This paper covers the problem related to AC interferences on East West Gas Pipeline (EWPL) and the mitigation measures taken for reducing / eliminating the same. AC interference was observed in Hyderabad region due to AC EHV Transmission lines crossing EWPL, three phase transformers and Single wire earth return (SWER) single phase transformers in the vicinity of pipeline. AC PSP voltage up to 80 Volts were observed on pipeline during night hours for which various mitigation measures were taken to bring down in acceptable range. Similarly, there is possibility of high voltage surge at station facilities along the pipeline route due to vicinity of multiple structures, long pipeline length and having multiple conducting structures at MLV stations comprising of RTD's, die-electric isolators, impulse Tubing for power gas and associated power gas and control equipment. Surge travel to such system can result in equipment failures. Various proactive measures to mitigate such instances were adopted on pipeline system and are implemented successfully. This paper illustrates the extent of the risk of corrosion, surge impact due to AC interference / surge and gives insight to various methods deployed for minimizing these risks in simple and most economical way. It also highlights the need for collaboration and operational coordination between the pipeline operators and state electricity boards to resolve such issues mutually & in most effective manner.
Melilo Junior, Angelo Celio (Petrobras) | Oliveira da Costa, Carlos Henrique (Petrobras) | Armani Delalibera, Carlos Alberto (Petrobras) | Schwingel Dias, Marco Antônio (Petrobras) | Palmeira de Oliveira, Thomaz Murrieta (Petrobras) | Pereira, Rafael Merenda (Petrobras)
The Libra Extend Well Test (EWT) project is composed of 2 satellite wells interconnected to an FPSO with an external Turret anchor. One well is the producer, with 6-inch service lines and 8-inch production line in lazy wave risers configuration. The other well is the injector, with two 6-inch gas flow lines also in lazy wave compliant configuration. In the project planning several actions were considered in order to guarantee the first oil date determined by the project, while the production unit (FPSO) was not available in the location and ready to pull-in campaign. One of these actions studied and later adopted was the prelaying operation of the flexible lines with floaters in the lazy wave configuration of the production line of the production well. Later on, similar studies were done considering the pre-laying of injection lines also. As this type of operation is not a track records at Petrobras for the ultra-deep water scenario, additional studies were necessary to ensure its feasibility and the safety execution. The objective of this article is to present the previous studies and the result achieved in the pre-laying operation of flexible line with floaters in the lazy wave configuration of the Libra EWT service line.
Gupta, M K (Oil and Natural Gas Corporation Ltd.) | Sukanandan, J N (Oil and Natural Gas Corporation Ltd.) | Singh, V K (Oil and Natural Gas Corporation Ltd.) | Bansal, R (Oil and Natural Gas Corporation Ltd.) | Pawar, A S (Oil and Natural Gas Corporation Ltd.) | Deuri, Budhin (Oil and Natural Gas Corporation Ltd.)
This paper discusses a case study of one of the onshore field of ONGC where while processing well fluid, frequent surge has been observed leading to shutdown of the SDVs creating severe operational problems and loss of production. It was imperative to find out the problematic wells/lines located in clusters which contribute for surge formation and mitigation approach with minimum modifications.
A transient complex network of sixty five wells flowing with a different lift mode such as intermittent gas lift, continuous gas lift etc were developed in a dynamic multiphase flow simulator OLGA. Time cycle of each well were introduced for intermittent lift wells. Simulation study reveals pulsating transient trends of liquid flow, pressure which was matched with the real time data of the plant and hence confirms the accuracy of the model. After verifying the results, different scenarios were created to determine the causes of surge formation. After finding the cause, a low cost approach was considered for surge mitigations.
An integrated rigorous simulation was carried out in OLGA, by feeding more than 12,000 data points to obtain model match. Several scenarios were also created such as optimization of lift gas quantity, optimization of elevation and size. Trend obtained after each scenario was pulsating behaviour and it matched with the real time data appearing in the SCADA system of the field. After rigorous simulation with each scenario, it was established that the cause of surge forming wells/pipelines. Once the root cause of surge has been confirmed then quantum of liquid generated due to surge was determined. Adequacy checks of the existing separators were carried out to estimate the handling capacity of the existing separators at prevalent operating condition. After adequacy check it was found that existing separators cannot handle the surge generated in that time interval leading to cross the high-high safety level, resulting closure of shut down valve (SDV). After establishment of root cause of the surge, a low cost solution with small modification in pipelines and control system/valves was adopted to arrest the surges. It was first of its kind simulation carried out for a huge network of wells/ pipelines by feeding more than 12,000 data to analyze the surge formation cause and capture its dynamism owing to wide array of suspected causes. This will help to address the challenges of efficiently reviewing the entire pipeline network while designing new well pad/GGS and will also help to arrest surge by adopting a low cost solution wherever such situation arises.
As the oil and gas industry is moving towards digital oil field, the selection of leak detection system (LDS) has become more crucial. Early detection of leaks not only saves environment from Hazardous hydrocarbons but considerable loss in production is also saved. This paper discusses about both internal and external LDS and its applicability for onshore and offshore fields. This paper will ease the selection process of LDS for green and brown fields of both offshore and onshore installation.
CML (Controlled Mud Level) is a dual gradient type of Managed Pressure Drilling (MPD). The CML system was developed and implemented on the Troll field to allow for reducing the annular pressures acting on the wellbore during drilling, thus allowing drilling areas weakened by faults and fractures and longer horizontal sections in the depleted normal pressured reservoirs. This paper will present a short introduction to the Troll field, a description of the system utilized, a summary of the rig integration, operations and experiences with the CML system on Troll.
In line Inspection (ILI) Interval are often based on conditions that are assumed constant over long sections of pipeline - perhaps entire pipeline systems. Many pipeline operators are following the fixed ILI Interval based on statuary requirement irrespective of different local corrosion growth conditions prevailing on the particular pipeline system. Scheduling the ILI based on maximum interval defined in statuary requirement may be very unrealistic and pose threats to the integrity of these pipelines. This technical paper discusses the importance of ILI Interval, corrosion growth rate analysis, recent development to determine the ILI Interval, an engineering approach to calculate appropriate ILI-RunInterval, mitigation plan to extend the ILI-RunInterval for particular pipeline system. This technical paper would enhance the awareness among the pipeline operators to appropriately calculate the ILI-Run Interval which would cost beneficial to pipeline operators in long term without any integrity threats.
Essam, Wael (BP) | Scarborough, Christopher (BP) | Wilson, Nick (BP) | Shimi, Ahmed (BP) | Santos, Helio (Safekick) | Hannam, Jason (Safekick) | Catak, Erdem (Safekick) | Lancaster, Jay (Seadrill) | Gooding, Neil (Seadrill) | Baan, Robert (Seadrill)
BP had long recognized the benefits of MPD, having been using it for years to deliver very challenging wells in Egypt, Trinidad and the North Sea; and it was time to bring these benefits to its GoM operations. Once the company team identified a portfolio of suitable candidate wells to allow the economics of the application to be advantageous, they partnered with Seadrill to provide the MPD service integrated into the West Capricorn drilling rig. This approach builds on synergies within the drilling contractor organization to achieve long term economic, competency, and risk management benefits, resulting from integrating this drilling method on the rig, and eliminating interfaces with 3rd party providers. The paper will discuss how the company and the drilling contractor teams, together with equipment suppliers and training providers, managed the project from initial system design, to installation and commissioning, to the successful delivery of the first well using MPD, at top quartile performance. It will discuss the process for optimizing the design and testing it from a reliability and process safety perspectives; engaging the regulatory authority and the classification society; integrating MPD in the well planning process and developing operational procedures for use on the rig; and delivering a training program for the wider team covering the technical and the human factors aspects to ensure a successful delivery.
Diniz Brandão Rocha, Leandro (Ocyan) | de Almeida Campos, José Eugênio (Ocyan) | Venâncio Xavier, Cristiano (Ocyan) | Visser, Thijs (Ocyan) | Freitas, Felipe (Stress Engineering) | Stahl, Matt (Stress Engineering) | Cruse, Greg (Oil States Industries)
This paper presents a case study of how a drilling contractor handled the implementation of Managed Pressure Drilling (MPD) equipment on 4 (four) drilling rigs, with focus on the impact on Well Control equipment and emergency disconnect while performing FMCD (Floating Mud Cap Drilling). The paper considers the effects of the rapid inflow of seawater from the bottom of the riser (water rush-in) during a possible emergency disconnect. Additionally, this paper discusses concerns about the subsea equipment when the drilling fluid level is close to the subsea BOP stack or below the seabed. Such scenarios can expose the drilling riser, riser adaptor, flexible joint, BOP annular preventer, BOP seals and gaskets to an inward-acting pressure differential. Restrictions that this inward-acting differential pressure may impose on the conventional equipment currently aboard the drilling units were taken into consideration to determine the feasibility of FMCD operations. This paper highlights the non-conventional considerations as well as challenges associated with this operation for the offshore drilling industry. Those challenges have also motivated technology innovation such as a reduced-friction, next-generation subsea flexible joint, which will operate equally in conventional or MPD conditions.
Viscoelastic surfactants (VES) are essential components in self-diverting acid systems. Their low thermal stability limits their application at elevated temperatures. The industry introduced new VES chemistries with modified hydrophilic functional groups, which enhances their thermal stability. These new chemistries are still challenged by the lack of compatibility with corrosion inhibitors (CI). This work aims to study the nature and the mechanism of the interaction between the VES and the corrosion inhibitors, which affects both the rheological and corrosion inhibition characteristics of the self-diverting acid system.
This study is based on rheology and corrosion inhibition tests, where combinations of VES and corrosion inhibitors are tested and complemented with chemical and microscopic analysis. Negatively charged thiourea and positively charged quaternary ammonium corrosion inhibitors were selected to study their impact on both cationic and zwitterionic VES systems. Each mixture of the corrosion inhibitor and the VES was blended in a 15 and 20 wt% HCl acid mixture, then assessed for its viscosity at different shear rates, CI concentrations, and temperatures up to 280°F in live and spent acid conditions. Each acid solution was assessed using Fourier-Transform-Infra-Red (FTIR) before and after each rheology and corrosion test to track the changes of the mixture functional groups. Each mixture was examined under a polarizing microscope to assess its colloidal nature. The corrosion inhibition effectiveness of selected acid mixtures was evaluated. N-80 steel coupons were immersed statically in the acid mixture for 6 hours at 150°F and 1,000 psi. The corrosion rate was evaluated by using metal coupon weight loss analysis followed by optical microscope examination for the metal surface.
The interaction between the CI and the VES surface charges and molecular geometries dictates both the rheological and the inhibitive properties of the acid mixtures. The use of a small molecular structure anionic CI with a cationic VES, results in a fine monodispersed CI particles in the VES-acid system. The opposite charges between the CI and the VES results in electrostatic attraction forces. Both the fine dispersion and the electrostatic attraction enhances the rheological performance of the mixture and packs the corrosion-inhibiting layer. The addition of a bulk and similarly charged CI with the VES results in a coarse polydispersed CI particles with repulsive nature with the VES. These properties increase the shear-induced structures and lower the packing of the inhibition layer deposited on the metal coupons, which decrease the rheological performance of the acid mixture and increase its corrosion rate. The FTIR analysis shows that there is no chemical reaction between the CIs and the VESs tested.
This work investigates the interactions between the corrosion inhibitors and the viscoelastic surfactants. It explains the impact of the surface charge of both corrosion inhibitors and VES on their rheological and corrosion inhibition characteristics. It adds a selection criterion for compatible VES and corrosion inhibitors.
Wang, Xin (Rice University) | Ko, Saebom (Rice University) | Liu, Ya (Rice University) | Lu, AlexYi-Tsung (Rice University) | Zhao, Yue (Rice University) | Harouaka, Khadouja (Rice University) | Deng, Guannan (Rice University) | Paudyal, Samridhdi (Rice University) | Dai, Chong (Rice University) | Kan, Amy T. (Rice University) | Tomson, Mason B. (Rice University)
Iron sulfide scaling is a severe problem in flow assurance and asset integrity in oil and gas and deep-water production. FeS scale control is challenging due to the extremely low solubility, fast precipitation kinetics and complexity of ferrous iron and sulfide chemistry. Despite the ubiquity of FeS, we have limited understanding about the kinetics and thermodynamics of iron sulfide. To address this problem, we have developed a reliable anoxic plug flow reactor using argon gas to remove oxygen and PIPEs or MES buffer to control pH. The FeS (mackinawite) solubility, precipitation kinetics and phase transformation were the focus of this study. The impact of temperature (25 – 90°C), pH (5.92 – 6.91), ionic strength (0.15 – 4.30 M), Fe(II) to S(-II) ratio, dispersant and chelating reagent have been investigated. It was found that mackinawite is always the first FeS precipitated and could be stable for a week. It was suggested that low pH, high temperature and low ionic strength could accelerate the FeS phase transformation. FeS precipitation is under diffusion control at pH lower than 6.1, which could be accelerated by high temperature and high ionic strength. But the precipitation kinetics would be faster at higher pH. Some evidence suggests the importance of neutral FeS(aq) species at pH 6 −7. A polymeric compound containing amide functional group showed a promising effect by controlling the FeS particle size and reducing FeS scale retention rate. EDTA showed satisfactory FeS scale inhibition effect, as well as reducing FeS scale retention and H2S corrosion rate.