth of 7558m MD at 1809m TVD (horizontal to vertical throw of 3.8). The horizontal displacement vs. vertical depth ratios for development wells have ranged from 1.5 to nearly 4. (Figure 4).
- Phanerozoic > Cenozoic > Paleogene > Eocene (1.00)
- Phanerozoic > Cenozoic > Paleogene > Paleocene (0.85)
- Geology > Sedimentary Geology > Depositional Environment (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.45)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (0.68)
- Europe > Norway > North Sea > Central North Sea > Utsira High > PL 169E > Block 25/8-11 > Balder Field > Statfjord Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Utsira High > PL 027 > Block 25/8-11 > Balder Field > Statfjord Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 103 > Block 25/8 > Jotun Field > Ty Formation (0.99)
- (32 more...)
Abstract This paper presents a case study of the detailed planning and BHA modeling used to improve performance in drilling deviated 24 inch hole sections and its implication to the on-going Ringhorne extended-reach-drilling (ERD) program. The paper describes the planning; modeling and results of the 24 inch drilling performance achieved in the longest extended reach well drilled to date in the Ringhorne Development, Offshore Norway. Ringhorne wells usually kick-off below the 26 inch conductor in 17–1/2 inch hole building angle from vertical to 65 degrees where 13–3/8 inch surface casing is typically set. This is not the case for the development with extended well targets where it came necessary to upsize the casing program with 18–5/8 inch surface casing. This requires a 24 inch deviated hole to be drilled from approximately 300 meters measured depth (mMD) to 70 degrees by 1000 mMD with casing point at approximately 1600 mMD to enable drilling to the reservoir targets at 1700 - 2000 meters true vertical depth (mTVD). The first 24 inch section was drilled using a 17–1/2″ polycrystalline diamond (PDC) bit, rotary steerable system (RSS) and PDC hole-opener. Severe vibration problems were experienced while drilling through the Utsira sands near the base of the section causing a rotary steerable tool failure. This led to loss of angle and slightly earlier casing point than planned. The next 24 inch section was drilled using a two-run strategy including a 17–1/2 inch RSS to total depth (TD) before picking up a 24 inch hole-opener in a separate run. The first hole-opener run twisted off above the bottomhole-assembly (BHA) while drilling the massive Utsira sandstone and three subsequent hole opening runs were pulled due to poor performance resulting in a tapered casing string to be set. Because of the poor BHA performance and the associated drilling problems, the operator and the service company conducted an extensive analysis of offset drilling performance followed by a thorough modeling study to ensure success in drilling the long reach 25/8 C-12 (C-12) well from the platform. Due to the complexity of the well, no deviation from the well path could be tolerated and the casing shoe had to reach the planned depth. Time and depth based data, formation information and vibration measurements from the offset wells were evaluated using analytical software. These results were used to analyze various BHA's for stability. This investigation led to the development of a stable BHA configuration and selection of optimum bit properties, recommendation for parameter combinations and response plans for the formations encountered. A plan was developed that focused on drilling practices and parameter adjustments according to the formation. The result was a significant reduction of vibration that enabled the rig crew to successfully drill the 24 inch section following the well path and run the 18–5/8 inch casing to planned TD without incident. History - Introduction Ringhorne Development Project is located in the southern part of the Norwegian North Sea, 160 kilometers offshore in 128.5 meters of water. Reservoir access is provided from a steel jacket platform housing 24 well slots (Figure 1). The platform location was selected such that multiple independent reservoirs could be developed within an 8 kilometer radius of the platform structure (Figure 2). The Ringhorne platform was installed in August, 2002; drilling began October, 2002 and is currently on going. To date, 19 wells have been drilled and completed with the most challenging ERD well being C-12 reaching a total depth of 7558 mMD at 1809 mTVD with a ratio of horizontal to vertical throw of 3.8 (from the mud line). The horizontal displacement to vertical depth ratios for Ringhorne development wells have ranged from 1.5 to 4. Shallow reservoir depths (1700 – 2000 mTVD) make well profile planning critical in order to reach production targets. Inclination is built from the start of the top hole section at 300 mMD reaching 65 – 70 degrees inclination at 1000 mMD then holding angle to casing depth at approximately 1600 mMD. The well path is critical in the top section, normally drilled as a 17–1/2 inch hole, but it has to be drilled as a 24 inch section for the extended wells to the outer boundary of the field.
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Greater Peace River High Basin > Tangent Field (0.99)
- Europe > Norway > North Sea > Central North Sea > Utsira High > PL 169E > Block 25/8-11 > Balder Field > Statfjord Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Utsira High > PL 027 > Block 25/8-11 > Balder Field > Statfjord Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 046 > Utsira Formation (0.99)
Abstract This paper discusses the design and testing of 10 ¾-in. and 7 5/8-in. casing directional drilling equipment and procedures that ConocoPhillips plans to use on a mature North Sea asset. ConocoPhillips has worked with Tesco Corp. and Schlumberger in building the tools necessary to complete this task. These include: downhole casing drilling tools, under-reamers, positive displacement motors, MWD tools, rotary steerable systems (RSS), and high capacity winches for this work. Testing this equipment in commercial North Sea operations is prohibitively expensive. Therefore, tests were conducted at a drilling test facility near Cameron, Texas, where operations were conducted over a wide range of rotating speed, weight and flow conditions as well as inclinations from vertical to horizontal. High frequency surface and downhole drilling mechanics measurements were made that allowed for diagnosing problems and improving the systems. Introduction Successful application of casing drilling in the Lobo trend in South Texas is well documented in terms of preventing lost circulation, eliminating stuck pipe and ultimately improving efficiency.[1,2] In addition to over 110 straight wells drilled to date in South Texas, two wells were drilled in 2004 which combined a rotary steerable and casing drilling system to demonstrate that directional casing drilling was possible. These were not exhaustive tests but they did prove that combining rotary steerable with 7-in. pipe for casing drilling was a viable option. The key question is, "Can the straight hole benefits realized in the Lobo Field be transferred to directional drilling in an offshore working environment"? The next step in casing drilling is to develop the tools and procedures to drill complex directional wells. With full directional capability, offshore development applications become possible. However, in order to make casing directional drilling a reality, significant technical challenges need to be overcome. Adopting this new drilling technology into a producing asset is a challenge beyond just the technical aspects. Implementing the technology may require rig/platform equipment modifications that impact production and the initial wells may take longer to drill as the learning curve develops. To reduce the risk associated with implementation, a wellbore profile similar in complexity (hole angle, build rate, depth) to a well to be drilled off of the Eldfisk B platform offshore Norway was drilled with 10 ¾-in. and 7 ¾-in. casing. The equipment used in these field trials included the same tools that would be used in Norwegian operations. This was done to mirror the activity that would be involved on the platform necessary to execute the project. Safety and training were also an integral part of the project. An initiative was started in February, 2005, to apply casing directional drilling for Eldfisk. Schlumberger and Tesco partnered with ConocoPhillips on this challenge in order to prove up the suggested solution and helped execute the two field trial tests that mirrored the wells to be drilled offshore. The Prize Casing drilling has demonstrated operational time savings of approximately 15% in straight hole applications as compared to normal drill pipe drilling. This benefit is also expected to apply to casing directional drilling in an offshore working environment. The comparison is based on normal operating times for each case. The expected bit rotating hours from drilling below the previous casing shoe until section TD is reached for casing drilling is sometimes more, but generally not more than 10% over that experienced with drill pipe. Eliminating the need to pick up drill pipe, condition the well, and trip out of the hole to run casing can save a substantial amount of time. Routine changes for bits, underreamers and MWD's will also provide a timesaving.
- Europe (1.00)
- North America > United States > Texas > Kleberg County (0.54)
- North America > United States > Texas > Milam County > Cameron (0.25)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Fulshear Field (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Lobo Field (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/7 > Greater Ekofisk Field > Eldfisk Field > Tor Formation (0.99)
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