Efficiency and effectiveness are strong influencing factors when developing rigless interventions within the current market. In the demanding industry of exploration and production (E&P), a synergy was created from strong collaborations between operator and service companies searching for solutions to provide more diagnostic capabilities, reduce overall cost of operations, and maximize well performance. The solution was found in real-time hybrid coiled tubing (CT) services, which drastically increased reliability and reduced assets and wasted time on location. Two onshore CT well interventions in the eastern foothills of Colombia where challenging conditions (i.e., high gas-production rate, high tortuosity, and dogleg severity) were overcome using a real-time hybrid CT system are discussed. To optimize the operational time to run a production logging test (PLT) and obtain downhole visual conditions, it was necessary to, in a single run, combine a flow-through, multisided, high-resolution visualization camera (first in industry) with real-time wireline services and a hybrid bottomhole assembly (BHA). The real-time hybrid integrated system includes a cable to connect any wireline tool and multiple fibers for communicating with additional sensors (i.e., tension and compression) to avoid exceeding the wireline tools’ capabilities, casing collar locator (CCL), and/or gamma ray (GR) sensor. These then correlate as a backup of the logging tool while performing operations as a PLT or injection logging test (ILT) and smarter tools (i.e., downhole multisided camera) that evaluate the perforations and fractures within the desired zones. This occurs in a single CT rig up without the need to modify the hybrid BHA, CT string, or CT connector and reduces the shut-in period of the well because CT and BHA capabilities provide more downhole insight. The hybrid flow-through sensor and camera BHA communication use the fibers installed in the CT; wireline uses the electric path for its telemetry. Because tool communication is independent, data can be evaluated simultaneously without constraints during the same run and pass, helping reduce additional operations because everything is transmitted from downhole, recorded, and displayed at surface the same time the tool senses or sees it. In an industry that demands continuous improvement during each stage of a well, increasing efficiency, reducing operational time, and developing technologies and techniques without compromising safety is no longer a request—it is now mandatory. This technology provides the benefits of fiber-optic and electric cable together and near limitless freedom to deploy multiple technologies independently or simultaneously without interference—a solution only an open architecture system can provide, establishing a step forward within the industry.
This paper presents a cement-evaluation workflow that encompasses the use of multiple measurement thresholds, proving that data processing with the use of logical discriminators can determine true cement-bond conditions with the use of conventional diagnostic tools.The algorithm filters raw and derivative acoustic data through various predetermined thresholds to discriminate well intervals that possess proper cement bond and vertical coverage. Should data associated with a well interval pass through all the chosen logical filters, the interval is flagged as having the necessary cement presence and bond to be considered an isolating annular barrier. The logical thresholds are operator-defined, enabling a customizable assessment of any cement type, regardless of operator standards, legal codes, or environmental regulations.The service was recently implemented in various wells where the customer required a decisive assessment to determine if a cement bond was minimally present prior to proceeding with abandonment. Their previous experiences with well-integrity diagnostics had resulted in contradictory information, requiring additional intervention work to help ensure zonal isolation. The interpretation workflow was able to indicate the presence of a minimum 11 ft of continuous cement and 100 ft of total cement behind the 7 5/8-in. OD production casing, which was one of the customer's well-integrity standards. The processed acoustic response, acquired with a cement-bond log tool and ultrasonic scanner, is presented in binary form, which clearly distinguished several intervals where annular cement complied with the various technical and legal variables that the client adopted.By eliminating the inconclusive nature inherent to cement evaluation, the new interpretation solution can rapidly serve operators with a simplified result, enabling faster decision making to determine whether or not remedial work is required. This routine can be especially valuable to asset decommissioning and new well drilling, where more assertive decisions regarding well-barrier integrity can result in operational efficiencies.
Discover a Career The substantial reduction in global oil prices has put the oil and gas community in a challenging and yet vaguely familiar position. It is once again reminded of the effect oil and gas prices have on companies working to profitably exploit these resources. When there are changes in prices, reserves estimation can dictate the profitability an operator can ultimately obtain. Larry Mizzau, principal for reserves and resources governance at Cenovus Energy reflects on his 30-plus years of experience in the industry and shares his thoughts on how commodity prices impact operators, reserves consultants, and young professionals (YPs) looking to establish a career in reserves estimation. What is reserves estimation? Reserves estimation is a key step in understanding an oil and gas company’s resource base and the opportunities it affords. It is found at the crossroads between asset management and financial stewardship. It involves the estimation of remaining volumes of hydrocarbons economically recoverable from an oil and gas operator’s subsurface assets using current technology. Given that reserves exist deep in the ground, they cannot be determined with absolute certainty and, as such, can only be estimated. To assist investors in understanding this uncertainty, reserves estimates are typically determined at different confidence levels. In Canada and the United States, public operating companies must disclose an updated estimate of their remaining oil and gas reserves on a yearly basis as part of their yearend financial reporting. Specifically in Canada, operators are required to disclose assessments prepared or audited by independent qualified reserves evaluators (IQREs) who can be externally or internally retained by the company.
Hydraulic fracturing and horizontal drilling have catalyzed the recent United States (US) hydrocarbon production "renaissance," spearheaded by unconventional asset development. The increase in oilfield activity, however, has exposed groundwater contamination as a potential environmental concern associated with the use of these two technologies. Government and state agencies have revisited regulations to help ensure well integrity, but operational success is currently limited because of tool deployment and centralization issues in horizontal wellbores. The combination of acoustic logging and conveyance technologies with field engineering insight has created a unique solution to well integrity monitoring in horizontal well intervals. Various successful logging services have been performed in wells producing from the Marcellus shale play in Pennsylvania. A well operator needed to determine proper cement placement between different fracturing stages to avoid unwanted fluid movement throughout the wellbore annulus. The logging tool string, composed of ultrasonic scanning and cement bond log (CBL) tools, was transported through the horizontal wellbore using a tractoring device. Tool centralization, which is critical to accurate operation of acoustic tools, is difficult to achieve in horizontal wellbores because of the influence of gravity and friction forces. This challenge was overcome by integrating centralization equipment for additional tool support while maintaining wireline tension limits. This case study discusses the operational background and challenge, creation of this innovative tool setup, and the effects this service will have on performing successful well integrity monitoring in additional unconventional horizontal wells.
Production logging is a necessity in today’s deep and complex reservoirs, where high-production and extreme downhole conditions (including high pressure high temperature (HPHT), carbon dioxide, and hydrogen sulfide) require constant monitoring of well performance. This service can be combined with other cased hole logs, such as tubing evaluation and pulsed neutron, to establish a customized relationship between the fluid, wellbore, and completion properties. This process enables the construction of an instantaneous relationship between these three elements and determines the efficient production of each well. This service integration was successfully applied in a deep gas condensate well in southeastern Bolivia. With more than 5200 m of total depth and a wellhead pressure of 5,500 psi, the operating conditions proved to be difficult. However, they proved ideal for the use of memory logging tools that, when deployed downhole with slickline wire, facilitated surface pressure control without risking log quality assurance/quality control (QA/QC). Producing at a high flow rate (> 100 MMscf/d) from three reservoirs, the well required constant flow profiling and production follow-up. In addition, the presence of carbon dioxide in the gaseous stream provided opportunities for weakening the mechanical integrity of the completion through the onset of corrosional events. After running a production log, the client discovered an unexpected fluid entry point in the completion string, which was confirmed as an orifice with a subsequent tubing evaluation logging run. After reviewing the original production log, the client determined that the high flow rate from a particular formation had eroded a blast joint and created the orifice. Running these services with memory tools reduced preparation time and operating costs. These benefits enabled the client to quickly acquire detailed information about the downhole condition of the well, improve the understanding of the relationship between reservoir and completion, and reduce production downtime and service costs.
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