Yudin, Alexey V. (Schlumberger) | Burdin, Konstantin (Schlumberger) | Yanchuk, Dmitry (Schlumberger) | Nikitin, Alexey Nikolaevich (Rosneft) | Bataman, Ivan Vyacheslavovich (Rosneft) | Serdyuk, Alexander (Rosneft) | Mogutov, Nikolay (Rosneft) | Sitdikov, Suleyman Saubanovich (Rosneft)
Traditionally, coiled tubing (CT) in Russia has had very limited service diversity. Its use has been concentrated at wellbore cleanouts and nitrogen kickoffs after fracturing treatments.
We used coiled tubing equipment and technologies to supplement stimulation operations in one of the world's largest oil fields, Priobskoe, which has up to five separate layers per well. Conventionally, well completions here have involved complicated workover operations with tubing, packers, and wireline perforating after each stimulated layer. Average wells with three layers took 30 days to complete. CT provided a significant improvement in completion efficiency, reducing the cycle time to just 10 to 12 days.
The first option of the completion and stimulation technology assumed "through casing?? operations, eliminating the use of frac strings and a packer, which is a significant achievement under Russian regulations. This was done with a 4-in.-OD perforator and casing with increased strength. A year later, a second option for the technology was introduced to operate on regular strength casing through tubing. A slimmer abrasive perforator that could fit into the packer's internal bore developed for this option was particularly effective for sidetrack and horizontal completions.
In total, 95 wells were analyzed with more than 250 stimulation stages. This includes an operational and technical review of the tools and techniques used to compare the efficiency of the whole cycle of completion, resources requirements and amount of risks and non-productive time associated. Also a productivity comparison of CT combined with fracturing technology versus standard process of wireline/workover/stimulation sequence will be given.
Recently a new coiled tubing technology has been used to clean out horizontal wellbores with a low downhole pressure. This technique uses a dual coiled tubing string and a special vacuum tool designed to create a pressure drop across the formation sand face in order to clean out formation fines, unwanted fluids and solids. The work string, used for this application, has a rectangular matrix design; the two 1-1/2??coiled tubing strings are encapsulated into one uniform body using a high strength thermoplastic jacket. The power fluid is circulated down through one of the strings and the returns, including fines and solids, are transported to surface, up the second string. To operate the system, a custom coiled tubing reel, with two rotating joints was designed. The fluid goes through a jet pump (BHA), where it passes through a nozzle creating a "Venturi effect??. New software has been developed to simulate the torque and drag, given that the cross section area is similar to a rectangle and it has two contact points, instead of one. A hydraulic simulation has been performed to determine the jet pump performance, circulation rates and pressures. Real time data was used to calibrate the models.
The technology has been used for liner clean outs, in horizontal heavy oil (8 API) wells, with low pressure averaging 362 psi at 2625 ft (2.5 MPa; 800 m TVD; ) reservoirs.
In the first well, 656 feet (200 meters) of 5-1/2?? horizontal slotted liner was cleaned out down to 3008 feet (916 meters) and 4.7 barrels (745 liters) of sand were circulated out to surface (30% of the total internal volume). In the first well the production was recovered from an initial rate 6 bbls/day to 31 bbls/day (1 m3/day to 5 m3/day). In the second well, with 5% H2S, the dual coiled tubing was run in the 4-1/2?? production tubing and the 4-1/2?? horizontal slotted liner was cleaned out down to 3550 feet (1082 meters).
Based on the results, this technology is proven to be a viable solution for cleaning long horizontal wells with low bottom hole pressures.
For almost two decades, coiled tubing drilling (CTD) has proved to be a successful method to reach the un-swept portions of Alaska's North Slope reservoirs. This method of drilling has evolved over the years with new technologies and efforts from contractors and operators striving to improve performance from lessons learned. Despite these improvements in equipment and processes, operators and contractors must still deal with certain inherent deficiencies of this drilling method when compared to conventional rotary drilling - suboptimal weight transfer, sometimes troublesome hole cleaning — due mainly to lack of string rotation and low flow rate range, etc. These shortcomings have the potential to induce other drilling performance problems that affect the smoothness of coiled tubing drilling operations. Severe lateral vibration and severe stalling have become acceptable evils over the years, resulting in undesirable trips for failure and unacceptable non-productive time (NPT), both undermining one of the key benefits of coiled tubing drilling - rapid pace operations compared to rotary drilling.
This paper introduces a new lower-speed downhole positive displacement motor (PDM). The technology is equipped with high-performance elastomer and was engineered to improve drilling and drill-bit performance in CTD applications. Recent field deployments in Alaska's North Slope CTD operations proved this design by eliminating earlier performance problems for improved CTD project economics. For example, the technology's ability to allow for about 10gal/min higher flow rates (compared to other motor designs) significantly improves hole cleaning; a key aspect in CTD operations.
Up to today, this downhole mud motor design has been utilized on 13 wells, accumulating 1,303 circulating hours, 577 drilling hours and over 20,700 ft drilled. Performance improvements in depth of cut, reduced lateral vibration, reduced amount of stalls, and other benefits were achieved. There was no trip for PDM failure in all of the 34 runs, traversing different formation zones. The corresponding paper will provide additional information on application benefits by investigating two recent field deployments.
During sidetracking operations in re-entry wells, unstable formations significantly reduce the probability of success. A typical solution to mitigate the problem is to set conventional casing across the trouble zone. The casing would serve as a mechanical barrier to prevent the collapse of the borehole.
In many cases, the tubing or casing used for re-entry operations is small diameter, e.g., 4-1/2??. Due to the small diameter, limited equipment is currently available for completion of these wells. Furthermore, due to the limited size of the production conduit after completing the re-entry with conventional equipment, the well becomes uneconomical.
As a solution to the limitations of conventional casing, solid expandable casing has been identified as a viable option to enable the completion of such directional wells. This technology provides mechanical stability in situations where conventional casing strings cannot be installed in the well due to geometrical restrictions.
The geometrical restrictions encountered in these re-entry wells coupled with the relatively large drift diameter needed to effectively complete the pay zone, calls for an expandable system with relatively large expansion ratios up to 30%. These high expansion ratios constitute a technological step-out with respect to off-the-shelf expandable systems.
Due to basic system limitations, these high expansion ratios cannot be achieved with hydraulic expansion systems. Therefore, a mechanical system which transmits no internal pressure to the expandable pipe during expansion is the most suitable solution.
Real time digital slickline services have been used increasingly in the Gulf of Mexico by a number of customers. Through its telemetry enabled capabilities and the purpose built tools that complete the platform, digital slickline services can deliver a number of safety and efficiency gains to all types of slickline operations.
Material presented in this paper will be from actual operations, examples being perforation, tubing punching and cutting, plug setting and cement dump bailing, and will demonstrate the operational efficiencies being delivered.
Enhancement of the slickline service comes from real time surface readout of in situ tool operational status, the critical core measurements of downhole toolstring movement, deviation head tension and shock, and the depth precision now offered through gamma ray and CCL sensors. Optional tools such as a pressure / temperature gauge bring yet further visibility on the impact of the downhole actions undertaken. Expansion of the slickline service capabilities come from the telemetry enablement and core tools, coupled with a range of specific tools and sensors that have been developed to run on this slickline platform, namely a electro-hydraulic setting tool, an explosive triggering device, a monobore lock mandrel, and a production logging suite.
The real time data that is delivered to the slickline operator removes the need for assumptions that often have to be made during conventional slickline operation, and allow for a more efficient and reliable slickline operation to be undertaken. This results in a reduction in operation time, and a reduction in unnecessary trips out of the well to check on the tool status or to validate depth. Furthermore, since digital slickline is able to carry out both slickline well preparation work and a range of remedial or measurement work often carried out on memory or eLine, these operations can often be conducted entirely utilizing digital slickline crew and equipment. This optimizes pre- and post-job logistics, equipment rig up and rig down, and the job execution itself. In addition to the obvious cost savings, with a slickline wire comes a simplification of the pressure control and a well control recovery situation.
An operator in Prudhoe Bay, Alaska required the ability to replace gas lift valves in their completion for improved oil production. Conventional methods had reached their limits due to extended well lengths and high-angle well deviations. Slickline was unable to overcome the higher deviations, while imprecise depth control during coiled tubing operations required multiple run-in-hole attempts to pull and replace the valve.
Based on previous, positive experiences with electric line - mechanical solutions, the customer chose a unique solution using a newly modified Kick-Over Tool (KOT). Two KOTs run in tandem and combined with a tractor and a hydraulic stroking tool (HST) were used to pull the existing gas lift valve (GLV) and replace it in a single run.
The tractor conveyed the tool string to the correct depth where the HST and the first KOT provided the pulling force for removal. Then, the HST and second KOT were used to successfully install the new GLV into the mandrel.
The operator is now able to optimize their gas lift design without the limitations imposed by conventional means for installing GLVs such as slickline and coiled tubing. This allows them to place gas lift valves in the high angle sections when necessary for increased oil recovery from their reservoirs.
Few changes have been made to the Kick-Over Tool technology in the past 40 years but it has been recently improved to operate more reliably in deviated and horizontal wells and has been modified to accommodate the forces generated by the HST. This paper will describe the challenges with the planning and execution of this operation and the implications for future gas lift design.
Gas-lift is very cost-effective in oil reservoirs with sufficient associated gas but insufficient pressure to overcome hydrostatic head. Its efficiency depends on the lowest true vertical depth (TVD) at which a gas-lift valve (GLV) can be placed/maintained in the tubing string, and the availability of gas compression infrastructure. For instance, given available gas and sufficient compression, placement of a GLV 100ft TVD deeper in a wellbore with productivity index of 1 bopd/psi could mean an improvement of about 40 bopd.
Maintenance of gas-lift valves is restricted by a combination of wellbore deviation and measured depth because gravity-dependent slickline is limited to sections of the well less than about 60 degrees deviation, and sufficiently lengthy coiled tubing is at times unavailable. The maximum vertical depth in a well at which a GLV can be reliably maintained, in part, defines the limits of primary production. Furthermore, the time/cost required to maintain GLVs is critical in highly productive wells (deferred production) and those requiring significant logistics to access (arctic, offshore, subsea, etc.); which causes operators to continuously seek new downhole efficiencies.
Gordon, Scott (Halliburton) | Larimore, David Russ (Halliburton Energy Services Group) | Cervo, Gustavo (Halliburton) | Boechat, Nivea (Shell) | Klein, Mark (Shell) | Buchan, Martin (Shell) | Morris, Colin James Innes (Shell) | Davis, Scott (Shell International Exploration and Production Inc.)
As the number of subsea wells in deepwater environments increases, companies who operate in these regions continue to seek safer and more viable economic solutions for improving value realization through well intervention. Traditionally, subsea well interventions are conducted from heavy-weight, mobile offshore drilling units (MODUs) with riser packages. Unfortunately, these intervention operations involve significant operating day rates with consequent NPV negative results.
This paper discusses a riserless intervention that was performed from a dynamically positioned multi-support vessel (MSV) that involved setting and recovery of a mechanical flow-control device in a well with a water depth of approximately 1900 m in the South Atlantic Ocean. The technologies and methods used in this intervention proved that these difficult subsea operations can be performed in a much more flexible and financially viable fashion than previously possible with conventional methods. The techniques developed for this operation also mitigated safety concerns for personnel and equipment, while executing the potential high-risk riserless intervention with success.
The paper will cover the record-breaking, light-weight intervention and the technologies used on this campaign that eliminated the need for a traditional MODU. Of particular interest is the unique vessel interface that allowed the operation to be performed safely and efficiently with slickline.
This successful intervention opens new opportunities for safer and more economical interventions in the deep and ultra deepwater arenas.
Long-reach horizontal wells with "Plug and Perf?? completions are commonly used to achieve economic production in today's unconventional reservoirs. After the multistage fracture stimulation operations are completed, coiled tubing (CT) is often used to remove the plugs. However as the lateral reach of wells increase, plug removal using CT becomes less efficient as weight on bit (WOB) decreases. Over the last few years, various fluid hammer tools have been introduced to the industry and have improved plug milling times significantly.
This paper will review the results and operational improvements observed from milling operations using both fluid hammer tools and/or lubricants. Data from shale formations across the U.S. (Eagle Ford, Bakken, Haynesville, Barnett and the Marcellus) is included. Analysis from the use of three types of hammer tools and/or lubricants will compare results to those of base case operations completed without fluid hammer tools or lubricants.
The paper will detail improvements in milling efficiencies, number of stalls, and stuck pipe incidents. Results will focus on when to run hammer tools and when to introduce pipe lubricant to achieve optimum efficiencies.
Many operators rely on word of mouth to design and perform extended-reach CT milling jobs. This can result in poorly executed, ‘non-engineered' plug milling operations. This paper will provide data to assist operators in improving their completion efficiencies
Orozco Espino, Rogelio Camilo (Pemex Exploracion y Produccion) | Melo Narcizo, Oscar (Pemex Exploracion y Produccion) | Ulloa Gutierrez, Joel Vladimir (Halliburton) | Robles Hernandez, Fernando (Halliburton)
Finding new areas to exploit for hydrocarbon production has become a challenge. This has led to wells being completed with more than two or three intervals in different configurations and with various petrophysical properties, which can greatly affect production and also accepting treatment fluids.
In addition, in low-pressure wells with multiple open intervals, conducting effective stimulation treatments using chemical diverters or foamed fluids is not always the best alternative.
For cases with multiple areas, stimulation using coiled tubing (CT) is optimal to help ensure stimulation in areas where new intervals have been created as a result of having previous intervals which had preferential acceptance of fluids.
The purpose of this study is to show how stimulation using CT has evolved from using conventional, rotary, and hydraulic-cleaning tools to the development of a new application for stimulation tools, which helps achieve better placement of acid treatment systems.
The advantages obtained with this new application are
• Water cut can be reduced with this technique to help ensure intervals near the water-oil contact are not encouraged.
• It can handle higher pumping rates for effective removal of the damage.
• Penetration of the stimulation fluids was evaluated using radioactive isotopes, and spectral recordings were taken to assess the depth of stimulated intervals, placement and an estimate of the treatment volume, and the radial penetration of fluids.
• Fluid flowback is faster, which saves time on installation and introduction of CT for interventions.
• This acid-stimulation placement technique is the best way to stimulate wells with more than two intervals when selective treatments are required.
During well intervention, control of the well is dependent on the integrity of the intervention-service provider's pressure-containing equipment. The service company's equipment becomes a safety critical element of the duty holder's safety case. Also, control of the pipe string being inserted into the well during HWO is critical to successful well control.
One service provider recently developed two safety devices that enhance the safety of pipe handling and pipe control during HWO activities. A pipe-handling winch tension-limiting system (TLS) was created that helps minimize the risk of accidental overload of the HWO pipe-handling ginpole and winch by retraction of the HWO jack while the pipe is connected to both the jack and the ginpole. This device helps minimize the risk associated with pipe-handling counterbalance winches that have been equipped with brakes. Also, a slip-bowl interlock system was developed that helps minimize the risk of two pipe-handling slip bowls being opened simultaneously, which could cause lost control of the pipe that is being run in hole. This new device replaces the industry norm "weevil latch,?? which is used widely to help reduce this risk. .
This paper describes the risks that these two safety-related inventions address and the details of the development projects that brought them to fruition.
HWO operations, more specifically, running jointed pipe downhole, involves two primary systems. The first is the pipe-handling system, which feeds individual joints of pipe into the jack, and the second is the jack itself. The pipe-handling system brings a joint of pipe from the ground (or deck when offshore) to the workbasket, where operators then connect the pipe to the string being moved downhole. Once the joint is connected to the string, it becomes part of the string, and its movement is controlled exclusively by the jack. The pipe-handling system usually consists of a hydraulically-powered winch and a mast, which has enough height above the jack to hold the joint in a position where it can be fitted to the string.
The two systems mostly operate independently, except for the period of time when a joint has just been fitted to the string and the pipe-handling system is still connected to this now-uppermost joint. Under these conditions, there is a risk that the jack can overload the pipe-handling system. The capacity of the jack to move a joint or string of pipe is many hundreds to thousands of times greater than that of typical pipe-handling systems. Therefore, when the two systems are rigidly connected, the jack will always control the movement of the pipe handling system. Because of this significant disparity in relative system strengths, the state-of-the-art for HWO pipe-handling systems has been the deliberate exclusion of load-holding brakes on hydraulic winches to prevent the jack from damaging or destroying the pipe-handling system when the brakes are set as a result of operator error or system malfunction (Fig. 1). Without brakes, the pipe-handling winch is always able to "spool off?? wire rope, with the hydraulic motor acting as a pump forcing fluid over a relief valve.