Extreme Challenges in FeS Scale Cleanout Operation Overcome using Temporary Isolation, High Pressure Coiled Tubing, and Tailored Fluid Systems

2014 ◽  
Author(s):  
Mustafa Buali ◽  
Noel Ginest ◽  
Jairo Leal ◽  
Oscar Sambo ◽  
Alejandro Chacon ◽  
...  
Keyword(s):  
Safety Concern ◽  
Gas Production ◽  
Reservoir Pressure ◽  
Chemical Solution ◽  
Reservoir Temperature ◽  
Coiled Tubing ◽  
Fluid Systems ◽  
Operational Envelope ◽  
Fluid Losses ◽  
Scale Deposition

Abstract The carbonate gas producing zones of the Ghawar field have been impacted by extensive FeS scale deposition, reducing overall gas production and significantly increasing risks of well interventions. Previous remediation included the use of workover rigs, which can be costly because of the time necessary for workovers and lost production. H2S levels (2 to 5%) found in the reservoir also contribute to higher costs and risks when using workover rigs. A chemical solution was also considered, but the FeS could not be 100% dissolved with HCl and the chemical reaction generated large amounts of H2S in addition to existing high levels of H2S in the reservoir. This poses a safety concern with the returns at surface along with potential corrosion of the coiled tubing (CT) and completion. Therefore, the safest and most economical method was deemed to be mechanical descaling with CT. This paper discusses two wells where mechanical descaling was applied using CT. Each well involved four major challenges that included low reservoir pressure, increased reservoir temperature, horizontal openhole completion, and scale with high specific gravity (3.7 to 4.3). The low reservoir pressure required pay zone isolation to allow for returns to circulate out the heavy scale and to minimize fluid losses to the formation. The fact that the wells had long, openhole sections created another challenge for isolation and cleanout. With a bottomhole temperature (BHT) as high as to 310°F, the operational envelope of temporary chemical packers in combination with loss circulation materials (LCMs) to isolate the openhole section had to be expanded. Following mechanical descaling with CT, the final challenge discussed in this paper is the process to clean out the LCM in the horizontal openhole and bring the well back to maximum gas production using pinpoint stimulation techniques.

Solids-Free Loss-Control System Enables Efficient Coiled Tubing Workover Operations: Case Studies in Ukraine

2021 ◽  
Author(s):  
Mykhailo Pytko ◽  
Pavlo Kuchkovskyi ◽  
Ibrahim Abdellaitif ◽  
Ernesto Franco Delgado ◽  
Andriy Vyslobitsky ◽  
...  
Keyword(s):  
Control System ◽  
Gas Production ◽  
Free Fluid ◽  
Fluid Loss ◽  
Successful Implementation ◽  
Reservoir Pressure ◽  
Well Completion ◽  
Coiled Tubing ◽  
Sand Control ◽  
Loss Control

Abstract This paper describes three coiled tubing (CT) applications in depleted reservoir wells, where full circulation and precise fluid placement were achievable only by using a novel solids-free loss-control system, such as abrasive perforating applications. It also describes the preparation work, such as laboratory results and mixing procedure performed to ensure successful implementation. The analysis of Ukrainian reservoir conditions by local and global engineering teams showed that in a highly depleted well, abrasive jetting through CT was the best option to efficiently perforate the wellbore. However, this approach could lead to later impairment of the gas production if the abrasive material (sand) could not be entirely recovered. Such a risk was even higher as wells were depleted and significant losses to the formation occurred. The use of solids-free fluid-loss material that was easy to mix, pump, and remove after the operation, was, therefore, critical to the success of that approach. In Ukraine, most of the brownfields have a reservoir pressure that varies between 50% and 20% of the original reservoir pressure. This is a challenge for CT operations in general and especially for abrasive jetting, which requires full circulation to remove solids. It also complicates intervention when precise fluid placement control is required, such as spotting cement to avoid its being lost into the formation. The perforation solids-free loss-control system is a highly crosslinked Hydroxy-Ethyl Cellulose (HEC) system designed for use after perforating when high-loss situations require a low-viscosity, nondamaging, bridging agent as is normally required in sand control applications. It is supplied as gel particles that are readily dispersed in most completion brines. The particles form a low-permeability filter cake that is pliable, conforms to the formation surface, and limits fluid loss. The system produces low friction pressures, which enable its placement using CT. Introduction of that system in Ukraine allowed the full circulation of sand or cuttings to surface without inducing significant damage to the formation for first time; it was also used for balanced cement plug placements. This project was the first application of the solids-free loss-control system in combination with CT operations. It previously was used only for loss control material during the well completion phase in sand formations with the use of drilling rigs.

scholarly journals Influence of Intrinsic Permeability on the Production Performance of Shenhu Hydrate Sediment through Depressurization

2019 ◽  
Vol 118 ◽  
pp. 01008
Author(s):  
Yingrui Ma ◽  
Shuxia Li ◽  
Didi Wu
Keyword(s):  
Production Rate ◽  
Gas Production ◽  
Production Performance ◽  
Absolute Permeability ◽  
Reservoir Pressure ◽  
Intrinsic Permeability ◽  
Reservoir Temperature ◽  
Natural Gas Hydrate ◽  
Hydrate Dissociation ◽  
Hydrate Reservoirs

Natural gas hydrate(NGH) is a clean resource with huge reserves. The depressurization method is an economical and effective exploitation method. In the process of depressurization, reservoir absolute permeability has an important influence on production results. Based on the data of Shenhu hydrate reservoirs, this paper established a depressurization production numerical simulation model. Then, the production performances such as pressure, temperature, gas production rate, cumulative gas production, and hydrate dissociation effect are all studied under different permeability conditions.study the change of reservoir pressure, gas production rate, cumulative gas production, reservoir temperature change and hydrate dissociation effect under different permeability conditions. Results show that higher permeability is conducive to the depressurization of hydrate reservoirs.

scholarly journals STUDY OF CONDENSATION PROCESS DURING WELL OPERATIONUNDER ABNORMALLY HIGH RESERVOIR TEMPERATURES (BY EXAMPLE OF THE YUBILEINOYE GAS-CONDENSATE FIELD)

2017 ◽  
pp. 47-51
Author(s):  
R. A. Gasumov ◽  
K. N. Safoshkin
Keyword(s):  
Molecular Weight ◽  
Gas Production ◽  
Constant Volume ◽  
Gas Condensate ◽  
Condensation Process ◽  
Low Molecular Weight ◽  
Reservoir Pressure ◽  
Reservoir Temperature ◽  
Fluid Accumulation ◽  
Physical Processes

Some of gas-condensate fields lying at great depths are characterized by abnormally high reservoir temperatures. One of the problems during the operation of wells at depleted fields which are developed without methods to maintain reservoir pressure is fluid accumulation at the bottom. The Yubileinoye gas-condensate field is selected as an example for study. At the field abnormally high reservoir temperature is combined with low molecular weight of formation fluid. Since the change in the content of components produced from the formation to the surface of the gas-condensate mixture changes condensate emission even at the constant volume of gas production. It is important to understand the physical processes occurring in the operation of wells.

scholarly journals Evaluation of natural gas production optimization in Kailashtila gas field in Bangladesh using decline curve analysis method

2015 ◽  
Vol 50 (1) ◽  
pp. 29-38 ◽  
Author(s):  
MS Shah ◽  
HMZ Hossain
Keyword(s):  
Production System ◽  
Gas Production ◽  
Curve Analysis ◽  
Production Optimization ◽  
Reservoir Pressure ◽  
Gas Field ◽  
Wellhead Pressure ◽  
Decline Curve Analysis ◽  
Decline Curve ◽  
Overall Performance

Decline curve analysis of well no KTL-04 from the Kailashtila gas field in northeastern Bangladesh has been examined to identify their natural gas production optimization. KTL-04 is one of the major gas producing well of Kailashtila gas field which producing 16.00 mmscfd. Conventional gas production methods depend on enormous computational efforts since production systems from reservoir to a gathering point. The overall performance of a gas production system is determined by flow rate which is involved with system or wellbore components, reservoir pressure, separator pressure and wellhead pressure. Nodal analysis technique is used to performed gas production optimization of the overall performance of the production system. F.A.S.T. Virtu Well™ analysis suggested that declining reservoir pressure 3346.8, 3299.5, 3285.6 and 3269.3 psi(a) while signifying wellhead pressure with no changing of tubing diameter and skin factor thus daily gas production capacity is optimized to 19.637, 24.198, 25.469, and 26.922 mmscfd, respectively.Bangladesh J. Sci. Ind. Res. 50(1), 29-38, 2015

scholarly journals Analisis dan Optimasi Pengaruh Suhu Gas Umpan Pada Kinerja Acid Gas Removal Unit

2021 ◽  
Vol 1 ◽  
pp. 67-74
Author(s):  
Iwan Febrianto ◽  
Nelson Saksono
Keyword(s):  
Simulation Model ◽  
Flow Rate ◽  
Gas Production ◽  
Gas Content ◽  
Production Test ◽  
Reservoir Pressure ◽  
Gas Temperature ◽  
Separation Unit ◽  
Acid Gas ◽  
Gas Removal

The Gas Gathering Station (GGS) in field X processes gas from 16 (sixteen) wells before being sent as selling gas to consumers. The sixteen wells have decreased in good pressure since 2011, thus affecting the performance of the Acid Gas Removal Unit (AGRU). The GGS consists of 4 (four) main units, namely the Manifold Production/ Test, the Separation Unit, the Acid Gas Removal Unit (AGRU), the Dehydration Unit (DHU). The AGRU facility in field X is designed to reduce the acid gas content of CO2 by 21 mol% with a feed gas capacity of 85 MMSCFD. A decrease in reservoir pressure caused an increase in the feed gas temperature and an increase in the water content of the well. Based on the reconstruction of the design conditions into the simulation model, the amine composition consisting of MDEA 0.3618 and MEA 0.088 wt fraction to obtain the percentage of CO2 in the 5% mol sales gas. The increase in feed gas temperature up to 146 F caused foaming due to condensation of heavy hydrocarbon fraction, so it was necessary to modify it by adding a chiller to cool the feed gas to become 60 F. Based on the simulation, the flow rate of gas entering AGRU could reach 83.7 MMSCFD. There was an increase in gas production of 38.1 MMSCFD and condensate of 1,376 BPD. Economically, the addition of a chiller modification project was feasible with the economical parameters of NPV US$ 132,000,000, IRR 348.19%, POT 0.31 year and PV ratio 19.06.

Using Advance Acid Fracturing Design to Increase the Production Efficiency in a HPHT Reservoir: A Success Story from Southern Mexico

2021 ◽  
Author(s):  
Frank Figueroa ◽  
Gustavo Mejías ◽  
José Frías ◽  
Bonifacio Brito ◽  
Diana Velázquez ◽  
...  
Keyword(s):  
High Temperature ◽  
Laboratory Tests ◽  
Reaction Rates ◽  
Gas Production ◽  
Carbonate Reservoir ◽  
Fluid Distribution ◽  
Acid Etching ◽  
Southern Mexico ◽  
Acid Fracturing ◽  
Fluid Systems

Abstract Enhanced hydrocarbon production in a high-pressure/high-temperature (HP/HT) carbonate reservoir, involves generating highly conductive channels using efficient diversion techniques and custom-designed acid-based fluid systems. Advanced stimulation design includes injection of different reactive fluids, which involves challenges associated with controlling fluid leak-off, implementing optimal diversion techniques, controlling acid reaction rates to withstand high-temperature conditions, and designing appropriate pumping schedules to increase well productivity and sustainability of its production through efficient acid etching and uniform fluid distribution in the pay zone. Laboratory tests such as rock mineralogy, acid etching on core samples and solubility tests on formation cuttings were performed to confirm rock dissolving capability, and to identify stimulation fluids that could generate optimal fracture lengths and maximus etching in the zone of interest while corrosion test was run to ensure corrosion control at HT conditions. After analyzing laboratory tests results, acid fluid systems were selected together with a self-crosslinking acid system for its diversion properties. In addition, customized pumping schedule was constructed using acid fracturing and diverting simulators and based on optimal conductivity/productivity results fluid stages number and sequence, flow rates and acid volumes were selected. The engineered acid treatment generated a network of conductive fractures that resulted in a significant improvement over initial production rate. Diverting agent efficiency was observed during pumping treatment by a 1,300 psi increase in surface pressures when the diverting agent entered the formation. Oil production increased from 648.7 to 3105.89 BPD, and gas production increased from 4.9 to 26.92 MMSCFD. This success results demonstrates that engineering design coupled with laboratory tailor fluids designs, integrated with a flawless execution, are the key to a successful stimulation. This paper describes the details of acidizing technique, treatment design and lessons learned during execution and results.

scholarly journals The Effect of H2S Pressure on the Formation of Multiple Corrosion Products on 316L Stainless Steel Surface

2020 ◽  
Vol 2020 ◽  
pp. 1-11
Author(s):  
M. Shah ◽  
M. T. M. Ayob ◽  
R. Rosdan ◽  
N. Yaakob ◽  
Z. Embong ◽  
...  
Keyword(s):  
Passive Film ◽  
Photoelectron Spectroscopy ◽  
Oil And Gas ◽  
Safety Concern ◽  
Product Layer ◽  
Gas Production ◽  
Localized Corrosion ◽  
Stainless Steel Surface ◽  
Oil And Gas Production ◽  
316L Steel

H2S gas when exposed to metal can be responsible for both general and localized corrosion, which depend on several parameters such as H2S concentration and the corrosion product layer formed. Therefore, the formation of passive film on 316L steel when exposed to H2S environment was investigated using several analysis methods such as FESEM and STEM/EDS analyses, which identified a sulfur species underneath the porous structure of the passive film. X-ray photoelectron spectroscopy analysis demonstrated that the first layer of CrO3 and Cr2O3 was dissolved, accelerated by the presence of H2S-Cl-. An FeS2 layer was formed by incorporation of Fe and sulfide; then, passivation by Mo took place by forming a MoO2 layer. NiO, Ni(OH)2, and NiS barriers are formed as final protection for 316L steel. Therefore, Ni and Mo play an important role as a dual barrier to maintain the stability of 316L steel in high pH2S environments. For safety concern, this paper is aimed to point out a few challenges dealing with high partial pressure of H2S and limitation of 316L steel under highly sour condition for the oil and gas production system.

scholarly journals Narasin as a Manure Additive to Reduce Methane Production from Swine Manure

2018 ◽  
Vol 61 (3) ◽  
pp. 943-953
Author(s):  
Daniel S. Andersen ◽  
Fan Yang ◽  
Steven L. Trabue ◽  
Brian J. Kerr ◽  
Adina Howe
Keyword(s):  
Methane Production ◽  
Biogas Production ◽  
Safety Concern ◽  
Swine Manure ◽  
Inhibitory Effect ◽  
Gas Production ◽  
Dose Rates ◽  
Deep Pit ◽  
Sugar Addition ◽  
Swine Operations

Abstract. High levels of methane production from swine operations have been associated with foam accumulation in deep-pit manure storage systems. This foam poses both a safety concern (i.e., flash fires) and operational challenges in managing stored manure. Mitigating methane production is one approach to controlling foam accumulation. In this study, swine manures obtained from three deep-pit storage barns in central Iowa were dosed with narasin to evaluate its inhibitory effects on methane and biogas production. Dose rates ranged from 0 to 3.0 mg narasin kg-1 manure. Overall, methane rates were reduced by 9% for each mg of narasin added per kg of manure, and this reduction was effective for up to 25 days. However, the inhibitory effect weakened with time such that no statistical difference in cumulative methane production between samples dosed with narasin and undosed controls could be detected after 120 days of incubation. In addition to methane rates, narasin addition reduced the degradation of total and volatile solids in the manure by 1.9% and 2.6%, respectively, for each mg of narasin added per kg of manure. Additional study treatments included sugar (10 g kg-1 manure) with and without narasin (1.5 mg narasin kg-1 manure). Results from this treatment showed that methane production was initially increased by the sugar addition, but the effect lasted less than six days, at which point cumulative methane production was similar to the control. When treated with both narasin and sugar, the inhibitory effect did not impact gas production during the sugar digestion phase but did reduce methane and biogas production thereafter. The addition of sugar and the rate of narasin addition caused changes to the microbial community as compared to the control. Overall, the results indicated that narasin can be an effective additive for reducing methane emission from swine manure, but further study is needed to recommend dosing frequency and to evaluate how continuous addition of manure impacts narasin effectiveness. Keywords: Biogas, Manure management, Manure treatment, Methane, Narasin, Swine manure, Swine production.

Whistling of Pipes With Narrow Corrugations: Scale Model Tests and Consequences for Carcass Design

2013 ◽  
Author(s):  
Joachim Golliard ◽  
Stefan Belfroid ◽  
Erik Bendiksen ◽  
Casper Frimodt
Keyword(s):  
Prediction Model ◽  
Gas Production ◽  
Scale Model ◽  
Small Scale ◽  
Operational Conditions ◽  
Flexible Pipes ◽  
Cavity Opening ◽  
Flexible Risers ◽  
Onset Velocity ◽  
Operational Envelope

Pipes for gas production and transport with a corrugated inner surface, as used in flexible pipes, can be subject to Flow-Induced Pulsations when the flow velocity is larger than a certain velocity. This onset velocity is dependent on the geometry of the corrugations, the operational conditions and the geometry of the topside and subsea piping. In this paper, small-scale tests performed on corrugated tubes are reported. The tested geometries include both “classical” profiles, similar to the inner profile of agraff flexible risers, and profiles with less typical variations, such as narrower and/or deeper cavities, or irregular pitch. These tests were performed in order to evaluate the validity of a prediction model developed earlier for the onset of pulsations, for corrugated pipes with these kinds of atypical variations, which are found on a new type of carcass designs. The mechanism of Flow-Induced Pulsations in corrugated pipes is discussed, as well as the principle of the prediction model. The experimental results show that the validity of the model remains reasonable in most cases, except when the cavities are very narrow. In this case, the model becomes overly conservative. This limitation can be attributed to the fact that, for very narrow cavities, the cavity opening becomes too small compared to the boundary-layer momentum thickness, effectively destroying any instability of the shear layer. Furthermore, the shift towards higher frequencies of the acoustic source term due to narrower cavities, and the possible coupling with higher acoustic modes, is considered. The results of the analysis are used to evaluate the onset velocity and whistling behavior of a newly developed carcass design of flexible risers. A previous analysis has indicated that the particular geometry profile of the new design improves the whistling behavior by pushing the onset velocity outside the typical operational envelope of flexible risers. The analysis confirms that the new design will be less prone to whistling than flexible risers with classical agraff carcasses.

scholarly journals Predicting ground subsidence due to long term oil/gas production in a Niger Delta basin, Nigeria: implications for CO2 EOR and geosequestration

2021 ◽  
Author(s):  
Fidelis Ankwo Abija ◽  
Tamunoene. K. S. Abam
Keyword(s):  
Niger Delta ◽  
Gas Production ◽  
Surface Subsidence ◽  
Rock Properties ◽  
Ground Subsidence ◽  
Economic Losses ◽  
Reservoir Pressure ◽  
Formation Pressure ◽  
Stress Changes ◽  
Pressure Depletion

Abstract Reservoir pressure depletion with production leading to porosity loss, compaction and surface subsidence are the effect of effective stress changes and the imposition of the overburden stress which was partly supported by the fluids on the rock grain skeleton. Ground subsidence is associated with environmental hazards, failure of operational facilities and damages to infrastructures amounting to huge economic losses. In this studies, subsidence has been assessed using the Geertsma nucleus of strain based on predicted reservoir pressure. Depletion was estimated as percentage pore pressure dissipation and dynamically derived geomechanical and petrophysical rock properties determined. Reservoir porosity vary from 15% – 32%, shale volume from 11.2% − 88%, bulk compressibility range from 2.52–2.53 x 10− 6 /mPa, and uniaxial compaction coefficient 1.15–1.8 x 10− 6/mPa. The vertical compaction in a typical reservoir interval with a thickness of 31.0m varies from 0.002mm to 0.05mm at 10% formation pressure depletion, − 0.005mm to 0.27mm at 50% formation pressure drawdown and 0.007 to 0.53mm at 99% production and reservoir pressure dissipation. surface subsidence would range from 0.045mm to 0.35mm at 10% pressure depletion, 0.058mm to 1.8mm at 50% pressure depletion and 0.045mm to -3.47mm at full reservoir pressure drawdown. At a distance of 92.45km from the Niger Delta coastline, subsidence in the oilfield can still spread to the coastline, the deformation causing damages to the environment, operational facilities and infrastructures that amount to huge economic losses to the operators and government. We recommend the use of CO2 in EOR to maximize production, mitigate subsidence through ground rebound and keep carbon securely sequestered.

Sign in / Sign up

Export Citation Format

Share Document