Wellbore integrity issues, including casing leaks and poor zonal isolation behind the casing, present a tremendous challenge to conventional cement slurries when dealing with low injectivity, pressure restrictions, pin-hole leaks, and/or a primary cementing microannulus, among others. If the conditions of these near-wellbore (NWB) issues exceed the capabilities of conventional cement slurries, alternative methods might be necessary. This paper presents the field implementation of an organically crosslinked conformance polymer sealant (CPS) system used successfully to address these wellbore integrity challenges. Although it is not a replacement for cement slurries in all situations, the CPS system provides an alternative chemical and engineering solution for treating NWB problems in special circumstances. The CPS system uses a copolymer of acrylamide and t-butyl acrylate (PAtBA) crosslinked with polyethyleneimine (PEI). The CPS system is injected into the formation and void spaces as a low viscosity solution that activates at a predicted time to form a hydrogel to completely shut off matrix permeability, fractures, fissures, and/or channels. This system has been successfully tested to withstand a differential pressure of at least 2,600 psi, has a working temperature range of 40 to 400°F, and is resistant to acid, CO2, and H2S environments. The CPS system does not develop any compressive strength, which simplifies the cleanup stage by easily jetting it out of the wellbore, opposed to cement that has to be milled out, which becomes increasingly challenging at shallow depths and/or in highly deviated wells. To date, more than 1,000 CPS system treatments have been performed globally to address conformance problems, such as water coning/cresting, high-permeability streaks, gravel-pack isolation, and/or fracture shutoff. In this paper, case histories related to casing-leak repair, annular flow between pipes, and poor zonal isolation behind the casing are presented. Additionally, lessons learned from the diagnostic stages of both offshore and inland case histories are highlighted.

Sand production is one of the major challenges for mature fields in Austria. With increasing water production, the severity of the sand migration augments, leading to the shut-in of the wells. Eliminating or substantially reducing sand production at the sand face is the most viable option to continue hydrocarbon production. The project's target was to research and apply a technically sound solution readily available in Europe, with reduced HSSE risks and little economic impact. To control intervention costs, it was decided to favor sand control solutions for rig-less interventions. Collaboratively, the teams evaluated formation rock consolidation with the help of an internally catalyzed aqueous-based emulsion of curable epoxy resin (ICABECER). Laboratory testing demonstrated the system's suitability for the target wells and confirmed the viability of the planned operations scheduled to deploy the treatment via coiled tubing (CT), as well as limiting concerns about permeability reduction. Finally, field operations of the application, clean-up, and production face were monitored and evaluated. The major concern when using resins to agglomerate sand grains in a reservoir rock is that the pore space is reduced, jeopardizing the rock permeability. Laboratory testing confirmed that the permeability of the rock can be retained. Due to the simplicity of the intervention, the treatment could be deployed with standard equipment keeping it within the budgetary constraints of very mature fields. To mitigate possible risks, wells having challenging production backgrounds and scheduled for plug and abandon were selected. In these wells, previous conventional sand control measures failed, such as gravel pack installations or attempting to produce sand and separate it on surface. Post-job results demonstrated that the in-situ consolidation generated a reduction of sand content to a level allowing production of the wells. During the clean-up period of the gas well, sufficient sand was produced to erode the choke. After the well start-up period, sand production was eliminated, and the well was returned to the target rate. Monitoring of solid contents in the flow and the evaluation of coupons confirmed the suitability of the technique to establish flow with acceptable risks contributing to economic success. The cost-effective ICABECER chemical treatment, along with the methodology, opens new opportunities for the asset to prolong well life and increase the overall recovery factor from the reservoir. Technical simplicity and the reduced environmental impact of the chemicals are key for resource-saving and sustainable operations in mature fields.

Unconsolidated fine formation sand in mature Austrian gas fields jeopardizes production rates and well productivity as increasing water cut enhances fines and sand production to the well bore. The wells peak production was years ago, making well intervention challenging to stay within tight economic limits. Stabilizing the formation rock with aqueous-based resin eliminated sand production and reduced intervention costs to restore target rates. To remain within economical budget levels for the projects, engineering-focused its research on treatments that can be applied rig-less and are suitable for the Austrian gas field reservoir parameters with moderately low temperatures, reasonable interval length, depleted reservoir pressure, and dis-stacked perforations. Team collaboration resulted in proposing a rock consolidation treatment with an Internally Catalyzed Aqueous-Based Emulsion of Curable Epoxy Resin (ICABECER). Thorough planning and pre-job lab testing reduced operational risks, saved costs, and optimized outcomes. The placement technique and displacement precautions resulted in reservoir rock without notable flow path reduction, allowing quickly anticipated target rates to be reached. The treatment outcome confirmed laboratory testing where rock permeability was retained, and only small amounts of residue sand were produced during the cleanup period. The intervention's simplicity allowed using standard field equipment, minimizing cost, and calculating a business case according to tight budgetary constraints. The wells, scheduled for plug and abandon because of pretreatment sand production, demonstrated a stable gas flow with reduced sand content enabling economic gas production. During the cleanup period, sufficient sand was produced to erode surface equipment; however, after the start-up period, sand production was reduced to zero, and the well was returned to the target rate. The technical simplicity of the chemical treatment and a collaboratively engineered and optimized application open new opportunities for the asset to reduce or eliminate sand production without the need for expensive sand control installations at the sand face. Furthermore, the chemical reservoir rock stabilization prolongs well life and increases the overall recovery factor. Reducing environmental impact is also key for resource-saving and sustainable operations in mature fields.

Historically, the preferred method for restoring production on oil producers in a mature field in South Europe (Field A) was bullheading a matrix acid stimulation treatment. Even if successfully implemented, bullheading treatments at matrix rate are not always optimum and, for Well A, it was decided to diagnose the producing interval first to deliver a better selective stimulation treatment through coiled tubing (CT). This paper presents a novel approach implemented and discusses its associated benefits. Real-time (RT) fiber-optic (FO) CT (RTFOCT) technology was selected to diagnose this well for such benefits. These include accessibility of the producing zone (horizontal section), pumping capabilities, and versatility in executing different well interventions using single equipment. The technology is composed of a FO cable preinstalled into the CT pipe and a modular sensing bottomhole assembly (BHA). In addition to be the telemetry medium for the sensing BHA, the FO can be used as a sensor for distributed temperature and acoustic sensing (DTS and DAS). Having access to downhole information in RT helped to implement the decision-making process more quickly. DTS and DAS were used to evaluate the reservoir performance before perforating and assessing well performance, post perforation and stimulation. The sensing BHA helped ensure accurate placement of the perforations and stimulation treatment using a RT casing collar locator (CCL) and gamma ray (GR). Monitoring the bottomhole tension and compression allowed the operation to be performed in a safer and more reliable environment. RTFOCT allows interval diagnostics, stimulation treatment, and evaluation in a single CT run. Having the RTFOCT available also allows quick reaction to unexpected well problems, making diagnosis and remediation easier and faster. Moreover, one of the main goals for well monitoring and field management consists of production optimization activities designed to decrease Water Cut (WC). This has been made possible thanks to the detailed downhole dynamic characterization of the specific water flooding zones coming from RTFOCT, which allows Operator to stimulate the matrix in the right zone to enhance well performance, as well as design focused Water Shut-Off (WSO) interventions. The focus of the paper lies in the capabilities of the Operators to effectively manage this new tool in order to perform downhole analyses in real-time. This enables potentially problematic or complex scenarios to be identified early on, allowing time to react before they fully develop, thus increasing the percentage of success of the planned job, as experienced in the case study presented.

Water production has always afflicted mature fields due to the uneconomical nature of high water cut (WC) wells and the high cost of water management. Rigless coiled tubing (CT) interventions with increasingly articulated operating procedures are the key to a successful water reduction. In the scenario presented in this paper, high technological through tubing water shut off (WSO) for a long horizontal open hole (OH) well in a naturally fractured carbonate reservoir leads the way to new opportunities of production optimization. Engineering phase included sealant fluid re-design: the peculiar well architecture and fracture systems led to the customization of a sealant gel by modifying its rheological properties through laboratory tests, to improve effectiveness of worksite operations. A new ad-hoc procedure was defined, with a new selective pumping and testing technique tailored to each drain fracture. The use of Real-Time Hybrid Coiled Tubing Services (CT with fiber optic system coupled with real time capabilities of an electric cable) made it possible to optimize intervention reliability. Details of the operating procedure are given, with the aim of ensuring a successful outcome of the overall treatment Sealing gels are effective in plugging the formation, but in fractured environments the risk of losing the product before it starts to build viscosity is high. The success of the water shut off job has been obtained by using specific gel with thixotropic properties for an effective placement. In addition, the pumping has been performed in steps, each followed by a pressure test to assess the effectiveness of the plugging. Results are compared to two past interventions with equal scope in the same well: a first one with high volume of gel and an unoptimized pumping technique through CT and a second where a water reactive product was pumped by bullheading. The selective and repetitive approach pumping multiple batches of sealant system with CT stationary in front of a single fracture provided the best results from all three techniques. The real-time bottom hole data reading capability provided by hybrid CT allowed the placement of thru tubing bridge plugs (BP) with high accuracy and confidence with the ability to set electrically, therefore reducing risks related to hydraulic setting tools (i.e. premature setting). This also allows continual pumping during the run in hole (RIH) to clean up the zone prior to setting the BP. The combination of this innovative pumping technique and customization of the sealant fluid made it possible to achieve unprecedented water reduction in the field. The high technology CT supported the operation by providing continuous power and telemetry to the bottom hole assembly (BHA) for real time (RT) downhole diagnostics. Moreover, the operating procedures offer basic guidelines to successfully perform water shut off jobs in any other reservoir independent of its geological nature and structure.