bluuebunny/crossref_metadata_2025_split huggingface dataset:
Unconventional P&A Intervention with Coiled Tubing Below a School Building: Comodoro Rivadavia, South Argentina Case History
Authors: Graterol H. , Calvo T. 
Published: September 2011

Abstract
Oil discovery and development in Comodoro Rivadavia City (South Argentina) has over 100 years of history and more than 2000 wells have been drilled within the city border.
The urban development requires take into account considerations related on Plug & Abandonment (P&A) well status, safety radius and additional special safety conditions. It is important to notice that many of the wells in the city have been pluged and abandoned before the current P&A governmental regulation that was approved in 1996.
A particular case is the Well Ch-1943, which was drilled in 1970, P&A in 1984, and later in 1986 a school was built on top of the well underestimating the associated risks in ignoring the assigned safety radius. Sed School remines active and functioning to this day.
The operator, assuming civic responsibility planned to bring the well to current P&A regulations. The Plug & Re-Abandonment of the well was scheduled to happen during the school summer break between December, 2009 and January, 2010. At that time the challenge was assigned to the P&A Team. The intervention involved many risks and the job needed to be finished in a very limited period of time. Chalenges included well planning, contracts approval, well location restrictions, site preparation to connect the well to the ground level, school roof removal, coiled tubing unit preparation for the well intervention with additional job deck and final surface job and had to be completed without affecting the school building structure.
This document describes the main tasks required to complete the particular challenging intervention complying with the highest safety and quality standards. The Well Intervention was completed successfully in 12 days with a 2″ Coiled Tubing Unit. The total length of the planning/preparation and execution of this project was 46 days.
The Case Story includes: –Well Planning–Well Location–Safety Risk Analysis–Site Preparation–Well Intervention ○Coiled Tubing Rig Up.○Well Calibration – Milling old cement plugs and scrap○Casing Corrosion & Bond Logs Annulus isolation guarantee○Squeeze & Balanced Cement Plugs–Final surface reconstruction
Joint efforts between service companies and the operator was a key factor in achieving the planned P&A results.
Well Interventions in Depleted Gas Wells Made Economical with Use of Small Size (3/4 in.) Coiled Tubing
Authors: Jelinek W. , El-Mabrouk K. , Biezen E. , Leybourne D. , de Jonge R. M. 
Published: September 2011

Abstract
Well interventions in depleted gas wells are often seen as not being economically viable. Since the production rates in these wells are generally low, the pay-back time on the cost of a coiled tubing (CT) intervention could be rather long, making cash flow and earnings not attractive for gas producing companies. Furthermore, due to the low reservoir pressure, introducing fluids in depleted gas wells may cause a water block, formation damage and liquid loading, which can kill the well. Small diameter Coiled Tubing, often called Mini Coil, can overcome these problems, making interventions in depleted gas wells both economical and feasible.
Mini Coil operations with ¾″ coiled tubing were re-introduced in Europe, after 25 years of absence, to offer cost-effective intervention methods for depleted gas wells. Typical Mini Coil operations include small acid treatments, salt plug washes, fluid lifting, inhibition of tubing, etc. For clean outs in wells with a coiled tubing velocity string completion or on offshore installations, where crane limitations do not allow for a standard coiled tubing reel to be used, Mini Coil can be an useful option1.
In this paper the design criteria, applications and the limitations of Mini Coil operations are discussed. Equipment design features and principles for the choice of coiled tubing size and material are presented. Candidate well selection criteria and the benefits of these types of operations are illustrated by case histories in the Netherlands and Germany.
Depleted gas wells, which might not be considered for any further interventions, can now be treated economically again. Mini Coil allows for the use of a compact equipment spread, resulting in cost savings through faster rig-up and rig-down times, smaller footprints, fewer personnel required and fewer truck loads. The small internal volume of the Mini Coil increases the control over the amount of fluid injected into a well, thereby reducing the risk of killing the well during a treatment.
Pushing the Boundaries of Concentric Coiled Tubing Technology To Resurrect Sub-Hydrostatic Gas Wells on an Unmanned Offshore Installation
Authors: Davies A. , Dunning M. J. , Kuchel M. P. , Roberts T. , Taggart M. J. 
Published: September 2011

Abstract
Ravenspurn North is a mature gas field in the Southern North Sea with 42 wells, drilled and many hydraulically fractured in the late 1980s. By 2006 more than half of the wells had ceased to flow and many were flowing intermittently. With ailing wells and consequently falling production rates, the longer term future for Ravenspurn North field was uncertain.
A wireline campaign suggested a common failure mode for many wells that large amounts of proppant had accumulated in the wellbore. Modeling of the potential range of static and dynamic pressure losses caused by this proppant supported a significant enhancement to the remaining gas potential. However, the depths of the wells combined with sub-hydrostatic pressure conditions and large diameter lower completions made achieving cleanout challenging. Furthermore, the target wells were located on unmanned offshore installations with minimal facilities, deck space and deck loading.
This paper details how each of these obstacles were successfully tackled to reinstate a target set of wells. It describes the various cleanout options that were considered, and why Concentric Coiled Tubing Vacuum Technology (CCTVT) was ultimately selected. Prior to this project CCTVT had never been deployed in the North Sea and nowhere in the world at these reservoir depths. The operation was delivered on the small unmanned installation by conducting the world-first boat spooling operation of Concentric Coiled Tubing; rigorously re-assessing deck loadings; and running the operation 100% self sufficient with a maximum of 10 personnel on board.
Finally this paper culminates with a detailed description of the successful CCTVT operations which recovered a total of 2,950 lbs of proppant from three wells to expose the perforations, and unload the wells of liquid. Furthermore, Concentric Coiled Tubing was used to mill out tubing profile nipples and install a packer to hang off 1,200 ft of flush joint tailpipe. Innovative thinking and close collaboration between operator and service companies was required as the ability to perform multiple operations on Concentric Coiled Tubing was in itself pioneering.
Overall this campaign has pushed the boundaries of intervention technology to deliver an extremely challenging project. This has resulted in a more certain future for the Ravenspurn North field, as well as unlocking opportunities in deep depleted gas wells worldwide.
Backpressure Valve for Subhydrostatic Wells
Authors: Xu Z. R. , Tunc G. , Pipchuk D. A. , Morbelli D. 
Published: September 2011

Abstract
Subhydrostatic or low bottomhole pressure wells are wells with large hydrostatic overbalance, that is, the hydrostatic pressure of the fluid column inside coiled tubing, drillpipe, or similar well intervention means is greater than the wellbore pressure at the corresponding vertical depth. The number of subhydrostatic wells is growing as more and more fields mature. Consequently, there is an increasing number of interventions required for these wells to improve and/or optimize their production. U-tubing of the fluid column is a very common and uncontrolled phenomenon during interventions in subhydrostatic wells that can cause problems. In this paper the focus will be on coiled tubing interventions; however, the same basic principles apply to other areas as well.
A backpressure valve (BPV) is a device that is used in subhydrostatic wells to hold the fluid column inside coiled tubing to prevent U-tubing. The BPV compatibility with other components in the toolstring is a critical operational requirement. Following recent tests conducted with the BPVs readily available in the market, it has been shown that these are not appropriate for a number of applications. One example is an application involving pressure pulse telemetry. For pressure pulse telemetry, conventional BPVs either cannot pass the pressure signals or greatly attenuate the magnitude of them.
A backpressure valve that is fully compatible with pressure pulse telemetry has been developed and will be presented in this paper. The root cause of why the conventional BPVs were not able to transmit pressure pulse will be discussed using the results from fundamental physics, computational fluid dynamics analysis, and lab and filed experiments. Finally, a typical set of results from a field trial using the new valve will be presented.
Inversion of DTS Logs To Measure Zonal Coverage During and After Wellbore Treatments With Coiled Tubing
Authors: Tardy P. M. , Ramondenc P. , Weng X. , Burgos R. , Baez F. , Ganjeh K. Yekta 
Published: September 2011

Abstract
Distributed temperature sensing (DTS) is a fiber-optic technology that provides continuous temperature profiles along the length of a well. When placing the fiber inside a coiled tubing (CT), one can monitor the temperature evolution while pumping, as well as during a shut-in period. This evolution, in turn, yields some indications about the fluid placement performance or zonal coverage. So far, interpretation of such DTS traces has mostly been qualitative. The work presented here demonstrates how DTS data can be used, coupled with an inversion algorithm and a forward model of fluid injection into a reservoir, to quantify the intake profile of treatment fluid along the wellbore. Recent field cases of matrix acidizing treatments in carbonate reservoirs are analyzed to illustrate the workflow and how it may yield valuable information.
Skin Monitoring And Well Testing Utilizing Fiber Optic Telemetry Enabled Coiled Tubing
Authors: Shaheen Tarek , El Fattah Mohamed Abd , Dilling Lambert , El Rahman Sayed Abd , Anwar Emad , Noya Vidal , Elsherif Tamer 
Published: September 2011

Abstract
For the last several years, viscous pills, polymer based, were used to kill the wells during the workover operation in the tronian formation existing in the eastern desert of Egypt. These polymer pills have negatively affected the wells productivity by blocking the pore throats and reducing the permeability. As an example, the well A-1 was producing 300 bpd (Gross) which declined dramatically after a workover operation which included the viscous polymer pills to produce only 20 bopd.
An engineering study was carried out to identify the main reason for the decline in the production. Several experiments were performed in the lab in order to simulate the filter cake using formation samples and evaluate the effect of the polymer being injected on the sandface permeability. An engineered solution was designed to break the polymer subsequently pumped in the formation and stimulate the matrix in order to recover and enhance the oil production. The remedial work was executed using a Fiber Optics Telemetry Enabled Coiled Tubing (FOTECT) system to optimize the treatment leveraging on downhole real time measurements.
This paper describes the first application of FOTECT in sandstone formations, involving:
1. The sandstone matrix stimulation operation.
2. Measuring both bottom hole pressure and temperatures at static and dynamic conditions during the entire operation.
3. Accurate depth correlation to achieve optimum placement of the treatment fluids
4. Monitor the chemical reactions in real time of the engineered treatment fluid.
5. Monitor the diversion performance during Sand Stone stimulations and the timing required for efficient reactions.
6. Qualitative production allocation of the interval as a response to the treatment fluids
7. Evaluation of the skin value real-time while executing matrix stimulation.
8. Pressure transient analysis in real-time enabling the standard output of a well test (permeability, skin, Pressure, and reservoir boundaries).
The experience demonstrates that use of real-time downhole measurements during the CT treatment allows: a) the evaluation of the well performance before and after the treatment, b) enables optimization of the treatment as it is executed, based on the formation response, enhancing the chance for a successful intervention, and c) provides an added alternative to perform a well testing operation right after the treatment, thus, obtaining valuable information to update the reservoir model.
Redefinition of Well Interventions in Naturally-Fractured Carbonate Reservoirs through Real-Time Coiled Tubing-Deployed, Fiber Optic Monitoring
Authors: Aviles Rodrigo , Flores Jose G. , Martin Frederic , Diaz Alan , Davila Luis E. , Monroy Rafael R. , Beltran Jorge , Moreno Angel R. , Martinez Armando 
Published: September 2011

Abstract
The South Region of PEMEX in Mexico produces 530,000 bopd from mostly mature, naturally-fractured carbonate reservoirs. The majority of the well interventions in the area present complications, due to a combination of extreme operational conditions, variety of reservoir rocks and fluid environments, and complex well configurations required to produce from large intervals in different flow units, many supported by active aquifers and secondary gas caps, that eventually reduce the production of oil as the water production and gas production increase. Rigless stimulation and maintenance well operations have been recognized for decades as efficient and cost-effective production enhancement enablers in the area. As the fields mature and the well interventions become more challenging, there is a higher demand on the operator side to successfully pinpoint the intervals and execute treatments that overcome unknown downhole parameters with confidence, maximizing success and avoiding additional remedial work.
A new approach, incorporating real-time, coiled tubing-deployed, fiber optics monitoring, was implemented in three well interventions in southern Mexico. These included: (a) the isolation of a high-water producing interval in a low-pressure reservoir using an inflatable packer; (b) a matrix stimulation requiring the accurate placement of fluids and diversion stages; and (c) the perforation and testing of several intervals in a gas injector well.
Real-time down-hole measurements of performance have been found to be an excellent option to improve the success rate in the well interventions in southern Mexico, allowing capturing unique quantitative feedback from the well, to be able to act with a greater degree of precision to increase production. Coiled tubing-deployed fiber optics proved to help the operator to improve efficiency and to optimize intervention performance with confidence in real time.
Success Story: Improving Reservoir Monitoring to Increase Production in Offshore Marginal Oil Field
Authors: Pramboeidi Sri Khresno , Subiantoro Edy 
Published: September 2011

Abstract
Mengkapan is a mature offshore oil field in the Malacca Strait PSC, located in central Sumatra, Indonesia. First oil flowed in 1986. The production wells produce multiple sands commingled with simple ESP completions. Cumulative oil production at the end of 2010 was 35 MMSTB, and the current recovery factor is around 50%.
Over the years, as oil rates declined and water cuts increased, the team ran production log campaigns to monitor the oil rate and water cut of sand. These logs revealed the occurrence of cross-flow and oil-blocking, which was attributed to differences in permeability and pressure between the sands. The log results led to workovers to isolate high water-cut sands by setting production packers. But after more years passed, the point was reached where there were no more zones to isolate with packers, and the team was forced to consider well abandonment.
Rather than abandonment, the team changed their mindset from "there is no remaining oil" to "there is by-passed oil and we can get it". The chosen technique was to squeeze-cement high water-cut zones and re-perforate by-passed oil sands identified from cased-hole logs.
In ME-02, massive cross-flow between high-permeability sands seen in the production logs did not matter, because the suspected by-passed oil sands were the lower permeability sands at the top of the perforated intervals which were unaffected by cross-flow. The Carbon-Oxygen log suggested by-passed oil in the upper part of some sands. Next, all perforated intervals were squeeze-cemented, using a technique fine-tuned with the team’s knowledge of cross-flow. Then, the by-passed oil zones were re-perforated, and the well was completed and put on-line.
Prior to squeeze cementing and re-perforation, ME-02 well produced 9000 BFPD, 45 BOPD. After the workover, the well produced 2000 BFPD, 104 BOPD. The budget was USD 660,644.00, but only 60% of the budget was used. It paid out in two months.
This paper tells the failures by relying on a single tool and the success story in ME-02 to increase the value of a workover (reduced operation cost and increased oil gain), including the concept, the data gathering, and the field operation.
Well Production Enhancement Results with Inflow Control Device (ICD) Completions in Horizontal Wells in Ecuador
Authors: Vela Ivan , Viloria-Gomez Lumay , Caicedo Ricardo , Porturas Francisco 
Published: September 2011

Abstract
Reservoir performance is dependent upon system interaction between the completion hardware, the wellbore reservoir section and its connection to surface.
A-priori condition used to design a robust completion solution are housing units capable of draining and collecting fluids along the entire completion length and simultaneously produce oil while delaying more mobile fluids. Therefore the completion design should focus on: Those scenarios that are expected to have greater impact in the producer wells: These include for example PI increase, adjusting drawdown pressure, flux balancing, delaying early entry of high mobile water or gas along the entire completed interval, well clean-up through time and extending well production life.Wether it is expected to accelerate initial production or balanced management of the field. The goal in both cases is to achieve efficient area drainage and uniform sweep while not leaving by-passed oil in the ground.Whether the contingency plans are for, alternative re-completions or preparing the wellbore for future operations such as EOR related activities to stimulate production from much lower oil residual saturations.Having hardware ready that allows changes in operational modes from producer to injectors or viceversa, or permits installation of slim hole units, technologies to enhance porosity or permeabilty, reduce viscosity and mobility ratios, implement fine reservoir characterization models, avoid reaching ultra-high WCUT too soon or to implement intermediate EOR operations to slow down this tendency.
In Ecuador, an operator has completed several wells equipped with ICDs, in both consolidated and non-consolidated reservoirs and with variable rock and fluid properties including viscosities varying between 4 to 47 cP. This paper describe the combination of ICD design, geo-steerirng, calibration with real-time log data, installation procedures and fluid historical production results through time.
A Fully Coupled Geomechanics and Fluid Flow Model for Well Performance Modeling in Stress-dependent Gas Reservoirs
Authors: Salah El-Din Ahmed , Elbanbi Ahmed H. , Abdelwaly A. A. 
Published: September 2011

Abstract
Predicting the performance of wells in stress-dependent gas reservoirs can be quite challenging to most conventional reservoir engineering tools. In this paper, a fully coupled geomechanics and fluid flow analytical model was developed for modeling well performance in stress-dependent gas reservoirs. For tight and unconsolidated gas reservoirs that exhibits variable formation compressibility, reservoir compaction, and stress-dependent properties deterioration such as permeability and porosity, the geomechanics effect may not be ignored. All these physical contributes play an important role on well performance. The coupled model considered all these contributes and evaluate their impact on well productivity. The model also accounts for the effect of the transient flow period and variable producing conditions in addition to the effect of non darcy flow in gas wells.
An optimization algorithm was used with the coupled model to estimate original gas in place and performance characteristics for each layer in case of multilayered gas reservoirs.
Different simulation cases and selected examples from gas wells producing from stress dependent gas reservoirs are used to illustrate the coupled model application. The results from this study indicates that a fully coupled geomechanics and fluid-flow modeling approach is necessary for analyzing highly stress-sensitive gas reservoirs
Evaluation of A New Liquid Breaker for Polymer-Based In-Situ Gelled Acids
Authors: Aksoy G.. , Gomaa A. M. , Nasr-El-Din H. A. , Wang X.. , Boles J.. , Cawiezel K.. 
Published: September 2011

AbstractIn-situ gelled acids with Zr4+cross-linkers utilize a solid breaker to reduce the viscosity of the gel at pH range of 4–5. A literature survey confirmed that solid breakers caused a premature reduction in the fluid viscosity resulting in a less than desirable productivity. Therefore, an effective liquid breaker that is based on tetrafluoroboric acid was developed. As pH increases, the liquid breaker releases fluoride ions, which will combine with the cross-linker, Zr4+. This study was conducted to evaluate this new breaker system under the following conditions: breaker concentration (0–200 ppm), and acid injection rate (0.5–10 cm3/min).The effect of the new breaker on the rheological properties of in-situ gelled acid was examined using a HPHT rotational viscometer. A coreflood study was conducted to follow the propagation of acid and cross-linker inside the limestone core. Samples of the core effluent were collected and the concentrations of calcium, zirconium, and acid were measured. Permeability enhancement and location of the residual gel were determined using CT scans.The pH profile during neutralization confirmed that the crosslinking of the polymer occurred at a pH value of 1.8. At a pH of less than 2, doubling the breaker concentration did not affect the viscosity of the acid. However at a pH of greater than 2, the viscosity of acid was reduced by 30%. At a breaker concentration of 0 ppm, the appearance of Zr in the core effluent sample was delayed by 0.25 PV compared to the reaction product, while at 100 ppm Zr was delayed by 0.75 PV. At 200 ppm breaker, no Zr ions were detected in the effluent samples. As the breaker concentration increased, more Zr remained inside the core, as ZrF4, which is water-insoluble. Increasing the breaker concentration from 100 to 200 ppm reduced the final normalized pressure drop by 50% at injection rate of 2.5cm3/min. Permeability reduction due to gel was reduced by increasing the acid injection rate. Therefore, the acid solution with the liquid breaker should be injected at high injection rates.