Innovative Live Well Perforating System Used in the Statfjord Field
Abstract: TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper describes a system developed for live well perforating and presents several case histories of its usage. The system has currently been used on 13 jobs on the Statfjord field. A total of 2106 m has been perforated, and the longest interval in one run has been 277 m in this particular field. The system has been used both for initial perforation on new wells and reperforation in live wells or in combination with zone isolation. Both injectors and prod… Show more
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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe technology for coiled-tubing-conveyed perforating (CTCP) under extreme conditions has been available for a number of years, but until recently, the techniques have not been used in Venezuela. This paper will describe the first experiences in which CTCP has been used in this area.The first candidate identified for the application was a new well in East Venezuela. This well was the first high pressure, high temperature (HP/HT) highly deviated deep monobore well completed in El Furrial Field in the North Monagas area that was perforated underbalanced with this technology. Although several traditional perforating methods were initially evaluated, the decision was made to perform the operation underbalanced using rig-assisted coiled-tubing technology because of the following advantages that could be realized from use of this method:• Debris in the tunnel would be reduced, minimizing the potential for formation damage. • The debris could be circulated out more easily.• The use of kill fluid to control the well would not be necessary. • By eliminating the cost of the kill fluid and the resulting costs of handling the returned kill fluid, well costs would be reduced. The operation was performed in a live well with a 77degree maximum well deviation and total depth (TD) of 17,907 feet. Several engineering simulations were performed before the job. These simulations enabled the operator and service engineering personnel to quantify the effects of CT fatigue, lockup, stresses, forces, elongation due to weight and temperature, and buoyancy effects. Other important factors considered were safety, health, environment, quality and well control, taking into account all possible contingencies. Finally, nine (9) coiled tubing runs were performed to complete the well, a total of 1,190 ft of 3 3/8-in., 6 shots per foot (SPF) and 2 ¾-in., 6 SPF guns were run. In all of the coiled-tubingconveyed perforating runs, the expended guns were retrieved successfully under live well conditions. To retrieve the guns without killing the well, a subsurface flapper-type safety valve, which enabled the operations to be performed under controlled conditions, was used.Currently, the well is producing 19,621 BOPD through a 1-in. choke and 1,591 psi surface pressure.Production and wellhead pressure expectations for this well were exceeded.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe technology for coiled-tubing-conveyed perforating (CTCP) under extreme conditions has been available for a number of years, but until recently, the techniques have not been used in Venezuela. This paper will describe the first experiences in which CTCP has been used in this area.The first candidate identified for the application was a new well in East Venezuela. This well was the first high pressure, high temperature (HP/HT) highly deviated deep monobore well completed in El Furrial Field in the North Monagas area that was perforated underbalanced with this technology. Although several traditional perforating methods were initially evaluated, the decision was made to perform the operation underbalanced using rig-assisted coiled-tubing technology because of the following advantages that could be realized from use of this method:• Debris in the tunnel would be reduced, minimizing the potential for formation damage. • The debris could be circulated out more easily.• The use of kill fluid to control the well would not be necessary. • By eliminating the cost of the kill fluid and the resulting costs of handling the returned kill fluid, well costs would be reduced. The operation was performed in a live well with a 77degree maximum well deviation and total depth (TD) of 17,907 feet. Several engineering simulations were performed before the job. These simulations enabled the operator and service engineering personnel to quantify the effects of CT fatigue, lockup, stresses, forces, elongation due to weight and temperature, and buoyancy effects. Other important factors considered were safety, health, environment, quality and well control, taking into account all possible contingencies. Finally, nine (9) coiled tubing runs were performed to complete the well, a total of 1,190 ft of 3 3/8-in., 6 shots per foot (SPF) and 2 ¾-in., 6 SPF guns were run. In all of the coiled-tubingconveyed perforating runs, the expended guns were retrieved successfully under live well conditions. To retrieve the guns without killing the well, a subsurface flapper-type safety valve, which enabled the operations to be performed under controlled conditions, was used.Currently, the well is producing 19,621 BOPD through a 1-in. choke and 1,591 psi surface pressure.Production and wellhead pressure expectations for this well were exceeded.
This paper presents a comprehensive study on the productivity and flow efficiency of horizontal wells completed with slotted-liners or perforations. The study is based on a semi-analytical model that couples the flow equations in the reservoir and wellbore. The reservoir model takes into account the 3D convergence of flow around perforations and slots. The wellbore flow model considers the pressure losses inside the horizontal well and the effect of axial influx at the perforations and slots. A new, experimental apparent friction factor correlation is used for horizontal wellbore flow computations with perforations and slots. The model is capable of incorporating the effects of selective completion and non-uniform skin distribution. The results of this study indicate that software based on detailed semi-analytical models can provide a powerful tool to design, predict, and optimize horizontal well completions. It is also shown that horizontal wells deserve genuine guidelines to optimize their completions. For example, horizontal wells are shown to require significantly lower slot and perforation densities to accomplish optimum PI compare to vertical wells. Similarly, in horizontal wells, the effect of slot or perforation phasing becomes more important as the anisotropy of the formation increases. Introduction Horizontal wells are one of the most important strategic tools in petroleum exploitation.1 As a result of the advances in drilling and completion technologies in the last two decades, the efficiency and economy of horizontal wells have significantly increased. Today, horizontal well technology is applied more often and in many different types of formations. The state of the art applications of horizontal well technology require better completion designs to optimize production rates, long-term economics, and ultimate producible reserves. Horizontal well completions can be categorized as natural completion, sand-control completion, and stimulation completion. Natural completion includes open-hole, slotted-linear, and cased and perforated completions. Sand-screens, prepacked screens, and gravel packing are the completions used for sand-control. Stimulation completion includes completion with hydraulic fracturing and fracturing with gravel packing (fracpack or stimpack). All of these completion methods have been used in practice under different reservoir conditions.2,3,4 In a horizontal well, depending upon the completion method, fluid may enter the wellbore at various locations and at various rates along the well length. Fig. 1 illustrates the interplay between the pressure and flux distribution along the wellbore through the completion openings. The complex interaction between the wellbore hydraulics and reservoir flow performance depends strongly on the distribution of influx along the well surface and it determines the overall productivity of the well. Therefore, the optimization of well completion to improve the performance of horizontal wells is a complex but very practical and important problem. The complexities of the numerical simulation of horizontal well completions make analytical models extremely attractive. However, the inherent difficulties of the analytical solutions caused by the complex flow geometries, excessive number of perforations or slots, and non-uniform distribution of flux along the horizontal well calls for the challenging task of developing efficient computational algorithms.
As development of hydrocarbon reserves continues to move into deeper and more complex reservoir conditions, operators have found that conventional techniques for testing, perforating, and stimulating have not been capable of providing satisfactory results in the severe well conditions. Even if operationally satisfactory, they have been unable to meet the goals for cost efficiency. This paper describes an experience in the Tropical Field, located in eastern Venezuela and operated by Repsol - YPF in which the reservoir is characterized by high-pressure reservoirs and complex geology due to faults and high-dip-angle formations. Repsol needed a method that would optimize well testing operations, improve safety, and cut costs without compromising the results of the operation; thus, a major change to traditional drill stem testing operations was needed. A technique, which would eliminate the need to kill the well to retrieve the guns and also provide the flexibility to test, evaluate, and fracture the well, was suggested. Instead of using a drilling rig or a work-over unit as in the standard drill- stem testing operation, the procedure would allow the operator to perform a rigless well test evaluation using optimum underbalanced conditions in favor of the reservoir. Several alternatives were evaluated for perforating and testing the well. After thorough examination of all possibilities, snubbing- and coiled-tubing-conveyed perforating (CTCP) methods were selected as the most promising alternatives for achieving the objectives proposed at the beginning of the project. While coiled tubing had been used to perforate in other areas in Venezuela, coiled tubing combined with snubbing had not been used in Venezuela. This paper will focus on the methods developed to satisfy the operational challenges, the results obtained with the use of the newly applied technologies, and how the technology was able to address the operator's needs as well as the difficult reservoir conditions. Instrumental in the success of the methodology was the combined use of super-deep penetration technology, state-of-the-art memory tools for depth correlation, real time data transmission, and the flexibility to perform several operations during a rigless well-test evaluation. This case history represents the first live-well intervention using snubbing and coiled-tubing perforating techniques performed successfully in eastern Venezuela. Introduction The Tropical Field is located in east Venezuela approximately 28 miles from Maturin, capitol of Monagas state, in the North Monagas Area. This location is one of the most prolific production areas in the country. The reservoir is characterized by high-pressure and complex geology due to faults and high-dip-angle formations. The field is presently under development, and 4 wells have been drilled. Oil is produced from two locations - the San Juan Formation at approximately 13,890 feet and from the San Antonio Formation at approximately 14870 feet. The average total depths in the wells are 15,800 ft. and are slightly deviated. Thus, perforation techniques had to be capable of operating in complex geology due to faults and high-dip-angle formations. Perforating Techniques used on Tropical Area. During the exploratory stage of field development, tubing-conveyed perforating (TCP) was used since it offered the capability to perforate the well in an underbalanced condition. In the first wells, the TCP string included the DST string for evaluation. The wells still had to be killed, but underbalance was obtained. Then, rigless perforating systems were considered. The objective of this change was to optimize the cost involved during the well-testing evaluation operation, and at the same time, obtain the benefits that can be achieved from having the completion already in place and the capability to perforate without killing the well. The technology applied at the beginning of the project was to perform TCP on coiled tubing; however in the well discussed in this case history, it also became necessary to use a snubbing unit to perform the gun runs because of the difficulties experienced in meeting operational requirements in the complex geology.
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