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Abstract Over the past years the usage of coiled tubing as a prefer method to deploy long and heavy guns in highly deviated wells has been widely spread in the oil industry to provide a single run without killing the well, perforate in underbalance conditions, reduce risks and improve job efficiency. The three wells are located in the Caspian Sea. In two wells, the objective was to isolate lower intervals and perforate a new zone through tubing and casing between two packers. On the other well, the objective was to perforate a new interval through casing after running a new completion and isolate lower production zones. Due to the challenges involving gross length of the new intervals, guns size, well deviation and live deployment needs several techniques were evaluated. The best approach was to use an Advance Live-Well Deployment (ALWD) system to deploy and retrieve the guns with a tube wire-enabled Coiled Tubing Telemetry (CTT) system focus on both safety and cost saving compare with conventional wireline perforating. Extensive job planning involved coiled tubing (CT) simulations to reach target depths, shock loading modeling to ensure forces are within CT string limitations, system integration test to verify deployment/reverse technique procedure and system communication to electrically activate guns. CTT integrated sensor assembly was used during deployment/reverse operation with a tension, compression and torque (TCT) sub-assembly to monitor accurate upward/downward forces. In addition, CTT logging adapter assembly was used for depth correlation and electrical guns activation. The ALWD system; composed by connectors and deployment blow out preventor (BOP), prove to be an efficient way to run, perforate and retrieve gross intervals of 212 m, 246 m and 104 m with guns successfully. During all these jobs several lessons learnt were created in order to improve the deployment/reverse procedure for future jobs including not only operational steps but also deployment/reverse bottom-hole assembly (BHA) configurations. Based on the success of these case histories, the ALWD combined with CTT system has been proven to be the preferred method when dealing with long perforation intervals in life well conditions, thru-tubing environment.
Summary The success of water‐conformance operations often depends on clear identification of the water‐production mechanism. Such an assessment can be complicated significantly when formation damage is also occurring. Coiled tubing (CT) and distributed‐temperature sensing (DTS) were combined to overcome challenging conditions (high temperature, low injectivity, high deviation, long perforated intervals, and wellbore damage) to identify damaged oil zones and suspected water‐bearing zones in an onshore well in Japan. The subject well experienced unexpected contamination of oil‐based mud (OBM) and completion brine, which generated tight emulsions in the wellbore during the completion phase. Despite a thorough cleanout and perforations, severe damage was observed and mostly water was produced. With the presence of persistent damage in the wellbore preventing any logging‐tool use, DTS was selected as main diagnostic method, with the fiber optics being deployed with CT to ensure full coverage of the interval. Acquired temperature surveys were processed and matched with simulated profiles, which tested various scenarios of damage. Ultimately, results were used to drive the design of remedial actions. The following operational sequence was implemented: temperature‐baseline measurements (6 hours), brine bullheading through the CT/tubing annulus at 0.2 bbl/min (22 hours), and shut‐in (6 hours) for warmback. The long injection stage was required to ensure that enough fluid was being injected across the entire interval while keeping the downhole pressure at less than the fracturing pressure. Real‐time DTS data during pumping and warmback indicated the presence of a main intake zone in the middle of the interval. Below that section, only marginal temperature changes were observed, which might be a direct consequence of the low‐injection‐rate limitation. Post‐job processing using numerical temperature simulation was performed to complement that analysis and quantify intake along the well. Temperature inversion against the DTS response was conducted independently using two different simulators, both of which yielded similar profiles, confirming the soundness of this approach. The results supported the presence of a larger intake in the middle interval and also showed that the bottom zone most likely took some fluid. Complementary information eventually pointed to the larger‐intake interval being the primary water‐bearing zone. This analysis led to the selection of the remedial actions to be performed in damaged oil zones. This study demonstrates how integrated use of data from design to job execution to interpretation can change the perception of a well and how DTS can be a viable alternative to damage and water‐production diagnostics in some extreme conditions when production‐logging tools (PLTs) cannot be used. Results of the DTS quantitative analysis provided local damage profiles along the well, which were critical to the subsequent planning of remedial activities.
Al Matar, Mohammed (KOC) | Mohapatra, Samarendra (KOC) | Al-Ateeqi, Hamad (KOC) | Gaur, Rishika (Halliburton) | Chawla, Sapna (Halliburton) | Khandelwal, Nakul (Halliburton) | Almesfer, Mohammad (Halliburton) | Gorgi, Sam (Halliburton)
Abstract Increasing water cut and well integrity are currently major concerns, particularly in mature fields. Excessive water production can detrimentally affect the profitability of hydrocarbon-producing wells if not controlled properly. This paper describes a successful zonal isolation case study in a dual-string completion well with well integrity challenges and variable permeability intervals using a modified organically crosslinked polymer (m-OCP) and coiled tubing (CT)-assisted real-time temperature sensing for effective placement and post-operation evaluation. The m-OCP system is a combination of a thermally activated, organically crosslinked polymer and particulate material for leakoff control to help ensure shallow matrix penetration. It is acid resistant, H2S tolerant, has controlled penetration, and is easy to clean up using a rotating wash nozzle. The setting time can be accurately predicted with simple laboratory tests. These characteristics make this system the preferred choice compared to the traditional cement squeeze method that is both time consuming and exorbitant. Diagnostic services delivered by CT-conveyed fiber-optic distributed temperature sensing (DTS) that add real-time capabilities to monitor well integrity assess reservoir performance and visualize treatment efficiency. Using real-time diagnostic services, tubing integrity was confirmed, and the treatment was placed in the same run, helping eliminate the possibility of an undesired leakoff. After allowing the setting time, a successful pressure test or post-cleanout DTS (in case pressure test is not feasible) was used to establish the reliability of this method. The first attempt was made on Well A of the field; however, isolation was successful using m-OCP and conventional CT. Operation execution and production recovery took more time than planned because of the uncertainty concerning well integrity in the dual-string completion and lost circulation in the depleted reservoir, which affected the economic deliverability of the operation. The major challenges with Well B of the same type in the same field remain the same. Thus, as part of lessons learned from the previous intervention, diagnostic services were chosen for a real-time evaluation of the completion to review well integrity and accurately place the optimized treatment, thereby helping improve overall results in the most time-saving and lucrative manner. The successful isolation of the water-producing zone/perforations in the southeast Kuwait field using m-OCP and CT-assisted real-time DTS to review well integrity can be considered a best practice for addressing similar challenges globally.
For more than 50 years, coiled tubing (CT) has been an intervention technology used primarily to maintain or increase production. In the last 10 years, CT telemetry systems have been used for such applications as milling, stimulation, well cleanouts, gas lifting, camera services, logging, and perforating. These systems have resulted in increased certainty, improved safety and efficiency, and reduced time and cost. In this article, a review of a CT telemetry system with 0.125-in. tube wire, including the technology development and field applications, is presented for the first time.
Unlike conventional CT for which surface-measured parameters, such as CT weight and length and pumping pressure, are the only parameters available to monitor the operation’s progress, CT telemetry systems provide real-time monitoring of downhole data such as pressure, temperature, depth, and others. The CT telemetry system described in this article consists of the surface hardware and software, a 0.125-in. tube wire inside the CT connecting the surface equipment and the downhole tools and sensors, and a versatile bottomhole assembly (BHA), designed in three sizes (i.e., 2.125-, 2.875-, and 3.5-in.). The 0.125-in. tube wire has the dual purpose of powering the downhole sensors and transferring the real-time downhole data to the surface. The sensors available are a casing-collar locator (CCL), two pressure and temperature transducers (capable of measuring downhole data inside and outside the BHA), and tension, compression, and torque gauges. In addition, cameras with front and lateral views and flow-through capabilities could be used. One of the advantages of this CT telemetry system is its versatility: Switching between applications is as simple as changing parts of the BHA, significantly reducing the operational time and cost, and increasing safety. Another advantage stems from the acquisition of real-time downhole data, enabling the CT field crew to intervene promptly on the basis of dynamic downhole events.
A state-of-the-technology review of the 0.125-in. tube-wire CT telemetry system is presented for the first time. The many benefits of the real-time monitoring of the downhole parameters during such CT applications are summarized. These applications include logging, zonal isolation, collapsed-casing identification, scale removal, cleanout and perforation, milling, confirmation of jar activation during fishing jobs, and others. Many of these applications were performed together, and the real-time monitoring of downhole data increased the job efficiency, control, and safety, and reduced the operational costs by simplifying the operational procedures and equipment.
The article summarizes the results stemming from 10 years of global experience with the 0.125-in. tube-wire CT telemetry system. A new case history involving the 0.125-in. tube-wire CT telemetry system and a vibratory tool is also presented for the first time. With the current trends to automate drilling operations, the details presented in this article show that the CT telemetry systems are poised to become standard technologies for all CT operations in the not-so-distant future.
Abstract A successful evaluation and development program in a tight gas-bearing formation requires considerable analysis, not to mention optimization to help ensure a profitable income. In time where problems arise and impact the performance of the well during completion, the risks of well intervention increase significantly. These problems sometimes are not allowing a hydraulic fracturing treatment to be performed. In a situation where hydraulic fracturing treatment is not feasible, an optimized stimulation design is needed to guarantee commercial gas production from the well within current completion constraints and allocated budget. In the attempt to find an economical yet effective stimulation solution, the hydrajet fracturing process was chosen to be implemented. This stimulation technique has a proven success rate in onshore applications. To increase the treatment efficiency, a novel acid-soluble abrasive material was used to connect the reservoir to the wellbore, which helped avoid sand cleanout time and use of additional chemicals. It was followed by a pinpoint acid stimulation to unlock the hydrocarbons in a low-pressure area of the reservoir. The post-treatment result showed a very promising result with the gas rate achieved, which was approximately double the rate expected by a conventional bullhead acid fracturing treatment. This has demonstrated the value that the technique brought to the industry. This paper discusses not only the result of the technique compared to wells that are completed and evaluated with different completion schemes, but also presents a best practice for the method used to stimulate a well. The success of this operation resulted in providing an alternative to completing their requirements relatively faster and more cost-effectively.
Abstract Well commissioning operations offshore encounter multiple organizational, operational and technical challenges that must be safely overcome to efficiently deliver high-quality service. Coiled tubing (CT) perforation and commissioning performed in hostile reservoir conditions and high pressure is one of the most complicated multiservice operations, especially in a sensitive aquifer ecosystem like the shallow Caspian basin. A comprehensive approach used to deploy an innovative solution to the challenges provided experience in such operations and lessons learned. An innovative perforation technique was selected for the project: electric-line-enabled CT for precise depth control in combination with an advanced gun deployment system for conveyance of long gun strings under pressure. New techniques were incorporated to improve equipment efficiency and reliability: detonation shock-resistant bottomhole assembly, two independent emergency disconnects, software to predict and evaluate shock load and dynamic underbalance, high-pressure H2S-rated and conventional connectors for a specialized tool deployment stack (TDS), rounded scallop guns, and high-tensile CT logging-head-disconnect weak points. To date, more than 10 well commissioning operations were successfully completed with this innovative method. Integrated service project management was a key approach to achieving successful results by effectively integrating multiple service lines. The technique proved to effectively minimize operational time, associated risks, improper equipment use, and interface failures between different service lines. The developed solution is a seamless integration of electric-line-enabled CT, the CT logging head, the gun deployment system for pressurized well conditions, and a set of wireline tools and specialized perforation equipment. The design was optimized to perforate the well in three or four runs at overbalanced condition (squeeze mode) in one rig-up job instead of the more than 20 wireline runs typical in conventional operations. Additionally, the use of CT provided the flexibility to perform pumping operations for well displacement, injection of an H2S scavenger, and stimulation, as per the operator's plan, without or with only partial rig-down. This was the first time that integrated service project with the described CT perforation technique was performed in the Caspian region. The acquired experience will facilitate design, preparation, and execution stages for such type of jobs with multiple services involved.
Koshy, N. S. (Cairn India Limited) | Anand, S. (Cairn India Limited) | Patil, B. (Cairn India Limited) | Singhal, A. (Cairn India Limited) | Chandak, K. B. (Cairn India Limited) | Vadapally, S. V. (Cairn India Limited) | Sabharwal, V. (Cairn India Limited)
Abstract Ravva is a mature field located offshore east coast of India with over 20 years of production history from Middle Miocene sandstone reservoirs. During the development phase of the field, Late Miocene (LM) sands were intersected in few wells at shallow depths. Due to the presence of more promising and critical zones below, these sands were not completed and fell above the production packer and behind the production casing. The marginal reserves in these sands did not justify workover operation to complete it. Rigless options were studied and a shut-in well was selected for implementation. In order to safely complete and access the bypassed shallow sands, a vessel based pumping operation was planned to place a cement packer in the tubing – casing annulus. The slurry was circulated into the production casing/tubing annulus through a circulation SSD installed above the production packer.The cement packer was thus placed across the zone of interest. Designing of the cement slurry was based on reservoir parameters and the setting time was optimized to prevent reversing of the slurry back into the tubing. The cement mix had a bonding agent to exhibit good metal-cement bonding providing prolonged endurance of the cement with the capability of holding the expected pressure differential. The cement packer emulated a production packer providing zonal isolation for the new completion. Size of the platform precluded spotting of the complete Coil Tubing spread on the platform. High cost prohibited catenary coil tubing operations. As an alternative, the pump spread was placed on a DP vessel and the coil tubing unit was spotted on the platform. A high pressure hose running up from the vessel to a standpipe on the main deck of the platform formed the main conduit for fluids being pumped from the vessel into the CT or wells. Onsite mixing of the cement slurry on the vessel required detailed planning and execution. The well was activated & tested at rates of 1500 bopd with no integrity concerns till date. This paper will emphasize on the operational procedure and challenges of successfully completing the zone and bringing the shut-in well online. The execution of this operation was done at 1/10th of the cost of a rig based workover. This has also opened up new opportunities to access similar bypassed reserves resulting in incremental production from reservoirs which would have otherwise been left untapped.
Inda Lopez, A.. (PEMEX) | Inda Herrera, L. A. (PEMEX) | Soto Lopez, E. O. (PEMEX) | Ramondenc, P.. (Schlumberger) | Murillo Vallejo, A. L. (Schlumberger) | Rosado Rivero, I.. (Schlumberger) | Worden, S.. (Schlumberger)
Abstract Mexico has long based its strength on the exploitation of its offshore fields to become one of the largest oil producers in the world. Although still yielding most of its production today, those mature fields have entered a downward trend for the past few years, with a gradual decline of their hydrocarbon output. This trend coincided with an increase in work over operations, most of them involving matrix acidizing interventions in carbonate formations for damage removal and stimulation purposes. Matrix stimulation of offshore Mexico fields presents several challenges, starting with the very nature of the carbonate rocks composing the reservoirs, whose properties can greatly vary within a short distance. In addition, the well conditions are also at times not well understood, with perforated intervals heterogeneously producing, and the increasing occurrence of water production. Finally, due to the location offshore, time-efficiency and operational simplicity became important workover requirements that have a direct impact on the chosen stimulation procedure, often achieved using a simple bullheading sequence, which unfortunately leaves the much needed control of zonal coverage out of the equation. This paper presents a carbonate acidizing workflow and interpretation method that have been developed and successfully implemented in offshore Mexico over the past couple of years. This technique constitutes the cornerstone to assessing and controlling matrix acidizing treatment coverage while it is pumped, in real-time, to ensure optimum treatment performance and maximum return on costs. The workflow relies on the use of a fiber-optic line enclosed inside a coiled tubing (CT) string to acquire distributed temperature sensing data, which are analyzed and translated into a zonal coverage profile using a fast interpretation algorithm. This information then allows stimulation engineers to determine the best strategy for the subsequent well stimulation treatment, including fluid volumes and placement sequence. As the case studies presented in this study will show, there is a lot to gain from this improved methodology. In particular, they show that the long-standing blind bullheading practice results in some shortcomings that may be detrimental to truly unlocking the full potential of those offshore fields.
A new lightweight, small-footprint coiled tubing unit (CTU) has been developed to enable CT for a broad spectrum of well service applications. The technology could substantially reduce well intervention costs, logistical support and risk exposure and can be applied to operating environments worldwide, both onshore and offshore. Wells that were once considered plug-and-abandon candidates due to cost, technical challenges or accessibility may now be candidates for small CTU solutions. The motivation for one Malaysia operator to use the small CTU was the limited operating capability of their platform i.e. small crane and limited deck space / weight restrictions. A lower zone in one of the operator's wells became inaccessible after damage occurred to a permanent tubing patch used to abandon an upper zone. Intervention methods were narrowed down to the small CTU or tractor-deployed milling. The small CTU was chosen to perform milling runs with 1-in. CT and motor. After several milling passes through the 2.2-in. ID tubing patch, access to the lower zone was accomplished. Perforation on slickline was unsuccessful and the 1–11/16-in. perforating guns were then successfully deployed on the 1-in. CT and the well perforated. Numerous challenges will be reviewed including work with small 1-in. OD pipe, small motors and working inside a restricted completion with high dogleg severity and 70 degree hole angle. A total of 23 runs, including 14 perforation runs, were performed and the entire job was completed safely and without any major issues in 20 days. The intervention was extremely successful with the well coming online at 15 MMSCFG/day. The intervention has allowed the operator to recover reserves that would have otherwise been abandoned due to expensive workover costs. Additionally, this job is the first of its kind ever performed in Malaysia and has opened up additional opportunities in shallow or deepwater installations.
Abstract The appraisal of deep tight gas reservoirs can be technically and economically challenging, with success dependent on applying the most efficient completion technology. Inevitably, this includes designing well completions that encompass the deployment of multiple hydraulic fracturing treatments. There is a tendency in the completion design phase to under-assess the number and variety of interventions that a well could undergo during its evaluation. Subsequently, the development and application of the appropriate well intervention strategy is crucial in maximizing the well potential and reservoir understanding. The deliverable of any tight gas appraisal program is to increase the level of confidence in continuing to pursue the resource opportunity by demonstrating stable and sustainable gas inflow flow rates. Recent drilling success targeting deep frontier gas reservoirs, such as the Amin located in the central part of Oman, have resulted in the need to evolve the well intervention process to include several new (for the region) technologies. These included the deployment of abrasive perforating to facilitate the initial formation breakdown operations, milling out the shoe track for a hydraulic fracturing treatment in an openhole setting, restoring full wellbore access by milling out multiple frac plugs, and temporary installation of a velocity string to eliminate liquid loading issues. Historically, many of these individual processes have been attempted or deployed with varying levels of success, but this is the first time that they have been integrated into a well strategy. This paper summarizes the process of selecting the best options for well intervention operations in low-permeability gas reservoirs. The integrated work design consideration and results of these completion techniques will be presented along with the key learnings derived from the process.