Many of the more recent wells in the Ekofisk Field in the Norwegian North Sea have been completed as monobores with lengthy horizontal or high angle sections and several distinct perforation clusters - as many as 20 separate zones can occur. The early methods of stimulating these chalk reservoirs involved high volume acid jobs, featuring bull heading, and the use of frac balls to divert flow to the less permeable sections. However after collection and evaluation of much data it became clear that many of the perforated intervals were unproductive. In order to address this situation it was decided to change to a selective stimulation method using newly designed coiled tubing (CT) deployed straddle pack-off tools.
Subsequent evaluation of this method indicated that it was a more productive approach; however the reliability of the method was less than desirable due to equipment and methodology failures. This realization lead to a detailed study of these CT operations carried out over a period of 9 months involving evaluation of the results of stimulating 9 separate wells with perforation sets ranging from 7 to 20. The study involved review of equipment design and function, material choice and methodology such as pumping techniques, use of glycol trains, accuracy of depth measurements, reliability of pressure measurement equipment etc. with the objective of optimizing them for future operations.
In this paper the authors will briefly review the history and results of the initial stimulation of these wells and the decision to go to straddle pack-off methods. They will then describe in detail the results of the study to evaluate and improve equipment and techniques, the lessons learned and the changes that resulted, leading to more reliable and effective stimulation techniques that are now being used.
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.
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.
Abdul Rahman, Afizza Anis (Petronas) | Hamzah, Nurul Ezalina (Petronas Carigali Sdn Bhd) | Ahmad Fauzi, Nurfaridah Bt (Petronas Carigali Sdn Bhd) | Safiin, Norhisham (Petronas Carigali Sdn Bhd) | Khalid, Zaidan B. (Petronas Carigali) | Syaifullah, Nalom (Petronas Carigali Sdn Bhd) | Jenie, John R. (Schlumberger) | El-hariry, Haitham Fouad (Schlumberger)
The sustained and relatively high value of oil and natural gas has resulted in an unprecedented level of drilling activity and implementation of innovative methods to recover as much hydrocarbon as possible, and as quickly as possible. The resulting demand for conventional drilling rigs for programs has forced the rates high and the availability low, making use of the units difficult to justify for use in declining fields with less significant amounts of recoverable product. The by-passed reserves remaining accessible in these depleted fields exist in volumes worthy of pursuit, but must be done economically.
In many fields, operators, either intentionally or unintentionally, bypass pay zones during initial development by focusing only on the best zones. Accessing bypassed thinly laminated formations can be economically attractive but poses several challenges, especially due to aged platforms and completion string in place, also offshore environment is adding its own challenges.
Coiled Tubing Drilling (CTD) has yet to establish itself in an offshore environment. Numerous one-off projects have been tried, but commitment was never made to a number of wells to see through the learning curve and realize the potential of the application. Offshore South China Sea have a huge quantity of candidates on existing installations, installations that, due to water depths and sub sea conditions require large, expensive rigs to drill or re-enter wells. Technically the wells can be accessed with coiled tubing with drilling parameters seen regularly in other projects. The challenges for this pilot project will be equipment specification and set up, efficiently exiting the casing, and management of wellbore stability in open hole drilling and completion techniques.
The main objective of this pilot project is to bring proven technology to offshore environment to access small bypassed reserves economically and provide an alternative to conventional drilling. The well candidates were selected with strict work scope to avoid going beyond the regular CTD application to ensure learning curve and lessons learned can be implemented throughout the project and achieve the objective.
This paper will described the preparation, execution, achievement and lessons learned from this 4 wells pilot project in offshore South China Sea.
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.
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.
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.
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.