The method for study of vertical gas-liquid flow with foaming agent

The issue of operation water-cut and "self-kills" wells is one of major aspects in gas production. One of the methods of solving this problem is the introduction of foaming agent into the well. The effectiveness of these technologies requires a theoretical and experimental study of gas-liquid flow with surfactants. We have analyzed existing works and have found out that experimental research in this area was carried out at atmospheric pressure. At the same time, the pressure in the well varies with the length of the wellbore and can affect the properties of foaming agent. The article presents a description of a facility for the study of gas-liquid flows with foaming agents at different pressure values. A method of conducting experiments on the facility, simulating a section of the production tubing of a vertical gas well, has been developed. The relations allowing calculating the volume contents of the phases in the gas-liquid flow with surfactants are proposed.

Successful Remediation of Sustained Casing Pressures in Gas Cap Injector Wells with the Use of Flexible and Self Healing System

Several injection wells in Prudhoe Bay, Alaska exhibit sustained casing pressure (SCP) between the production tubing and the inner casing. The diagnostics on these wells have shown communication due to issues with casing leaks. Conventional cement systems have historically been used in coiled-tubing-delivered squeeze jobs to repair the leaks. However, even when these squeeze jobs are executed successfully, there is no guarantee in the short or long term that the annular communication is repaired. Many of these injector wells develop SCP in the range of 300-400 psi post-repair. It has been observed that the SCP development can reoccur immediately after annulus communication repair, or months to years after an injector well is put back on injection. Once SCP is developed the well cannot be operated further. A new generation of cement system was used to overcome the remedial challenge presented in these injector wells. This document provides the successful application of a specialized adaptive cement system conveyed to the problematic zone with the advantage of using coiled tubing equipment for optimum delivery of the remedial treatment.

Case History: Hydraulic Workover Unit Utilized to Recover Highly Corroded 30-Year Old Completion from a Live Gas Well in the United Arab Emirates

In the UAE, an Operator needed to perform a completion change out in a gas well, where the existing completion has been installed for over 30 years. Logging operations had revealed several leaks point in the production tubing due to corrosion. To rectify the situation, a Hydraulic Workover (HWO) Unit was proposed integrating a punch ram in the Blowout Preventer (BOP) Configuration to manage the bleed off of potential pressure trapped between the isolated sections of the completion at surface. This document describes how the highly corroded completion tubing with eleven retrievable plugs set in a live gas well was recovered. The HWO Unit was modified so that one of the cavities in the BOP stack was dressed with customized punch rams for five inch pipe, with the objective of allowing control of any potential leaks due to plug failure. The pressure relief operation could then be completed by means of punching the tubing in the controlled environment that a Stripping BOP Stack provides. This paper compiles the details of the BOP configuration and operating procedures to recover the completion by stripping out of the well and operating the punch rams with the snubbing unit. This includes the pre-job preparation required for a successful operation and the overall design with where to locate the collars and plugs for an accurate punch, and how to confirm that the plugs are holding the pressure to continue retrieving the next completion section. In the end, a safe operation was completed with zero incidents or down time allowing the intervention to continue to the next stage of recompleting the well and putting it back to production. The customer was able to get the well back to production with an alternative solution to what was initially considered, representing a significant cost and time saving.

Novel Application of Epoxy Resin to Eliminate Sustained Casing Pressure Without Costly Downhole Well Intervention - Case History from East Kalimantan, Indonesia

An operator recorded 1100 psi of sustained casing pressure between a 9-5/8" casing and a 3.5" production tubing annulus seven days after the cementing operation was completed for the 3.5" production tubing. A production logging run was performed, and results indicated gas was flowing from a zone 86 feet below the 9-5/8" casing shoe. As per the operator's standard, such a situation suggests subsequent well completion operations cannot be processed and must be remediated. The most common solution for such situations is to perforate and squeeze to ensure zonal isolation in the zone from which the gas is flowing. Due to the slim tubing size this operation can be difficult, and there exists a high risk of leaving set cement inside the 3.5" tubing. Furthermore, drilling would require extensive time with a coil tubing unit and in the worst case could lead to the loss of the well. To provide a dependable barrier for long term well integrity, a novel approach consisting of epoxy resin was discussed. A highly ductile, solids-free resin was designed and tailored to seal off communication from the gas source to surface. The void space in the annulus was estimated to be less than 5 bbl. An equipment package was prepared to mix and pump the resin into the annulus. Resin was pumped through the wellhead casing valve using a hesitation squeeze technique with the maximum surface pressure limited to 3000 psi. Once all resin was pumped, the casing valve was closed to allow enough time for the resin to build compressive strength. The job was planned to be performed in multiple stages consisting of smaller volumes. The job was completed in two stages, and the annular pressure was reduced. On the first job, 1 bbl of resin was mixed and injected into the annulus. The pressure build up was decreased from 550 psi per day to 27 psi per day. To lower the annular pressure further, a second resin job was performed using 0.35 bbl resin volume, which further reduced the annular pressure build up to 25 psi within 3 days. No further stages were performed as this was considered a safe working pressure for the well owner. After 2 months no annular pressure was observed. The application of this tailored resin helped to improve the wells integrity under these circumstances in this high-pressure gas well. Epoxy resin with its solid-free nature and deep penetration capabilities helped to seal off a very tight flow path. This application of pumping resin through the wellhead to overcome annular gas pressure can be an option when the flow path is strictly limited, or downhole well intervention is very difficult and risky.

Case Studies on Multistring Isolation Evaluation in P&A Operations

Cement sheath quality assessment is a critical initial step in plug and abandonment (P&A) operations during oil and gas well decommissioning. However, the technologies commonly used require unimpeded access to the casing annuli, thus enforcing the need for production tubing pulling or inner casing milling. Cement integrity or isolation evaluation through multilayered well casing strings will provide the opportunity to significantly reduce operational time and costs and to greatly simplify the traditional P&A process. As desired by the industry for years, recent advancements in isolation evaluation have proven the feasibility to assess cement sheath quality without the removal of production tubing or inner casing. The new development, consisting of a sophisticated logging apparatus with a novel processing methodology, led to a groundbreaking technology evaluating zonal isolation through multiple casing strings in wells. The logging tool is deployed in the borehole using E-line, slickline, or coiled tubing. Then, the acoustic energy that is emitted and received by the tool travels through the tubing and surrounding annulus to reach the isolation barrier behind the casing. A proprietary frequency-domain processing algorithm successfully identifies the desired signal by discriminating it from overwhelming undesired signals such as tubing arrivals. The latest development stage further enables the segmentation of the measurements, providing an improved sensitivity to detect the azimuthal variations in the cement sheath quality. Case histories of applying omnidirectional and segmented multistring isolation evaluation technology in field trials in the North Sea are presented in the paper. The measurement accuracy has been verified through side-by-side comparisons with industry-standard cement bond log (CBL) and ultrasonic logs recorded after the tubing was removed. Additionally, the technology has been proven applicable to various casing or tubing weight and size combinations with tubing eccentric inside the casing. Thus, it is practicable in actual well configurations and suitable for the deviated well sections as well. In conclusion, this innovative technology that exhibits quantitative assessments of bonding or isolation conditions of wells in multistring configurations provides a cost-effective solution during P&A and further demonstrates a great potential to accelerate along the path to a rigless P&A operation.

Theories and Work Towards Understanding a Mysterious Case of Severe Bakken Brine Incompatibility

The Bakken formation is well known for producing brine very high in total dissolved solids (TDS). Halite, calcium carbonate, and barium sulfate scales all can pose substantial production challenges. Trademarks of Bakken produced brine include elevated concentrations of sodium (>90,000 mg/L), chloride (>200,000 mg/L), and calcium (>30,000 mg/L), contrasted against low concentration of bicarbonate (50-500 mg/L). In the past 3 years, operators have experienced unexpected instances of severe calcium carbonate scale on surface where produced fluids from the production tubing commingled with the gas produced up the casing. Initially treated as one-off scale deposits despite the application of scale inhibitor, acid remediation jobs or surface line replacement were typical solutions. As time has passed, this issue has become more and more prevalent across the Bakken. Investigation of this surface issue discovered a most unexpected culprit: a low TDS, high alkalinity brine (up to 92,000 mg/L alkalinity measured to date) produced up the casing with the gas. When mixing with the high calcium brine typically produced in the Bakken, the resulting incompatibility posed remarkable scale control challenges. The uniqueness of this challenge required thorough analytical work to confirm the species and concentrations of the dissolved ions in the brine produced with the gas. Scale control products were tested to evaluate their abilities and limitations regarding adequate control of this massive incompatibility. The theory that corrosion contributed to this situation has been supported by a unique modelling approach. Once corrosion was identified as the likely source of the high alkalinity brine, corrosion programs were instituted to help address the surface scaling. This paper highlights the evaluations conducted to fully grasp the severity of the incompatibility, the theories put forth to date, work conducted to try to replicate the phenomena in the lab and in models, and chemical programs used in the field to address corrosion and scale. While not known to exist in other oilfield basins, conventional or unconventional, this discovery may have implications for the broader industry if similar situations occur. The possible explanations for why this may be happening may have implications for scale control, asset integrity, and potentially even the methods by which wells are produced.

Results of Bench Tests of Tube Steels of the Production Tubing with a Chromium Content of 1%, 3% and 5% on a Unit Simulating the Operating Conditions of Producing Wells

Currently, most of the fields of RUE Production Association Belorusneft are at a late stage of development, which is characterized by a high water cut of well production. One of the main tasks in such conditions is the search for engineering solutions aimed at preventing corrosion of well equipment during oil production. Under the operating conditions of producing wells of the fields of RUE Production Association Belorusneft, well equipment is subject to electrochemical carbon dioxide corrosion [1]; mainly the inner surface of the tubing is subject to corrosion attack. The average rate of local corrosion in the corrosive environments of the oil fields of Belarus is 2–3 mm/a. The first cases of corrosion damage to production tubing were identified in 2010. Taking into account the high cost of stainless tubing, since 2011, the technology of inhibitory corrosion protection has been successfully implemented in the fields of Belarus by the method of constant dosing of the reagent into the annulus of production wells. The use of inhibitors made it possible to eliminate well failures due to tubing leakage, extend their service life by at least 4 times and reduce the local corrosion rate to 0.1 mm/a. However, an increase in the number of production wells damaged by corrosion caused by water encroachment of the wells, as well as an increase in the cost of reagents for oilfield chemicals require the use of new technological approaches, the search for alternative, economically more profitable solutions.

First Ever Offshore Deployment of an Inflatable Packer Anchoring System for Rigless Installation of an Insertable Progressive Cavity Pump: A Case Study

An offshore well located in Indonesia required rigless installation of an insertable progressive cavity pump (I-PCP) as a cost-effective solution to restore production while eliminating the need to retrieve the upper completion for extensive maintenance. The well had been previously completed with a conventional progressive cavity pump (PCP) as an integral part of the completion and was placed offline for approximately one year due to mechanical failure of downhole components. Typical I-PCP anchoring methods were not feasible alternatives for this application. A pump-seating nipple (PSN) insertable seal stack could not be used due to the lack of a PSN at the required I-PCP setting depth, and a mechanical J-slot anchoring device could not be deployed because rod conveyance from an offshore barge is subject to constant heave, which results in fluctuating axial loads and rod position, which would pose the risk of prematurely activating a mechanical J-slot anchor during deployment. An inflatable packer anchoring system was selected as a solution to the operational challenges encountered in this application. The system comprises inflatable packer technology, a hydraulically-actuated anchoring slip mechanism, seal cups, and a shearable intake sub. Conveyed on sucker rods, the system provides the required pressure competence to confirm tubing integrity and enable a complete hydraulic setting sequence. The first ever offshore installation of this system proved its optimal functionality by successfully anchoring an I-PCP inside 3-1/2" production tubing riglessly from an offshore barge. The system was set by applying pressure via the tubing-rod annulus, and the well was immediately placed into production. After being shut-in for more than one year, this unique solution provided the well operator with a safe and low-cost alternative to reestablish production while eliminating the need for a workover rig. The objective of this paper is to provide a case study analysis of the first offshore deployment of this technology, discuss its potential for optimizing PCP/I-PCP completion designs, and explain the economic and operational benefits of associated rigless well intervention operations in comparison to current alternative methods.

Experiments of Liquid Loading and Intermittent Production Using a Lab-Scale Reservoir-Tubing Setup

Experiments were performed to investigate the physics behind intermittent production and liquid loading, using a setup containing a reservoir model coupled to a vertical production tubing. In the experiments both gas and liquid are injected into the reservoir, which is a container in which sand with two different permeabilities is placed. Quick closing valves are incorporated into the experimental setup in order to simulate well shut-ins and start-ups. The experimental results show that the addition of the reservoir to the experimental set-up shifts the minimum in the total pressure losses over the system to lower gas flow rates as the permeability of the reservoir decreases. When performing shut-ins where a significant liquid column is present in the tubing, as is the case in liquid loaded wells, performing a sufficiently long shut-in can lead to the deliquification of the system.