|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Results are presented on a long duration batch treatment using corrosion inhibitor in deep sour gas wells. This paper discusses the lessons learned during this implementation. An innovative method of placing downhole corrosion coupon was used to monitor the field result. Gauge cutter runs indicate a reduced accumulation of iron sulfide scale for the batch treatment interval. The selection of the corrosion inhibitor involved corrosion testing at high shear and high temperature with hydrogen sulfide and carbon dioxide and high temperature, high pressure core flood tests.
Corrosion tests were done in a rotating cage at low and high temperatures, high partial pressures of carbon dioxide (CO2) and hydrogen sulfide (H2S) and a different rotation rates. Core flood experiments were conducted on a 6-inch-long limestone core at 280° F and 5000 psi. The stability of the neat corrosion inhibitor at different temperatures was confirmed in a laboratory umbilical injection system. The batch treatment procedure was designed to ensure a sufficient amount of chemical to coat tubing completely. The batch treatments were monitored in the field using a new downhole corrosion and scale monitoring tool.
Initial screening of corrosion inhibitor testing at high temperatures, with high partial pressures of H2S and CO2 using both X65 and T95 coupons at different rotation rates indicated that the selected corrosion inhibitor was a good candidate for treating a sour gas well. Core flood testing showed that the permeability of nitrogen through limestone at 280° F and 5000 psi was 1.23 md with a standard deviation of 0.06 md. The permeability of gas through limestone at residual corrosion inhibitor saturation was 1.32 md with a standard deviation of 0.06 md. Capillary testing of the product was conducted at 166° C (350° F) and 5000 psi for 7 days. The chemical passed the test and no sign of differential pressure increase or product instability. The product was used in two sour gas wells. No formation damage was observed with batch treatment. Downhole monitoring coupons were used to monitor the trial in instances where corrosion inhibitor was and was not used. The coupon experienced generalized corrosion between 5 -10 μm in 3 months (0.8 -1.6 mpy) when corrosion inhibitor was not used. The coupon that had a batch treatment experienced generalized corrosion between 3-8 μm in 5 months (0.3 -0.8 mpy). Slight pitting corrosion was found in both coupons. For the trial without inhibitor, pitting features between 20 to 25 μm was found. This corresponds to pitting corrosion rates between 3 to 4 mpy. In the coupon that was batch treated with corrosion inhibitor, one pit of 13 μm was found. This corresponds to a rate of pitting corrosion of 1.2 mpy. It was found that gauge cutters would travel to longer depths in the intervals after batch treatment when compared with intervals where no chemical was used. This was good indication of reduced scale formation index. The application is useful to prevent sour corrosion and iron sulfide scaling (ferric source). The field trial utilized novel downhole monitoring technology and is an instance of a successful long duration corrosion inhibitor treatment that did not damage the carbonate formation.
Cable failure and corrosion are two important modes of failure for electrical submersible pumps (ESP) especially for ESP working in high temperature, high shear, and saline environments with carbon dioxide (
The brines used in this work are listed in
For internal corrosion on tubings and ESP parts, corrosion tests were done using a high temperature small autoclave test and jet impingement. The small autoclave test setup allows measurement of corrosion rate using linear polarization resistance (LPR) method with a three electrode system where the counter and reference electrodes are Hastelloy C276 (
Copyright 2020, International Petroleum Technology Conference This paper was prepared for presentation at the International Petroleum Technology Conference held in Dhahran, Saudi Arabia, 13 - 15 January 2020. This paper was selected for presentation by an IPTC Programme Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the International Petroleum Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the International Petroleum Technology Conference, its officers, or members. Papers presented at IPTC are subject to publication review by Sponsor Society Committees of IPTC. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the International Petroleum Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented.
Downhole gas compression (DHGC) in gas wells is a relatively new concept in production engineering, but it represents one of the most promising technologies to revive dead wells, to boost gas production and to maximize total gas production recovery. This technology could be analogous to electrical submersible pumps (ESPs) for oil wells, as it increases well production by reducing the back pressure at the wellbore sand face; this is achieved by providing boosting pressure to cover for outflow pressure requirements (i.e. tubing losses and well head backpressure). However, downhole wet gas compression applications are considerably more challenging than those for ESPs. The purpose of this paper is to describe step by step the procedures and workflows to evaluate downhole gas compression applications, from information preparation, to multiphase flow calculations and sensitivity analyses.
The applications of this technology are more complex than conventional pumping methods for oil wells. Calculations are more involved with considerations for gas compressibility, multiple flow regimes, liquid volume fraction at compressor intake, compressor pressure ratio requirements, liquid loading conditions, discharge pressure and discharge temperature, among other effects, which are some of the main factors to be measured for this type of application.
There is no standard methodology in the oil industry for gas well modeling and sensitivity analysis for DHGC applications. Just few publications can be found in the literature with some description of the evaluation process but missing some other relevant aspects of the application. This paper presents a systematic process to evaluate applications of DHGC including well performance modeling and compressor simulations.
A new comprehensive methodology has been used for downhole compression application in this study, using nodal analysis software for well performance modeling in combination with a process system simulator to model compressor performance.
Ghadimipour, Amir (Baker Hughes, a GE Company) | Barton, Colleen (Baker Hughes, a GE Company) | Guises, Romain (Baker Hughes, a GE Company) | Perumalla, Satya (Baker Hughes, a GE Company) | Izadi, Ghazal (Baker Hughes, a GE Company) | Franquet, Javier (Baker Hughes, a GE Company) | Mahrooqi, Shabib (Petroleum Development Oman) | Dobroskok, Anastasia (Petroleum Development Oman) | Shaibani, Mahmood (Petroleum Development Oman)
As part of a multi-disciplinary investigation to optimize a tight reservoir development in the Sultanate of Oman, a comprehensive geomechanical characterization was performed and its results used as input for 3D non-planar hydraulic fracturing simulations. The simulation results led to better understanding of the reservoir response during hydraulic fracturing stimulation and thereby improved the decision making process for future field development. The focus of this paper is to highlight the geomechanical aspects of the analysis which explained several of the difficulties encountered during stimulation.
Geomechanical models were constructed covering the target sandstone and overlying clay-rich formation for ten horizontal and vertical wells by integrating diverse data including openhole logs, core rock mechanical tests, stress-induced failure interpretations from image logs, and stress measurements from mini-frac data. The geomechanical models were further supported by the results of available temperature, tracer and production logs. 3D geomechanical models were created by capturing the lateral and vertical variations of rock and geomechanical properties from these 1D models away from the wellbores, guided by the variations in seismic attributes using a co-simulation method. 3D modeling revealed a number of stress barriers supported by location of microseismic events in the target reservoir.
The geomechanical setting of the target formation is found to be complex with significant variations laterally and vertically. The West area of the field was found to have relatively lower stress compared to the Main area. Also, the Middle and Lower intervals of the target formation were shown to have considerably higher horizontal stresses (strike-slip/reverse faulting regime) compared to the Upper interval (normal/strike-slip faulting regime). The high stresses in Middle and Lower sections have the negative consequence of reducing the fraccability of these intervals as they require high breakdown pressures. In some cases, where breakdown was achieved, the resulting horizontal hydraulic fracture yields disappointing production results due to its inability to connect the reservoir vertically. Another important lesson learnt from geomechanical characterization in this field was the role of high angle bedding in truncating the vertical growth of hydraulic fractures. This understanding can further help to optimize the location of perforation intervals in stimulation designs of future development wells in this field.
Geomechanical characterization of this reservoir demonstrated considerable lateral and vertical heterogeneity that could only be captured by very detailed integration of well-based and seismic scale data. In addition, the effects of the
Downhole wet gas compression technology (DHWGC) is a relatively new artificial lift concept for gas wells that aims to boost production, maximize recovery and delay onset of liquid loading. By definition, wet gas compressors are capable to handle certain amount of liquids entrained in the gas, however, there are some circumstances where large amounts of liquids accumulate below the compressor and need to be removed to allow the gas well to flow. Liquids can accumulate below the downhole compressor after well intervention or as result of condensates accumulation during normal production. To this end, a means to enable liquids removal for Downhole wet gas compression applications must be developed. The objective of this study was to identify completion solutions that enable liquids unloading below the compressor. This paper introduces a new concept with a simple well architecture that will enable continuous operation and eliminate needs of additional well interventions to remove liquids accumulation that occur during well shut-in operations.
The 12 ¼" section in the western desert, Bapetco concision is challenging to be drilled as of the highly interbedded carbonate and shale formations, which are known to exhibit high levels of vibrations (torsional and lateral) associated with high drilling torque. Such high drilling torque lead-to increasing the
Customer NPT can cost up to $ 450k in case of sidetracking the well. In case the
The solution of adjusting the depth of cut downhole (Self-Adjusting) which have been newly introduced to the market targeting to decrease downhole vibrations, specially torsional vibrations and allow smoother transition between lithologies with different compressive strength and help in a smooth transition between the different layers while optimizing the depth of cut control
When the self-adjusting feature engages with rock for steady state drilling, the feature gradually retracts, controlling DOC to find the optimal exposure of the element for the current drilling parameters and formations. As dynamic instabilities occur, the self-adjusting feature reacts at fast time scales to mitigate the event. This should result in optimizing the bit response to deliver the best performance real time, decreasing the torsional vibration, NPT & MSE. This will lead to increase the drilling efficiency. The 12 ¼" PDC bit with the self-adjusting was tested with one Shell/Bapetco in the western desert wells, resulting in decreasing the vibration levels, decreasing the MSE hence increase the ROP 57% compared to average of the field which resulted in significant reduction to the drilling cost compared to the offset wells while achieving 35K of savings compared to the best offset
Below will present how the latest self-adjusting PDC technology had a significant impact on drilling time and cost savings by mitigating drilling dysfunctions that could result in unplanned trips and drilling inefficiencies if not addressed in a timely manner
Hussain, Maaruf (Baker Hughes, a GE Company) | Amao, Abduljamiu (King Fahd University of Petroleum and Minerals) | Muqtadir, Arqam (King Fahd University of Petroleum and Minerals) | Al-Ramadan, Khalid (King Fahd University of Petroleum and Minerals) | Babalola, Lamidi (King Fahd University of Petroleum and Minerals) | Jin, Guodong (Baker Hughes, a GE Company)
The knowledge of rocks elastic properties (REP) is crucial to geomechanical modeling throughout an asset life cycle. Reliable geomechanical models requires calibration of well log REP with core measurements. However, sample availability, representativeness, time, and cost are problems associated with core measurements. In this paper, we integrated REP derived from two laboratory techniques performed on several core covering over 800 ft interval samples from Paleozoic tight sands and shale reservoirs to obtain a continuous REP profile for better- upscaling of reservoir model parameters. For lithology delineation, intact core samples were scanned utilizing MicroXRF. While, REP was measured using Autoscan and AutoLab systems. The Autoscan employs non- destructive technique to characterize the variability of REP. The AutoLab uses the standard triaxial testing method to provide REP at reservoir conditions. The results were tabulated and statistically treated to establish significant empirical relationships. REP derived from triaxial tests on selected samples include, the P and S wave velocities (Vp and Vs), static moduli (Young’s modulus (Es) and Poisson’s ratio (vs)), as well as dynamic moduli (Young’s modulus (Ed) and Poisson’s ratio (vd)). While the reduced Young’s modulus (E*) was obtained from non- destructive method. Lithofacies were established from elemental data. The E* reveals details of several geomechanical heterogeneity and anisotropy which are not possible with traditional triaxial method. There is a significant correlation between E* and Es, Ed, Vs, and Vp. A continuous REP profile was developed using E* with geochemical data. Based on the characterized profile, fracture height growth barriers identified were toughness/modulus and interface barriers. These can significantly affect hydraulic fracture vertical growth within the studied Paleozoic tight sands and shale reservoirs units.
The approach, which uniquely considered scales of rock geochemical and mechanical properties and data analytics, demostrate the possibility of generating a continuous REP profile using laboratory aquired dataset. Thus, the difficulty associated with geomechanical characterization and model calibration of highly laminated unconventional reservoirs using actual laboratory data is resolved. This has a directly implication to both conventional and unconventional geomechanical modeling, where the determination of upscaled-reservoir model parameters matters.
This paper attempts to answer a fundamental question pertinent to fracture characterization of unconventional basement reserves using rock mechanics & petrophysics; are open fractures in basements necessary critically stressed? Evaluation of naturally occurring fractures are critical for production as well as reserves estimation. In this regard, a study well was drilled in the basement section of the Cauvery basin to explore unconventional pay zones & characterize the contributing fractures by integrated Geomechanical & Petrophysical analysis.
A suite of open hole logs including the basic, acoustic and electrical borehole images were acquired and an integrated approach was taken, including geomechanical analysis to identify the contributing fractures. Standard petrophysical evaluation in basements was inconclusive and porosity quantification from fractures posed a major challenge. Image log analysis involved identification of conductive and resistive fractures in the gauged wellbore and combining Stoneley reflectivity further indicated probable open fractures. Following this, a geomechanical analysis was carried out to determine the current in-situ stress orientation/magnitudes based on observed breakouts. Finally a CSF study was done to check for fracture slip events.
Based on the integrated study of Petrophysics and Geomechanics, an optimized workflow was developed and the critically stressed fractures were identified. It was found that, while some fractures strike direction was different from the present day maximum horizontal stress direction (SHmax), in general, most fractures were indeed aligned to SHmax. To check the fluid flowing capability of fracture networks, formation tester was deployed in selective zones for testing and sampling. Successful hydrocarbon sampling from selective fractures with orientation not aligned to SHmax led to the validation of the current study. The results proved that while most critically stressed/open fractures did indeed contribute to flow, a smaller fraction of the naturally occurring fractures while contributing to flow, were not necessarily aligned to the in situ orientations.
The results present a discrepancy between observation and the expectation that open fractures are necessarily oriented parallel or nearly parallel to modern-day SHmax. This works highlights the fact that although paleo-stresses may influence the fracture networks, it is the contemporary in-situ stresses that truly dominate fluid flow and only through a detailed understanding of the critically stressed areas, can we come to a decisive conclusion that further improves overall recovery.
At a time when maximizing operational efficiency is needed more than ever, advancements in data processing and analytical capacity may provide a sustainable path for uncovering hidden correlations and other insights from one of the basic roles and responsibilities of any surface logging services provider. This paper showcases a side-by-side comparison of two gas extraction devices and how they influence gas readings and, eventually, total gas measurement related to well control operations monitoring.
Although the trend analysis from gas reading values is imperative for pore pressure predictions and other classical readings, this paper negates its use for lower explosive limits (LEL) by using laboratory methods paired with a study in the field. The apparatus used to extract total gas in water-based mud was a constant-volume, constant-temperature and constant-flow system. The detector used to measure the total gas concentration was a flame-ionized detector (FID) system.
The influence of gas extraction devices on gas data is crucial for the determination of total gas. Conditions affecting gas readings have been explored at length, and they include gas extraction temperature, mud flow rates, gas flow rates, and drill rates (i.e., rate of penetration). Due to the development of analytical capacity, the extraction method and the analysis devices are compared in this paper.
Wellsite total gas monitoring, which usually provides common wellsite total gas values, has been heavily analysed regarding what it fundamentally represents. Total gas also helps operators to harness their data and use it to identify process safety indicators, as well as other environmental emissions applications.
Estimates of total gas concentration in the drilling fluid, as detected by a gas extraction device, can vary, based on the device type. This paper shows how the different extraction methodologies fit into well safety operations monitoring and process safety requirements to better evaluate and define new risk communication and safety practices in the industry.