bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Comprehensive Computational Framework for Long Term Forecasting on Serious Wellbore Damage and Ground Surface Subsidence Induced by Oil and Gas Reservoir Depletion
Authors: Liu Ruijie , Liu Zhijun 
Published: February 2017

Abstract
Depletion of oil and gas reservoirs results in ground surface subsidence and wellbore damage. Accurate prediction of subsidence and wellbore damage can provide a strong support to reservoir management and community precaution on subsidence impact. For reservoirs with soft rock formations, depletion-induced reservoir compaction results in serious damage and permanent deformation of rock formation. Cap plasticity models are crucial to achieve a more reliable prediction on the compaction of reservoirs with soft rocks. In this study, we develop a fully coupled and fully implicit finite element framework along with cap plasticity models for modeling the compaction of reservoirs with soft formations undergoing finite deformation. Creep models are also formulated with cap plasticity models for predicting the long-term effect of reservoir compaction. A material integrator for stress return mapping for both plasticity and creep models is consistently formulated to achieve fast convergent rates. A reservoir compaction model with three horizontal production wells and a wellbore damage model are solved using the proposed computational framework as well as cap and creep models with parameters obtained from field tests. We have demonstrated: 1) a good performance of the proposed computational framework in modeling the compaction of soft rock reservoirs with complex payzone geometries; and 2) the predicted subsidence with cap plasticity models could be seven times greater than linear elastic or plasticity models without caps.
Optimizing CT Material Properties for Extended Reach Operations
Authors: Newman Ken , Kelleher Patrick , Gunby Brian 
Published: February 2017

Abstract
There is a demand in the industry for coiled tubing (CT) that can safely reach significantly farther in horizontal wells than the current, steel based technology can reach. Some have suggested that CT composed of lighter materials could maintain a neutral or positive buoyancy (floating) in the horizontal section and thus be capable of reaching extraordinary total depths without exceeding their yield limit. However, several other aspects of CT operations must be considered for a complete assessment of extended reach capability, and these aspects often cause lighter materials to friction lock at shallow depths relative to their steel counterparts.
Using a parametric analysis, this paper will quantify the effect material properties, including stiffness and density, have on CT performance in extended reach wells. It will also correlate those properties with materials available today such as steel, titanium, and composites to explain why steel tubing is used in most CT operations.
Real Time Fatigue Endurance Monitoring of Open Water Coiled Tubing Downlines
Authors: Tipton Steven M. , Xie Bin 
Published: February 2017

Abstract
Coiled tubing was utilized as a conduit-type riser to deliver high-pressure fluids from a rigless multi-service vessel (MSV) during a GOM multi-well treatment campaign. The campaign consisted of high pressure pumping into a number of subsea wells for extended durations. The coiled tubing (CT) downlines are deployed with a clump weight through open water and connected to the subsea safety module and well stimulation tool.
The depths of these operations were on the order of 1,372m (4,500 ft) and quite similar (±100 ft). Fluids (including acid) were pumped continually through the conduit at pressures up to 10,000 psi for extended periods of duration (on the order of several days) from the MSV to the fixed subsea safety module. Waves and currents impose pitch and roll on the MSV, along with the need for continual dynamic repositioning. This motion causes discrete wrapping and unwrapping at the point where the tubing just exits the sheave (the "hot spot"). This leads to elastic strain fluctuations that can lead to significant high cycle fatigue (HCF) damage.
The MSV must continually adjust its heading for optimal metocean response. A unique system was designed and implemented to coordinate this positioning with minimized CT HCF damage accumulation. The system uses a robust position transducer to provide continual input about the critical components of vessel motion. This information is used by a program to compute the near real-time dynamic stress response of the tubing at the hot spot and the corresponding HCF damage accumulation, along with the low cycle fatigue (LCF) damage accumulation that occurs along the entire length of the tubing as it is deployed during each job. The system facilitated the management of multiple jobs, assuring that hot spots were not over-exercised from job to job. This was important due to the similar depths of the wells. The hot spots were tagged with paint to confirm their location.
The mechanics underlying the fluctuating stresses at the hot spot are described along with how these are computed from the MSV motion. Post campaign fatigue testing was conducted to validate the residual life in the tubing, as predicted by the program.
Fishing More Than 3,000 Meters of 1-3/4-in Coiled Tubing A Case Study
Authors: Merchan A. , Lopez A. , Deolarte C. , Sosa M. , Franco E. , William A. , Rodriguez F. , Ponce G. , Cervantes J. R. 
Published: February 2017

Abstract
We describe the situation and challenges, the implemented process and strategies, and the downhole tools used during the remedial work to successfully recover 3041 m of 1 3/4-in coiled tubing (CT) pipe lost-in-hole during an acidizing job.
During an acidizing job through the CT string as a part of a workover job in a well of a mature field in offshore Mexico, after filling the pipe with acid, the CT operator was ready to spot it across the perforated interval. When the up-hole movement started, the CT weight reached approximately 36,000 lbf (normal pulling weight at that depth in the previous runs) and then the CT weight went to 0 lbf. After retrieving the pipe to surface, it was noticed that only 199 m of CT were recovered from the well, leaving +/- 3041 m of CT pipe inside the hole. After a total of 43 runs and over 20 days, the entire CT string including the Bottomhole assembly (BHA) was recovered, and the well was put back on production. The key was to conform the top of the fish with a downhole motor equipped with a milling shoe, and then exploit the versatility and fast rig up/down capabilities of slikcline to position the fishing tool on the top of the fish. After the fish was latched, a GS profile was left in hole, thus allowing the CT to latch and retrieve the entire fish.
Fishing operations are considered more an art than a science because of all the variables involved, for example, type and top of the fish, restrictions along the wellbore, available fishing equipment, pulling capacities, and so on. However, following industry best practices, fishing can switch from a nightmare to a useful learning and successful experience. The authors will summarize the milestones in the operation, which serves as an example of collaborative work between the operator and service company that led to a successful outcome.
How to Perforate Challenging Wells Completed in Two Casing/Liner Overlap Sections: Mature Ecuador Field Case History
Authors: Alvarez Jhonny , Naranjo Edwars , Agila Cynthia , Castillo Rommel , Cuenca Dario 
Published: February 2017

Abstract
One of the primary challenges for wellbores completed with overlap sections in prospective pay zones is determining how to establish effective communication between the wellbore and reservoir. Conventional perforations are not sufficient to initiate production. This paper presents an effective method for communication with the reservoir using cutting or slotting tools.
Based on Bernoulli's energy conservation principle, an abrasive fluid, primarily composed of gel and silica sand, is forced through jets under a predetermined pressure, converting pressure energy into kinetic energy and enabling the fluid to exit the jets at velocities exceeding 1/2 Mach; this enables the abrasive cutting of the production liner/intermediate, cement sheet, and formation rock. This technique can be applied with either coiled tubing (CT) or jointed pipe, thereby achieving success in different applications, such as perforations in a single casing, overlap casing sections, and before hydraulic fractures.
A value-added element of this perforation technique includes the application of a relative-permeability-modifier (RPM) additive as part of the abrasive fluid, which helps prevent formation fluid loss while jetting under high overbalance pressures in low-pressure wells. This paper describes the job design, oil-production expectations from the operator, operational data, simulations, skin analysis, and results of this case. The technique was designed and individually applied in two target sandstones, Reservoirs A and B, which are coincidentally located on both 9-5/8 × 7-in. and 7 × 5-in. overlap sections, respectively. The method enabled a customized design for each zone, which resulted in more aggressive perforations to overcome the challenge in both sections.
Successful production improvement for a mature field in Ecuador was achieved using this perforation technique, which was the only available solution at the time to overcome such challenges. Advantages and lessons learned are discussed and compared to conventional gun-based perforating techniques. Another interesting factor of this case history is that Reservoir B was new, with unknown fluid and petrophysical properties.
Electric-Line Milling Operation on Tree Master Valve of a High Surface Pressure Well Enables Well Control
Authors: Al-Ajmi Mohammed D. , Al-Ajlan Raed A. , Al-Hajri Nasser M. , Al-Quwaisim Hussain A. , Zamka Saleh I. , Al-Subaie Fehead M. , Green Todd A. , Al-Hajri Muhammad A. , Al-Meshal Fahad M. , Al-Shammari Nayef S. , Sagr Hani , AlJedawi Raed 
Published: February 2017

Abstract
This paper presents the success story of an innovative milling operation on a stuck-closed tubing master valve performed with electric line technologies. This field application has resulted in restoration of well accessibility, enabled well control, and saved costs related to rig intervention. The paper also documents lessons learned and recommends proper operational procedures related to future similar rigless operations, specifically with regards to well control and barrier philosophy.
A stuck-closed surface valve in a live well is treated with extra caution as it presents a serious and challenging well control issue. Such a situation often calls for immediate intervention to restore well accessibility and reestablish well integrity barriers. The stringent well control requirements of the oilfield operator make the operational design and corresponding job execution even more challenging. In this case, Well-A is a land based vertical oil well on which the master gate valve was stuck and non-functional in the closed position. The pressure bellow the valve was last measured to be 1200 psi, a relatively high shut-in wellhead pressure compared to other offset producers in the same field. The wellhead was equipped with two carbon steel master gate valves, in addition, to the swap valve. The lowermost gate valve is the stuck valve, hence, preventing access to the well. Several attempts to repair and grease the valve body and stems were unsuccessful. Accordingly, the oilfield operator has decided to mill the gate valve, secure the well, and then replace the entire tree.
The uncertainty in the well pressure below the master valve posed a significant operational risk. This is due to the impact of well fluid pressure force on the electric line rig-up after the gate valve is milled. Therefore, job planning, design, and execution were guided by a risk based and comprehensive contingency plan that accounted for all probable well control scenarios. The rig-up consisted of coiled tubing flanged risers, annular blowout preventer, Shear/Seal ram, and wireline blowout preventer in order to ensure the presence of adequate well control barriers throughout the operation. Adhering to a ‘safety first’ attitude, the operation was concluded successfully and met its said objectives. The successful massive undertaking of such critical well intervention operation has marked a new milestone in rigless well interventions.
Advanced Live Well Deployment System Enables Remedial Sand Control Solution
Authors: McClean Charlie , Hillis Parry , Zuklic Stephen , Ross Colby , Kidd Peter 
Published: February 2017

Abstract
In producing fields in moderately consolidated sandstone reservoirs, at any given time it is possible if not likely to have wells underperforming or even shut-in due to sand production. Later in the life of these fields, this issue becomes even more significant. Often times the reserves don't justify the economics of a full rig workover or the productivity risk of well kill operations. In these cases, the only option to restore productivity is utilizing through-tubing methods, deployed into the live well. Historically these systems have presented significant limitations in terms of interval length and reliability. However, by utilizing an advanced deployment system to eliminate mechanical risks and length limitations of typical through tubing systems, and by integrating this with a detailed, analytical approach to sand control selection, the benefits of live-well deployment can be realized without sacrifice in terms of installation reliability or long-term productivity.
A detailed engineering and testing process was applied to insure ruggedness and ease of use in the field on the mechanical deployment system to allow virtually any length assembly to be deployed using conventional coiled tubing BOP equipment. Concurrently, a thorough analysis is conducted to understand sanding tendencies across the interval and particle and flow characteristics in order to select and optimize sand screen characteristics as well as isolation devices to compartmentalize the interval for maximum well life. The paper will demonstrate multiple applications of the resulting system which allowed efficient installation across large producing intervals without the introduction of kill weight fluids, eliminating the associated productivity damage and risk. The operations were completed without NPT and the associated costs. The active sand control design and the detailed producing plan enabled production above targeted rates maintained to date.
Subsea Coiled Tubing Acid Stimulation Operation Using CT Tractor in Angola
Authors: Rajamani Karthik , Schwanitz Brian 
Published: February 2017

Abstract
An Angolan operator needed to perform a coiled tubing (CT) acid micro-wash stimulation on a subsea sand screen completion in order to improve production. The CT simulation showed that the coil would not reach the objective, which was the bottom screen, even with friction reducers, without the assistance of additional forces. The operator chose to deploy a downhole tractor to provide a pulling force to achieve the desired depth. However, this horizontal well had debris which prevented reaching the objective and required changing strategies to accomplish the job.
A downhole tractor can be powered by pumping fluids down the coiled tubing, driving a turbine which powers the hydraulic systems in the tractor. The drive fluid will then pass through the tractor and out the bottom of the tool to provide the treatment. Surface testing is performed prior to the job to determine at which pumping rate the tractor will be engaged and disengaged. This testing is performed with and without treating nozzles to gauge tool performance and expected pumping rates for tractoring and treating.
In this Angolan operation two runs were required to reach the bottom screen due to debris fill in the completion preventing passage during the first run. On the second run the CT provider used a nozzle that could both clean the well and treat in the same run. This operation demonstrates the effectiveness of using CT tractors, which are under-utilized in the industry, to achieve extended reach beyond the normal CT range. It also demonstrates the quick mobilization and same day deployment, as well as problem solving that can occur when service companies (CT provider and tractor provider) work closely together.
Best Practices in Pre-Fracturing Coiled Tubing Intervention Operations Increase Success Rate of Hydraulic Fracturing Treatments
Authors: Guizada Pablo , Rahim Zillur , Al-Kanaan Adnan , Al-Rashed Ahmed , Kayumov Rifat , Arifin Mohammad , Al-Jalal Ziad 
Published: February 2017

Abstract
Well stimulation and intervention are typical activities to enhance the productivity of gas-bearing sandstone reservoirs and meet the increasing demand for energy. Many wells target sandstone formations that require stimulation to produce gas at an economical rate. Proppant fracturing is the preferred stimulation method for such reservoirs because it creates highly conductive pathways between the wellbore and the reservoir. Prior to any fracturing treatment, sufficient injectivity at an acceptable bottomhole treating pressure (BHTP) needs to be established. Depending on the reservoir quality, the task of breaking down the formation and establishing a sufficient injection rate may sometimes be challenging due to the high in-situ stress and compressive strength of the reservoir rock. Formation breakdown pressure can exceed the completion limitation due to stress alteration zones around the wellbore. For such cases, interventions using coiled tubing (CT) are often required to proceed with the hydraulic fracturing operation.
Two well-known remedial CT treatments are typically used to address wells with high breakdown pressures or low injection rates. The first is treatment by chemical means. Chemicals containing organic solvents or acids are squeezed into perforated intervals in the wellbore; subsequent soaking of the well with such chemicals can help remove some of the near-wellbore damage induced by drilling. The second is treatment using a mechanical approach; abrasive fluids containing gelled fluids and sand are jetted at high pressures through a nozzle at the target depth to create a cavern that connects the wellbore with virgin, non-stress-altered sections of the reservoir. More than 10 interventions performed over the past five years are analyzed in this paper. These include both abrasive jetting and chemical squeeze job techniques. Analysis indicates that only half of the abrasive jetting jobs were successful, and none of the chemical squeeze treatments provided positive results. Based on detailed analysis, ways forward were determined that will improve the success ratio for remedial actions using CT, including employing fiber-optic real-time telemetry to precisely place the bottomhole assembly and perforating with CT to optimize operational efficiency.
This paper provides an analysis of the well intervention practices that aid fracturing operations and prevent challenging situations such as high breakdown pressure that result in unsuccessful fracturing treatments. The knowledge obtained from this analysis can be extended to other regions where similar breakdown challenges exist.
A New Record for a Rigless Completion Campaign Through Efficient Coiled Tubing Hydrajet Assisted Fracturing Operations in a Mature Field in Northeastern Colombia
Authors: Jaimes Mariana , Bahamon Jorge I. , Mora Edgar , Campo Pablo , Reina John F. , Orozco Alex O. 
Published: February 2017

Abstract
This paper addresses issues concerning treatment execution and discusses results from successful coiled tubing (CT) hydrajet assisted fracturing (HJAF) treatments performed during a campaign in a mature oil field located in northeastern Colombia.
The Tibú field is a mature field in northeastern Colombia having low-permeability reservoirs that necessitate stimulation techniques, such as hydraulic fracturing, to increase production by increasing the contact area of the producing intervals. Additional challenges exist, including small well location pads, complex community relationships, and security problems that inhibit simple, fast, and efficient operations. To address these issues, a solution was proposed involving a blend of conventional proppant fracturing with the versatility and efficiency provided by a CT-deployed hydrajet perforated pinpoint stimulation method. These operations included well cleaning using slow-rotating wash tools and correlation for depth control using a gamma ray/casing collar locator.
More than 40 wells have been completed using CT HJAF treatments in this field. Some technical advantages provided by the application of this technique are a higher perforating efficiency and a significant reduction in near-wellbore (NWB) friction, yielding reduced risk of premature screenouts, enabling higher pumping rates, and generating longer fractures. Post-fracturing oil production results met expectations for this mature oil field, proving the economic viability of this technique for successful multistage hydraulic fracturing in a short period of time. For most of the wells, all completion activities, including up to three fracturing stages, were performed in four days.
This paper shows how the proposed CT application for HJAF operations can yield significant benefits and improve the level of sustainability in these types of mature oil fields.
Employing Effective Water Treatment with New String Technology in the Eagle Ford to Mitigate String Failures
Authors: Kakadjian Sarkis , Nwachukwu Raymond 
Published: February 2017

Abstract
This paper reviews steps taken to mitigate coiled tubing string failures resulting from microbial-induced corrosion (MIC) in the Eagle Ford by initiating an effective water treatment process alongside the use of coiled tubing with bias weld in sour fatigue similar to base tube performance.
Premature failures of coiled tubing strings can be capital intensive for most coiled tubing companies in the current oil and gas market. In 2015 there was a total of three string failures resulting from MIC in the Eagle Ford—with an estimated cost of USD 750,000. MIC has been implicated in few corrosion related challenges in the well service industry in the past.
The water treatment process was implemented in field on 21 December 2015. The mitigation process involved treating the circulating fluid in the fracturing tanks on location with chlorine dioxide, peracetic acid, or BDNP quick killer biocides. These are combined with glutaraldehyde or combination solution of glutaraldehyde and quaternary ammonium (glut/quat combo) for longer term bacterial control at the start of each job. Water samples of the circulating fluids are taken within 8 hours to get the relative light units (RLU), which determined the proper time to re-treat the water on location. RLU values were also correlated to typical sulfur reducing bacteria (SRB) and acid producing bacteria (APB) levels in South Texas. The water treatment process has been administered, along with the continuous metering of the bacteria and introduction the new coiled tubing technology, for 12 months with no string failure has been encountered. Further analysis of the effectiveness of the treatment will be conducted later in the string life when the involved strings are retired.