No abstract

Conventional slick-line temperature surveys enable successive temperature measurements at pre-determined depth stations along the well-bore. This method has two major drawbacks. The wellbore fluid flow dynamics impact the temperature accuracy while the uncertainty in depth leads to erroneous conclusions on spatial temperature distribution along the wellbore. Remedial actions based on these temperature measurements do not always help optimize productivity or injectivity. To overcome these measurement uncertainties and correctly evaluate the gas-lift system performance for the oil producer wells or to identify temperatures anomalies, such as flow behind casing for water injection wells, continuous temperature measurements with time and depth are needed.The slick-line fiber optics distributed temperature sensors technology presented in this paper measure simultaneous temperature traces along the well-bore with time. This is widely used in oil wells located at Maracaibo Lake, where approximately 95% of the wells are produced using gas-lift and also applied in La Concepcion water injection wells for wellbore integrity. There are technical papers on fiber-optic technology applications as a qualitative monitoring tool but very few case histories where slick-line is used as the method of fiber deployment. This paper will describe eight success histories where fiber-optic sensors have been deployed using slick-line. These case studies are grouped as follows: Gas-Lift System Evaluation in which four wells were subject to analysis: Completion leakages detection in producers and injectors; Identification of water entry as well as channeling of water behind casing. This paper will also demonstrate the application of this technology to implement production enhancement techniques. The use of this technology for operational flexibility, time saving and data quality will be compared to conventional temperature logging. In addition, it will show how environmental risks are eliminated by deploying fiber on slick-line for leak detection services.

Distributed Temperature Measurements (DTS) have been used in the oilfield now for over 10 years, with the majority of applications requiring the fiber to be installed permanently in the well, either inside a 1/4-in control line or as part of an electrical gauge cable. A slickline 1/8-in diameter wire has now been developed with an optical fiber embedded inside it so that DTS measurements can be performed during a conventional slickline operation. This new approach to temperature monitoring means that the optical fiber can now be deployed temporarily in a producer or injector well only when needed, using a conventional slickline unit which can also run a bottomhole pressure gauge or a production log at the same time. The ability to monitor the whole well with DTS using a slickline intervention installation allows the operator to use this technology to resolve a range of well integrity, production and stimulation problems. This paper highlights the use of fiber-optic slickline monitoring in Texas and New Mexico over the past two years by discussing a number of field cases that show the application of this technology for monitoring well integrity and diagnosing well problems, how the DTS can be used to evaluate the fracture height created by a fracture job, determining the effectiveness of the stimulation in acid stimulation operations and also how the data can be used to monitor water injection in low rate injector wells. Because the fiber is deployed and data is acquired on a "when needed" basis, it is proving much more economical than a permanently installed optical fiber, and can bring the benefits of this monitoring technology to a greater number of wells.

Production from naturally fractured reservoirs can be greatly enhanced by stimulation with acid. When pumping the treatment from the surface (a bullhead treatment), the acid tends to enter the reservoir at the most permeable interval (conductive natural fractures). Without any other injectivity control, the acid will not likely divert from this path. Mechanical diversion techniques using swab cups or inflatable packers on jointed pipe or coiled tubing (CT) can ensure injection into the various intervals.With these methods, surface pressure can be monitored to assess fluid placement effectiveness for each zone treated, but uncertainty of the friction pressure in the pipe while pumping can result in an incorrect interpretation of fluid entry. These mechanical isolation techniques are typically more costly and time consuming than bullhead jobs. Diversion techniques for bullhead stimulation treatments using chemical or foam diverters are more efficient, but lack the confirmation that all the zones received acid because of uncertainty of interpreting downhole behavior from surface pressure. A new technique using fiber-optic distributed temperature sensing (DTS) measurements offers a solution when bullheading by providing an indication of where the acid has been injected into the fractured reservoir.A system has been developed consisting of a fiber-optic element encased in an acid-resistant slickline (commonly referred to as SL-DTS) that can be deployed in wells to monitor acid treatments in real time. The entire length of the fiber-optic strand functions as a temperature sensor with a vertical resolution of approximately 3.5 ft. The SL-DTS is gravity deployed or can be pumped into highly deviated or horizontal wells prior to the stimulation treatment. Once in place, the fiber is interrogated with pulsed laser energy to record temperature profiles versus time over the entire fiber length. These time-based data allow easy observation of thermal events due to fluid injections as well as any exothermic reaction of the acid system with the formation. Surface-temperature fluid pumped into perforations provides a cooling effect along the flow path. Interaction of the acid system with carbonate-containing minerals in the formation generates heat. Temperature profiles observed during and after pumping can be used to detect and quantify the distribution of the fluid system into the various intervals.This method was used to successfully delineate acid placement in several deviated wells during bullhead stimulations. The data illustrate zones successfully treated as well as zones that may be targeted for remedial treatment. SL-DTS offers a unique opportunity to optimize stimulation placement in fractured reservoirs or any reservoir with variable injectivity.

Located in Eastern Venezuela the Santa Ana Field is part of the most important gas province of Venezuela: Anaco District. Its main productive zones are the Merecure and San Juan formations, which are sandstones characterized by their high permeabilities (100 - 500 md) and low pressures (1200 - 2200 psi). The wells in Anaco District are normally perforated using conventional static underbalanced techniques. The productivity of these wells was evaluated using nodal analysis techniques coupled with perforating performance simulations. The quality and amount of data was recognized to be limited. However, a qualitative diagnosis of these results indicated that the static underbalanced condition and the shaped charges used were not enough to effectively clean the perforation tunnel and surpass the near wellbore damaged zone. Dynamic underbalanced perforating coupled with high performance charges was selected as the technology that would improve productivity in the challenging wells of Santa Ana. This technology has been applied in similar scenarios across the industry in recent years, although no documentation was found on its use in such low pressure environments. This paper describes how dynamic underbalanced perforating was deployed successfully, while pushing the limits of its application envelope. To obtain a dynamic underbalanced condition in such a low pressure environment, the shot density had to be reduced to 2.5 spf, raising concerns about its effect on well productivity. Two wells were selected for this field trial. They were perforated using a TCP/DST string, which allowed the well to be tested immediately after perforating. Details of the diagnosis, planning, execution and evaluation phases of this project are described. The resulting gas production and zero perforation skin represented more than a two-fold productivity increase compared with the target reservoir average well production. These results demonstrate the effectiveness of the technique under borderline conditions, and promote its application in similar scenarios worldwide. This project shows the importance of production and perforating diagnosis, leveraging technology application and pushing the limit of dynamic underbalanced perforating in order to increase productivity in mature/low pressure assets. Introduction Perforating can be defined as the process of connecting the well with the reservoir by creating a tunnel which goes through the casing, cement sheath and the reservoir rock. The main objective of perforating is to create a clean tunnel sufficiently long that it reaches the undamaged reservoir. This process is fundamental to the productivity of the well; however, its importance is often overlooked during completion operations. It was recognized that perforating was an area that could be improved in Anaco District well completions. As a result, a qualitative evaluation of conventional perforating performance was done. This evaluation confirmed the link between poor well productivity and perforating and justified the field trials of new technology in this area. Most of the perforating technology developments have been focused on obtaining deeper penetrations. However, few breakthrough advances have been achieved relating to tunnel quality. The industry has relied solely on static underbalance, which is now a well recognized technique for perforation cleanup. The appropriate level of static underbalance has been extensively researched1,2,3; however, more recent investigations4,5 have presented relevant evidence indicating that static underbalance is not the only governing factor in effective perforation cleanup.