No abstract

The largest active onshore field in Western Europe produces crude from 20 long horizontal wells from a naturally fractured carbonate reservoir. The produced crude deposited asphaltenes in tubing, openhole sections, and slotted liners. Over time, the deposition became so severe that it involved the reservoir fractures, affected well productivity, and caused a premature fieldproduction decline. Removing the formation damage, therefore, became a priority for appropriate field management.The injection of asphaltene inhibitors at packer depth reduced asphaltene deposition in tubing but did not protect the long openhole or the natural fractures from plugging. Bullheading or coiled-tubing (CT) solvent treatments were frequently performed with limited benefits.In 2009, an extensive asphaltene cleanout campaign was performed with more aggressive solvent treatments, covering almost 70% of producing wells. Continuous post-treatment-analysis improved the stimulation effectiveness and optimizing the dissolving fluids led to a production increase per treated well of 500 to 3,500 bbl crude per day. Unfortunately, the treatment techniques applied did not allow sustained production increase unless well interventions were frequent, up to bi-monthly.To reduce the treatment frequency, an emulsified-acid treatment was performed. The innovative emulsion, where acid was emulsified in solvent, provided a delayed acid reaction and allowed live acid to penetrate deeper into the formation. This allowed the flow pattern to be changed in a way such that the asphaltene deposition was slowed down, and the high well production was sustained over a prolonged period. This paper describes the history of the treatment methods, the extensive asphaltene-cleanout campaign performed, the post-job analysis, stimulation-treatment improvements based on field experience, and the final novel application of an emulsified-acid treatment that sustained a prolonged production gain of more than 10,000 BOPD and recovered initial well productivity.

Distributed temperature sensing (DTS) is used on wells to determine the effectiveness of acid treatments. The technology uses a fiber-optic cable to read temperature in real-time, which allows for validation of fluid placement. In the case studies presented in this paper, effectiveness was determined during the pumping of the job. Using this process, the operator was able to decide if a change to the design needed to be made in real-time during pumping. The effectiveness of the acid job was dictated by how effective the fluid was placed into all zones. Concerns related to the acid treatments included where the acid was placed in the well, if the acid went where it was supposed to, and if the acid went into the first least-resistive zone and subsequent zones went untreated. If the latter took place, then investment capital for gallons of acid was not used wisely. The acid treatments included a wide variation of stimulation methods, such as stimulation of the formation using fracturing or matrix rates, varying the acid percentage, varying the type of acid, using linear, gelled, or crosslinked acid, varying the rate, and using diverters. Historically, on acid jobs, surface readings for pressure and rate were the only indicators to judge the effectiveness of the treatment. As the operator attempted the previously mentioned acid treatments and also monitored the treatment using DTS, it was observed that what is seen at the surface can be misleading. This is because surface pressure can be masked by friction and is therefore not a valid indictor for what occurred down hole, and because diversion can take place without surface indication. DTS allowed for practical adjustment to the diversion strategy for the well that was being treated. Candidate selection is highly recommended when using the DTS-number process. Placement of stimulation fluid was and is critical to well stimulation. DTS allowed real-time analysis to determine in real-time if stimulation was effective during the job.

No abstract

As things progress each year in the oil industry, there is a much greater emphasis on safety. Live well-intervention operations are challenging because of inherent risks and require detailed risk analysis and appropriate mitigation, such as redundant safety devices. This paper presents details of the development, testing, and successful field deployment of a newly designed safety valve that can be used on coiled tubing (CT), jointed tubing (JT), and CT-JT hybrid string applications. This safety valve, located at the junction of the CT and JT, is a key component of the CT-JT hybrid string. Once the CT is connected to the JT, the valve can be pressure actuated to close or open the flow path to the wellbore. This allows the hybrid string to be run in hole (RIH) and pulled out of hole (POOH) with complete wellbore-pressure control. Various methods can be used to activate the valve, such as using surface hand pumps, pressuring between blowout preventers (BOPs), or remotely with pressure differential downhole. Double-flapper check valves have typically been part of a standard well-intervention bottomhole assembly (BHA). However, integrity of these valves is always in question after heavy pumping operations, especially with sand-laden fluids. This new safety valve incorporates a protective sleeve that keeps the flapper assembly covered and in pristine condition in its normally open position, helping to ensure a more reliable seal on closure. Chemical compatibility of elastomers, along with low- and high-pressure sealing reliability, are some of the challenges involved with conventional designs. Considering these limitations, the new safety valve offers a true metal-to-metal, non-elastomeric, spherical-to-spherical, flapper-closure mechanism with low- and high-pressure sealing capability based on ISO 10432/API 14A specifications. The flapper valve is designed and manufactured based on award-winning subsurface safety-valve technology. The safety valve was virtually tested using computational fluid dynamics, followed by functional testing on a full-scale prototype. Validation testing for functional, pressure, and sealing capabilities was conducted at an API type test facility. The safety valve was subsequently deployed and successfully passed field-trial operations.