Areepetta Mannil, A. (Schlumberger) | Lobov, M. A. (Schlumberger) | Buyanov, M. (Schlumberger) | Chang, K. (Schlumberger) | Silva, L. (Schlumberger) | Kazakov, A. (Lukoil-Nizhnevolzhskneft) | Eliseev, D. (Lukoil-Nizhnevolzhskneft) | Zemchikhin, A. (Lukoil-Nizhnevolzhskneft)
Korchagina and Filanovskoe oil fields in the north Caspian Sea have many extended- and mega-reach wells that uses inflow control device (ICD) screen completions with sliding sleeves. This completion technique empowers the operator with the ability to shut off unwanted water/gas breakthrough and allows for more control of injection or inflow with unlimited number of stages or zones. This paper describes a new verified workflow to successfully intervene these wells and manipulate (open/close) these sliding sleeves using coiled tubing (CT).
It has proven challenging to shift these sliding sleeves using conventional methods with CT owing to the limitation of available weight on bit (WOB) at the toe end of those extended-reach wells, even when using large-size CT strings. The new proposed workflow uses a well tractor operated in tandem with a hydraulic shifting tool to generate the required shifting force downhole. The bottomhole assembly (BHA) also includes a novel flow control sub, assembled between the shifting tool and the tractor, with the ability to control the flow to selectively activate the tractor, the shifting tool, or both, based on surface commands by manipulating pump rate.
To verify the methodology, a realistic well scenario was simulated at a test site by installing two ICD screens with sliding sleeves at the end of a 1,000-ft-long horizontal flow loop. The sleeves on each ICD screen required approximately 4,000 lbf set-down force to open. The available WOB at the end of horizontal loop with 2-in. CT was only 1,000 lbf; applying more than 1,000 lbf set-down load could have detrimental effects, including CT buckling. The 3⅞-in. OD well tractor used for the job was able to generate 6,000 lbf of pulling force downhole, which was more than enough to shift the sleeves open. Both sleeves were successfully opened by tractoring down while maintaining both the tractor and the shifting tool in the on position, which was achieved by manipulating the flow control sub using pump rate cycles. Both sleeves were then successfully closed, one after the other, by pulling with the CT with the tractor turned off while maintaining the shifting tool in the on position, again achieved by manipulating the flow control sub. Live downhole pressure and force measurements were key in confirming proper functionality of the tractor and identifying different tool modes. Having real-time data is also crucial for proper depth correlation using casing collar locators (CCL) or gamma ray measurements to ensure activating the correct sleeves.
This marks the first time that a workflow was verified on the use of pull force generated by a well tractor to manipulate completion accessories in extended-reach well interventions using CT. The technology, preparation, results, and prospects of implementation are discussed in this paper.
For many years, Saudi Aramco has searched for a way to replace the practice of drilling out the DV’s and Shoe Track with a tricone bit, followed by a polycrystalline diamond cutter (PDC) bit to drill the new formation to the next casing point. Many bit manufacturers have conducted trials to overcome the challenge, with limited success. This paper discusses a successful, single-run technology to drill out and continue drilling using only a PDC bit.
Investigations of the root causes of failure and erratic performance led to extensive review of bit design and drilling practices, but fail to overcome the single-run challenge posed by cutter wear and damage experienced during the drill out.
Recently developed shear cap technology provides a means of installing high-grade tungsten carbide caps on the PDC cutters. The caps protect the cutters during the drill out, and then wear away to expose the cutters in pristine condition for drilling the formation.
The shear cap technology has been tested extensively and optimized using various bottom-hole assemblies. The result has been a considerable breakthrough in the success rate for drilling the formation section, accompanied by a time reduction that has resulted in huge savings in offshore oil drilling operations.
The standard PDC bits fitted with the protective technology are successfully providing a one-trip capability, saving a round trip to change the bit and achieving a 100% success rate in drilling to the next the casing point. When drilling in the casing, the tungsten carbide shearing caps are effectively mitigating the cutter damage typically experienced when drilling out the shoe track. Drilling performance in the formation and the ability to efficiently drill the full section, demonstrates the undamaged condition of the cutters when the bit exits the casing. Overcoming the longstanding efficiency challenge of drilling both shoe track and formation in a single run is being achieved with the novel technology’s ability to enable optimal formation drilling by protecting cutters during the shoe drill out.
Crane, Davon (Continental Resources) | Zhang, Youhe (Schlumberger) | Douglas, Charles (Schlumberger) | Song, Huimin (Schlumberger) | Gan, Xiaoge (Schlumberger) | Lin, Zhijun (Schlumberger) | Mueller, Levi (Schlumberger) | Skoff, Greg (Schlumberger) | Self, Jordan (Schlumberger) | Krough, Bradley (Schlumberger)
Most traditional polycrystalline diamond compact (PDC) cutting elements have a flat polycrystalline diamond table at the end of cylindrically shaped tungsten carbide body. During drilling, the flat diamond table engages the formation and shears the rock layer by layer. A new ridge-shaped diamond cutting element (RDE) has a similar cylindrical tungsten carbide base; however, the diamond table is shaped like a saddle with an elongated ridge running through the center of the diamond table and normal to the cutter axis. The intended cutting portion, the "ridge," engages the formation to fracture and shear the rock at the same time. The design intent was to create a unique cutting element that could combine the crush action of a traditional roller cone insert and the shearing action of a conventional PDC cutter. The new cutting elements were tested in the laboratory against standard flat PDC cutters in a rock-cutting evaluation, and later the new elements were applied to PDC bits and run under real drilling conditions.
The laboratory rock-scrape tests indicated that the new cutting element not only enables the cutter to efficiently shear formation in the same way as a conventional PDC cutter, but also delivers a crushing action similar to a roller cone insert. Preliminary results indicated a reduction of roughly 40% in both cutting force and vertical force on the new ridged diamond element cutters (RDE) over a conventional PDC cutter. Similar findings were also observed during the rock-shearing test on a vertical turret lathe (VTL). Subsequent field tests in multiple areas in North America have produced faster rates of penetration (ROP) in most of the cases. The trials indicate that the new cutting element is efficient at removing rock, and a bit equipped with these elements requires less mechanical specific energy (MSE) during drilling than does a bit with a conventional PDC cutter. In addition, the reduced cutting forces reduces bit torque and thus improves the drilling tools’ life and the bit directional performance. Field data has proven this technology improves drilling performance in terms of ROP and footage over the current PDC bits fitted with traditional flat PDC cutters.
A significant percentage of all ESP failures are electrical failures and this becomes even more noteworthy in harsh, high temperature applications such as Steam Assisted Gravity Drainage (SAGD). For this reason, it is extremely important to continue the enhancement of ESP motor technologies that are specifically designed to address the challenging and unique SAGD environments that include wide bottom hole temperature ranges, abrasives and gas rich fluids. Through experience and testing, it has been learned that for these types of applications it imperative to design not only to a high temperature limit, but also to withstand extreme temperature cycles experienced on steam injection facility shutdown. A combination of historic evidence with controlled laboratory evidence yielded improvement areas for a new high-temperature ESP motor development. The new high ultra-temperature motor breaks paradigms and opens a new generation of motors that looks towards above 300 C downhole temperatures. This paper will review the performance of the motor at Suncor's Firebag SAGD field where 92 units have been installed since January 2015 in bottom hole (BHT) temperatures reaching 240 C. Description of the laboratory qualification, major design characteristics and field results will also be discussed on the paper.
Failure of umbilicals such as leakage or blockage in the hydraulic lines can be a challenge during operation of subsea infrastructures such as Christmas trees. These failures cause loss of redundancy and, in worst case, the operator will lose control of important valve functions on the trees. In that instance, the operator is forced to shut down production to perform costly umbilical repair or replacement prior to resuming operation.
As an alternative to umbilical repair and replacement, Siemens has developed a compact subsea hydraulic power unit (SHPU) for installation close to the subsea tree. The unit is intended as a standardized part of the operators’ toolbox, and is connected to the tree by Subsea Instrumentation Interface Standardization (SIIS) level 2 interfaces. The SHPU will take available electrical power from the existing infrastructure at the well site, and store it in a battery based energy bank. When hydraulic power is needed for valve operations on the well system, it will be provided by a pump driven by an electrical motor. Installation and retrieval of the SHPU can be done using a typical inspection, maintenance and repair (IMR) Vessel with a lift wire and remote operated vehicle (ROV) assistance.
The SHPU may also be used as a building block to develop long step-out developments in a cost-efficient way. By producing the hydraulic power locally at the seabed, it is possible to remove the hydraulic lines of the umbilical and thereby gain significant reductions in investments.
One of the primary recommendations of the Wood Review is for Government and Industry to develop and commit to a new strategy for Maximising Economic Recovery from the United Kingdom Continental Shelf (UKCS). To achieve this recommendation several strategies are proposed. These cover the key UKCS areas which require enhanced development to ensure that the UK maximises the production of its assets.
As part of the Technology Strategy, there is push to apply better reservoir management techniques on a cost effective basis. In order to manage a reservoir appropriately, the produced fluids have to be measured accurately. Typically in the UK, this is accomplished through the use of Well Tests and associated equipment – namely test separators supported by single-phase flow measurement technologies.
Well test data is critical to operations in the offshore industry and covers a wide variety of applications. The data can be used to allocate produced fluids to particular wells either directly, or through verification of multiphase flowmeters. The data can also be used in the determination of reservoir size and in the positioning of new wells and installations. Another key use of well test data is in the optimisation of well production where well stream parameters can be altered to maximise hydrocarbon production levels.
However, recent first-hand audit experience by DECC suggests that well test measurement systems may not be operating at their optimal levels. For instance, primary measurement elements (flowmeters) are often not removed and recalibrated on a routine basis. There is also evidence of flowmeters being exposed to two phase flows resulting in meter degradation. In addition, the interval between the testing of individual wells may extend to several weeks, with the flow rates between tests inferred by interpolation. The risk is therefore that these measurements may result in a measurement bias.
This paper will present work completed on behalf of DECC into the current state of the art for well testing in the UKCS. North Sea operators have been questioned and their responses used to calculate typical uncertainties achieved during well testing. The significance of the uncertainty in measurement is highlighted through case studies into the impact on the applications that use well test data. Finally, alternative methods to current well testing practice are discussed with their expected impact on the UK offshore oil & gas industry.
The submitted paper provides evidence and recommendations in line with the ethos of the Wood Review, as well as assisting industry to achieve the goals and step-wise improvement in performance, which the Review demands.
Lian, C. J. (Shandong University of Science and Technology) | Hou, J. Z. (Shandong University of Science and Technology) | Gao, G. L. (Taian Taishuo Strata Control Science and Technology Co. Ltd.) | Wang, G. (Taian Taishuo Strata Control Science and Technology Co. Ltd.) | Song, W. T. (Henan Polytechnic University)
ABSTRACT: It has wide distributions and large recoverable reserves of Jurassic period coal seam in China. It is difficult to maintain stability of the development roadways with long service term for Jurassic strata because there are abundant argillaceous rocks and some minerals in the high argillaceous rocks will be expanding while meeting with water. The fractures of the roadways develop well under high stress and are suitable to filling with grouting. But the poor cementing performance of cement with argillaceous rock as well as a heavy water filtration rate of cement slurry had resulted in failures of many engineering cases adopting cement grouting to reinforce this kind of roadways. In this paper, according to characters of the high argillaceous rock in Jurassic strata, a marlaceous inorganic grouting material which possesses the well cementing performance with argillaceous rocks and little filtration rate was introduced; and the grouting reinforcement mechanism, construction technique and engineering application effect about it was clarified. It will be of great significance for reinforcement and maintenance of the development roadways with high argillaceous rocks.
According to statistics, 60% of the proved coal reserves in China distributes in Early-Middle Jurassic period of northern North China, southern Northeast China and Northwest China, along with late Jurassic to early Cretaceous period of Northeast China and east Inner Mongolia. The period of coal forming is short and argillaceous rocks are abundant in Jurassic strata. Moreover, there are quite a few expanded minerals in some strata. So the roadways are easily to be deformed and damaged when affected by mining-induced stress. In addition, this kind of soft rock roadways has an obvious time effect. For the development roadways with long service term, serious deformations are frequently observed and part of the roadways has suffered deformation and maintenance time after time. The stability support of the development roadways really need much cost.
Lai, Rixin (GE Global Research) | Chi, Song (GE Global Research) | Garces, Luis (GE Global Research) | Elgsaas, Kristin Moe (GE Oil & Gas) | Alford, Mike (Chevron Technology Co) | Dong, Dong (GE Global Research) | Zhang, Di (GE Global Research) | Masoud, Haji (Chevron Technology Co) | Gunturi, Satish (GE Transportation) | Harfman Todorovic, Maja (GE Global Research) | Sihler, Christof (GE Global Research) | Song-Manguelle, Joseph (ExxonMobil) | Datta, Rajib (Arizona State University) | Pappas, James Marcus (RPSEA) | Gupta, Rajan (GE Global Research) | Rocke, Svend Erik (GE Oil & Gas)
The offshore oil and gas industry is developing subsea processing systems far away from the shore and in ultra-deepwater. These subsea systems are usually power intensive, and thus a reliable electrical transmission and distribution (T&D) system is desired. In this paper, the modular stacked direct current (MSDC) architecture is presented to meet the technical challenges of the ultra-deepwater subsea systems. Instead of using a bulky centralized high voltage direct current (HVDC) converter station, the high dc voltage is achieved by stacking a number of power converter building blocks in series on both the on-shore station and the seabed stations. The dc-link current is controlled to be constant, and the dc-link voltage will vary according to the loading condition. This architecture renders fault-tolerant capability and feasibility for field extension. The details for the system architecture, the control algorithm, the simulation and experimental results will be described. The test results and the studies show that the MSDC system is a very attractive solution for subsea applications.
Plug and Abandonment (P&A) can easily contribute with 25% of the total costs of drilling exploration wells offshore Norway. Cost efficient P&A technology is therefore necessary to reduce cost of exploration drilling. In this paper, qualified technology for cutting and retrieval of wellheads using a separate vessel is described in detail. It is shown how to use this technology to significantly reduce the total costs of exploration drilling. The technology has now been used on several abandonment operations on the Norwegian continental shelf.
In the paper it is presented through examples how efficient P&A operations are run using a dedicated vessel to perform parts of the wellhead cutting and retrieval operation earlier conducted with the drilling rig. Examples illustrate how the different wells are permanently plugged back to maintain all barrier requirements before the drilling rigs leave the wells with wellheads in place. During a later wellhead removal campaign a dedicated vessel arrives cutting the casings underneath the sea bed and finally removes the wellheads. It is shown that removal of more than two wellheads in a campaign is necessary to make this type of operation cost efficient.
By transferring activities like Plug and Abandonment (P&A) and anchor handling from rig to dedicated vessels, the cost of drilling operations will be reduced and drilling production will be increased (Sørheim et al., 2011). The objective of transferring these activities to the dedicated vessels is to maintain the drilling rig activity at their core functions, which are drilling and completing wells. For example, in offshore drilling operations it is generally more cost effective to pre-set anchors prior to arrival of drilling rigs than to let the rig be an active part in anchor handling (Saasen et al., 2010). Similarly it can be efficient to pre-set conductors prior to rig arrival. As mentioned, permanent P&A is also an operation where activities can successfully be moved from rigs to dedicated vessels. In addition to the economical benefits of moving activities to dedicated vessels, there is a significant Health, Safety and Environment (HSE) benefit. These transferred activities are now conducted by specialised personnel on dedicated vessels. On the rigs these activities will be parallel to other rig activities and thereby represent a slightly higher HSE risk.
Going and Haughton (2001) presented tools for casing string recovery including casing cutter, a hydraulic casing spear and a combined marine swivel/hanger seal extractor have been presented earlier. This system has successfully been used on drilling rigs to remove casing strings and wellheads. P&A without the use of drilling rigs is currently a routine operation on land wells. See for example Tettero et al. (2004). These techniques however, are not straightforward in offshore operations.
P&A of offshore exploration wells represents a significant part of the drilling cost especially for production wells. Normally these operations are conducted by removing completion equipment followed by placement of a series of cement plugs. This application of cement plugs is described by for example Liversidge et al. (2006). Also, while drilling exploration wells, the P&A operation is a significant cost. Therefore, a method using a concentrated sand slurry for P&A of the reservoir has been applied to minimise the time to wait for the cement to cure (Saasen et al., 2011). In the following it is shown how parts of the P&A operation successfully have been transferred from the rig to a dedicated vessel and thereby reduced rig time on non-drilling activities.
There are many small scale onshore and offshore gas fields and there are also many diverse small LNG consumers around the world. However, smaller unit of gas fields could not be practically developed due to unfavorable unit price competition with larger ones. Therefore, many stranded gas fields are still waiting for new viable technology for the small unit production. In order to have unit production cost competitiveness, CAPEX and OPEX should be reduced. Cluster LNG technology based on increased pressure liquefaction has distinct advantages in OPEX and CAPEX with inherent high liquefaction efficiency together with superior environmental performance. One of the potential gas consumers for the small capacity LNG would be fuel oil fired diesel engine or gas turbine power plant operators who eagerly attempt to change the fuel source to natural gas due to high fuel oil price. Most of the cases, power plants are located far away from the gas fields, so efficient gas transportation solutions have to be provided. LNG is efficient means of gas transportation between 2 different locations. On the other hand, it requires complicated gas treatment and liquefaction systems which results in high delivery cost. Considered that gas engines need gas as final form not as LNG one, if the interim product of LNG liquefaction is simplified, it would be beneficial to overall project economy. As an application example, extensive economic studies for 0.5 MTPA Cluster FLNG, LNG transportation vessel, and 350 MW capacity LNG power plant have been carried out. Typical distance from the gas field to power plant is 2,000 Km though it can have competitiveness up to around 5,000 Km. The smaller unit LNG production system with high competitiveness would activate developments of stranded gas field, and it would change business paradigm by bringing flexibilities and diversities in the industry.