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
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.
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.
A Natural Gas Liquid fractionation plant located in Ontario, Canada receives NGL feedstock from local industries in order to produce propane, iso-butane, and condensate. These finished products are stored in horizontal tanks and storage wells/salt caverns located within the chemical plant. One of these gas storage wells required two bridge plugs in order to create a barrier to enable workover operations to be undertaken.
The objective was to load the well with brine in order to perform a logging run and replace the wellhead. There were two challenges involved in this operation: the lack of a workover rig and ‘wellbore fluid' for setting an inflatable bridge plug. TAM International's SlikPak™ Plus inflatable bridge plug setting system was the optimal solution because its ‘carry fluid' configuration is capable of transporting the necessary inflation fluid to set a bridge plug without a workover rig on location.
An additional challenge had to be overcome as well; both bridge plugs had to pass through a 7.6?? (193.4 mm) ID wellhead restriction and inflate inside 13-3/8?? (339.7 mm) casing. Therefore, during the first run, the inflatable bridge plug setting system had to carry twenty gallons (75.70 L) of inflation fluid within twelve 3-½?? (88.9 mm) OD fluid chambers located along the toolstring in order to inflate and set the retrievable bridge plug. The client provided 105 feet (32 m) of lubricator and two cranes in order to perform a safe rig up of the 94 feet (28.65 m) long toolstring. The first bridge plug was successfully set at a depth of 2,040 feet (621.8 m) by stroking the mechanical Pull Intensifier. After the plug was set, the top section of the well was bled off and loaded with brine to enable the usage of the ‘wellbore fluid' setting configuration, which successfully set the second bridge plug 31 feet (9.44 m) above the first one.
After the wellhead changeout took place, both bridge plugs were successfully equalized, deflated, and retrieved in order to re-enable gas storage in this well. It is expected that there will be similar operations on a nearby well in the future.
The increased demand for natural gas from shale plays in the US has forced the industry to be more efficient and develop innovative methods for fracture-stimulation optimization. Pinpoint-fracturing methods represent a divergence from the conventional methods with minimal optimization needed to help maximize reservoir volume. Multiple-interval completions can be performed efficiently so that all intervals receive the designed proppant volumes, one interval at a time. To accomplish this efficiency, coiled tubing (CT) is used to hydrajet perforate intervals for individual fracturing treatments at predesigned depths. Using various methods, CT depths can be corrected to actual depths, resulting in the precise placement of the perforations. Proppant plugs are used not only for isolating previously stimulated intervals, but also for maximizing the near-wellbore (NWB) conductivity necessary for long-term production performance. These fracturing methods do not require removing the CT from the well between treatments, and contingencies for early screenout can be remediated immediately with minimal impact to overall completion costs. Treating intervals individually substantially reduces the amount of hydraulic horsepower required onsite.
The latest pinpoint-fracturing technique provides maximum engineering flexibility in the execution of these treatments by allowing downhole control of the proppant schedule; this can be used to optimize the stimulated reservoir volume (SRV) on-the-fly, in real-time, and with downhole control. The process also incorporates large-OD CT. A recent 25-interval completion in the Eagle Ford shale demonstrated the process and is discussed in this paper.
Over the last few decades, coiled tubing technology has found increasing applicability in oilfield operations, including well intervention, well logging, coiled tubing drilling, perforation and fishing operations. Significant attention has been given to the prediction of friction pressure loss of various fluids pumped through coiled tubing and the annular space between the tubing and the wellbore. The importance of such prediction cannot be underemphasized, as adequate knowledge of the anticipated friction pressure is useful for determining the required pump horsepower and developing hydraulic programs during the operational planning stage.
However, a coiled tubing string can buckle under its own weight when the axial compressive load acting on the string exceeds a certain threshold, known as critical buckling load. In long extended reach wells, the extent of buckling, as well as its effect on fluid flow hydraulics can be significant, especially in the annulus between the tubing string and the wellbore. Despite the frequent occurrence of tubular buckling in many oilfield operations, previous publications on annular flow have traditionally considered flow in concentric and eccentric annuli, mainly discussing the effects of diameter ratio, fluid rheology and eccentricity on the friction pressure loss observed in such conduits.
The present numerical and experimental study examines the characteristics of steady-state isothermal laminar flow of non-Newtonian (Power-law) fluids and turbulent flow of Newtonian fluids in annulus with a non-rotating buckled inner tubing string. Numerical modeling results of fluid flow in various three-dimensional annular geometries using Computational Fluid Dynamics (CFD) are presented, ranging from a uniformly eccentric annulus to an annulus consisting of "corkscrewed?? inner tubing - a helical buckling state, whereby the coiled tubing is permanently deformed when the prevailing bending stresses exceed the yield stress of the tubing. In addition, extreme cases of "arbitrarily?? buckled coiled tubing annulus were evaluated for each size of coiled tubing considered. An interesting observation is the increase in annular friction pressure loss with increasing buckling extent. The CFD simulation results have been verified experimentally using a field-scale flow loop comprising of a helically buckled tubing annulus and an equivalent uniformly eccentric annulus. Practical empirical correlations have been developed, taking into account certain buckling parameter, to improve the accuracy of annular friction pressure loss predictions in coiled tubing operations involving a considerable level of buckling.
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.
Kenison, Michael (Schlumberger) | Adil, Abdur Rahman (Services Tech. Schlumberger) | Morrison, Richard Joseph (Schlumberger) | Ramos Valencia, Carlos Fernando (Schlumberger) | Harber, Bonnie En (Schlumberger) | Hermelink, Henk (Schlumberger) | Frederiksen, Christian Husum (Maersk Oil & Gas A/S)
Sliding sleeves are used to enable selective zonal isolation and can improve water and gas management throughout the life of the well. Because of the large shifting force and extended reach required to operate sliding sleeves in long horizontals, coiled tubing is typically used. Coiled tubing also provides the benefit of pumping fluids to clean out or treat the well. A surface load measurement with coiled tubing may sometimes provide a positive indication of shifting, but not in all cases. Also, surface measurements alone do not provide a way to determine the sleeve position. This paper describes conventional techniques used to confirm proper shifting and determine sleeve position. An improved method is presented, along with yard and field test results.
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.
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.