Wellbore instability is caused by the radical change in the mechanical strength as well as chemical and physical alterations when exposed to drilling fluids. A set of unexpected events associated with wellbore instability in shales account for more than 10% of drilling cost, which is estimated to one billion dollars per annum. Understanding shale-drilling fluid interaction plays a key role in minimizing drilling problems in unconventional resources. The need for efficient inhibitive drilling fluid system for drilling operations in unconventional resources is growing. This study analyzes different drilling fluid systems and their compatibility in unconventional drilling to improve wellbore stability.
A set of inhibitive drilling muds including cesium formate, potassium formate, and diesel-based mud were tested on shale samples with drilling concerns due to high-clay content. An innovative high-pressure high temperature (HPHT) drilling simulator set-up was used to test the mud systems. The results from the test provides reliable data that will be used to capture more effective drilling fluid systems for treating reactive shales and optimizing unconventional drilling.
This paper describes the use of an innovative drilling simulator for testing inhibitive mud systems for reactive shale. The effectiveness of inhibitive muds in high-clay shale was investigated. Their impact on a combination of problems, such high torque and drag, high friction factor, and lubricity was also assessed. Finally, the paper evaluates the sealing ability of some designed lost circulation material (LCM) muds in a high pressure high temperature environment.
This session will discuss open-hole sand control completion, gravel and screen design and field performance. This session will cover production enhancement of carbonate reservoirs using acid and non-acid treatments. Topics of papers in this session discuss evaluation, characterization, and remediation of formation damage in new, secondary recovery, and producing well environments. Rustom K. Mody, P.E., is the VP–Technical Excellence for Baker Hughes a GE Company. Mody has more than 39 years of experience in drilling, completion and production of which 30 years with Baker Hughes a GE company in various executive positions in technology.
Produced water chemical compositional data are collected from a carbonate reservoir which had been flooded by North Seawater for more than 20 years, so there is an opportunity to analyse the large amount of produced water data collected, understand the brine/brine and brine/rock interactions and explore the impact factors behind them. In some publications, core flood experimental tests were performed with chalk cores or carbonate columns in order to make an understanding of possible chemical reactions occurring triggered by injected water with different composition (Seawater, low salinity water or any other brine). However, most of the time the laboratory conditions where core flooding experiments are implemented cannot fully simulate the real reservoir conditions. Therefore, in this study, with the help of the valuable produced water dataset and some basic reservoir properties, a one-dimensional reactive transport model is developed to identify what in situ reactions were taking place in the carbonate reservoir triggered by seawater injection.
From the perspective of reservoir mineralogy, calcite, as the dominant mineral in the carbonate reservoir, is relatively more chemically reactive than quartz and feldspar which are usually found in sandstone. Whether calcite is initially and dominantly present in the carbonate reservoir rock is dissolved under seawater flooding or not is the first key issue we focused on. The effects of calcite dissolution on the sulphate scaling reactions due to incompatible brine mixing and the potential occurrence of carbonate mineral precipitation induced by calcite dissolution are investigated and discussed in detail. The comparison of simulation results from the isothermal model and the non-isothermal model show the important role of temperature during geochemical processes. The partitioning of CO2 from the hydrocarbon phase into injected brine was considered through calculation of the composition of reacted seawater equilibrated with the CO2 gas phase with fixed partial pressure (equivalent with CO2 content), then subsequently the impact of CO2 interactions on the calcite, dolomite and huntite mineral reactions are studied and explained. We also use calculation results from the model to match the observed field data to demonstrate the possibility of ion exchange occurring in the chalk reservoir.
This case study is done on a mature oil field. In this field, a thin dolomitic layer is thought to be acting as a baffle of water injector in the field. As this thin layer is less than 50 cm thick and not consistently recognizable using some conventional logs, this is a trial of using a combination of advance distance to boundary detection and ultra-high-resolution imaging tool to steer the well above this thin layer. Based on core available data, it is a dolomitized Redstone with a strong hydrocarbon stain. The tight, relative dolomite is likely to act as a baffle to vertical fluid flow. To enhance the effect of planned water injection project, placement of horizontal well just above the dolomitic layer by a meter or a meter and a half was the target for a successfully injector well in this field. Challenges to the landing of such a well includes depth, thickness, and dip uncertainties. Additionally, there are the errors that are inherent to correlating between the reservoir scale and the seismic scale. Finally, it is difficult to discern boundaries in this low-resistivity environment characterized by very low resistivity contrast. Resistivity contrast, in particular, is of major importance as it plays the main role in determining the operability of common distance-to-boundary tools.
Combination of distance to boundary detection capability and Ultra-High Resolution Imaging while drilling allowed to place wellbore precisely at certain distance from the dolomitic fluid barrier, avoid any unwanted exits and to evaluate this dolomitic layer properties by resistivity, density/neutron data known as triple-combo sideways with the above mentioned used technology for steering. The data provided were integrated with seismic surveys to refine the reservoir structure and geometry interpretation. The improved understanding made it possible to optimize recovery and production through optimum landing of the well and to map the overlying and underlying reservoir parameters.
By selecting the right tool configurations in the bottom-hole assembly (BHA), formation tops were detected from a distance of up to 2m true vertical thickness (TVT) and in the same time parallel to the dolomitic layer in most of the well trajectory. Resistivity contrast was as low as 0.3 ohm.m versus the 0.9 ohm.m when detecting the dolomitic layer marker unit. On the other hand, in some areas of the well, crossing the dolomitic layer and a one bouncing to it was needed to build the confidence in this method and confirming the steering interpretation for the future upcoming wells in the same field.
The existing literature provides little guidance on the relevance of formation damage or return permeability results obtained from reservoir-conditions core flood testing on sandstone cores with heavy formate fluids. The drilling and completion in open hole of all six production wells in the Huldra field with heavy formate fluid provided a rare opportunity to appraise the results from HPHT core flood testing carried out on Ness (North Sea Brent Group) sandstone reservoir cores as part of the original drilling fluid qualification process for the Huldra development program.
Low- and high-permeability sandstone core plugs obtained from the productive Ness reservoir formation in the Huldra field were subjected to static and dynamic exposure to heavy formate drill-in fluids under HPHT reservoir conditions at 350 psi overbalance for a period of 296 hours. The cores were then exposed to short-duration drawdowns under HPHT reservoir conditions to simulate the very early phase of production start-up. The permeability impairment results obtained in these laboratory tests were compared against the production performance data for six Huldra field wells drilled and completed with sand screens in open hole in Brent Group sandstones with the same heavy formate fluids.
The reservoir-conditions (11,400 psi, 150°C) core flooding test with a SG 1.92 formate drill-in fluid sample from a Huldra well drilling job reduced the permeability of a 1416 mD Ness core by 37.8%. The same fluid reduced the permeability of a 2.8 mD Ness core by 65.9%. Repeating the same reservoir-conditions core flooding tests with a fresh SG 1.92 formate drill-in fluid sample prepared in the laboratory gave very similar results. In all cases the permeability of the cores was restored to original levels by soaking the wellbore face of the cores at balance for 24 hours with 15% acetic acid under reservoir conditions. The full restoration of permeability by non-invasive soaking of the core faces with dilute organic acid at balance suggested that the source of the tractable impairment was residual CaCO3/polymer filter cake still pressed onto the core face after lengthy drilling fluid exposure at overbalance and a very short clean up by drawdown.
The six Huldra production wells were drilled with SG 1.92 formate fluid at 37°-54° inclinations through the Tarbert, Ness, Etive and Rannoch reservoir formations and completed in open hole with 300-micron single-wire-wrapped screens. The wells cleaned up naturally during production start-up, without the need for acid treatment, resulting in skins that were at the low end of the expected range. The Hudra field was shut down in 2014 after producing 17.3 GSm3 of gas, representing an 80% recovery of the original gas in place.
This has been a useful first appraisal of a set of historical return permeability test results obtained with heavy K/Cs formate fluids. As more data become available from other HPHT gas condensate fields developed entirely with heavy formate brines (e.g. the Kvitebjørn and Martin Linge fields) it may become possible to assign some predictive value to the results of return permeability tests with these fluids.
Abouie, Ali (The University of Texas at Asutin) | Korrani, Aboulghasem Kazemi Nia (The University of Texas at Austin) | Shirdel, Mahdy (The University of Texas at Austin) | Sepehrnoori, Kamy (The University of Texas at Austin)
Scale deposition in surface and subsurface production equipment is one of the common problems during oil production, resulting in equipment corrosion, wellbore plugging, decrease in production rate, and frequent remediations. In this work, a detailed procedure is presented through which a compositional wellbore simulator is developed with the capability of modeling comprehensive geochemical reactions.
The compositional wellbore simulator (UTWELL) is developed by applying different numerical approaches and flow-regime-detection methods to accurately model multiphase flow in the wellbore. In addition, several deposition mechanisms are incorporated for the transportation, entrainment, and deposition of solid particles in the wellbore. Subsequently, a geochemical module, IPhreeqc, is integrated into the wellbore model to handle homogeneous and heterogeneous, reversible and irreversible, and ion-exchange reactions under either local-equilibrium or kinetic conditions. This package provides a robust, flexible, and accurate integrated tool for mechanistic modeling of scale deposition in the wellbore.
Through our integrated simulator, deposition profiles of carbonate and sulfate scales in the wellbore are predicted for several case studies. Significant effects of physiochemical properties (such as pressure, temperature, salinity, and pH value) on the scale deposition in the wellbore are discussed. In addition, comparing simulation results with experimental data reveals that hydrocarbon-phase dissolution has a significant effect on geochemical calculations compared with the temperature/pressure variation effects.
To the best of our knowledge, there is no comprehensive simulator available in the industry through which scale deposition in the wellbore can be predicted accurately. In this paper, scale deposition profile in the wellbore is estimated by including the interaction of the hydrocarbon and aqueous phases and its effect on the aqueous-scale geochemistry (by use of a compositional wellbore simulator); effects of parameters that vary greatly in the wellbore (pressure, temperature, and pH value); and comprehensive geochemistry simulation (provided through coupling of the wellbore simulator with IPhreeqc). The outcome of this study yields a comprehensive tool for scale deposition prediction in the wellbore and will help scale deposition risk-management and mitigation plans.
Nitrate has been used to control Sulphate Reducing Bacteria (SRB) in oil and gas reservoirs. Nitrate is thermodynamically a strong oxidizer, which could increase carbon steel corrosion rates yet; literature documenting the effect of nitrate on corrosion is scarce and contradictory.
This study investigated the effect of nitrate on carbon steel corrosion under simulated oilfield produced water (rich in carbon dioxide with pH~5) and simulated seawater (minimum carbon dioxide and a pH~7). CO2 corrosion tests were conducted with carbon steel X65 exposed to uninhibited brines at 25°C, 60°C, and 80°C via rotating cylinder electrode (RCE). Inhibited synthetic brine was tested under acidic environments at 80°C. Changes in nitrate, nitrite, ammonium and ferrous ions were monitored using ion chromatography.
The results provide experimental evidence to demonstrate that the corrosivity of nitrate strongly depends on pH. Nitrate tends to increase CO2 corrosion rates in the presence of synthetic produced brine (pH~5) and is relatively benign when added to synthetic seawater (pH~7). At the conditions tested, nitrite impurities contained within the source of nitrate tend to increase carbon steel corrosion exposed to synthetic brines.
In the presence of metallic iron and under CO2 environments, nitrate reduces to ammonium, which is thermodynamically stable in acid solutions. The reduction of nitrate can be modelled based on first order kinetics. The main factors promoting the reduction of nitrate are pH, iron to nitrate ratio, and temperature.
Scale deposition in surface and subsurface production equipment is one of the common problems during oil production resulting in equipment corrosion, wellbore plugging, decrease in production rate, and frequent remediations. In this work, we present a detailed procedure through which a compositional wellbore simulator is developed with the capability of modeling comprehensive geochemical reactions.
The compositional wellbore simulator (UTWELL) is developed by applying different numerical approaches and flow regimes to accurately monitor multiphase flow in the wellbore. In addition, several deposition mechanisms are incorporated and validated against experimental data to study the transportation, entrainment, and deposition of solid particles in the wellbore. Subsequently, a geochemical module (i.e. IPhreeqc) is integrated into the wellbore model to handle homogenous and heterogeneous, reversible and irreversible, and ion-exchange reactions under either local equilibrium or kinetic conditions. This package provides a robust, flexible, and accurate integrated tool for mechanistic modeling of scale deposition in the wellbore.
Through our integrated simulator, deposition profiles of carbonates and sulfates scales in the wellbore are predicted for several realistic case studies. Significant effects of physiochemical properties (i.e. pressure, temperature, salinity, and
To the best of our knowledge, there is no comprehensive simulator available in the industry through which scale deposition in the wellbore can be predicted accurately. In this work, by including 1) the interaction of the hydrocarbon phases on the aqueous-scale geochemistry (by using a compositional wellbore simulator) 2) effects of parameters that vary greatly in the wellbore (i.e. pressure, temperature, and
Disproportionate permeability reduction (DPR) may provide field solutions to address high volumes of water production and efficiency of oil recovery in non-communicating layered reservoirs. This work evaluates the lab-scale DPR effectiveness at different formation wettability conditions using an environmentally friendly, water-soluble, silicate gelant. A robust, time/temperature stable and easy-to-design water-soluble silicate gelant system is utilized to conduct DPR treatments in oil- and water-wet cores using a newly established steady-state, two-phase chemical system placement. The experimental procedure is applied to ensure the presence of moveable oil saturation at which the injected DPR fluid (gelant) gels in the treated zone and to quantitatively control the placement saturation conditions in the formation. DPR treatments are conducted using a steady-state, two-phase (oil/gelant) placement to better control the water/oil saturation at which the silicate gel sets. The performance of water-soluble, silicate-based DPR treatments are evaluated using pre- and post-treatment two-phase (brine/oil) steady-state and unsteady state permeability measurements.
Strongly water-wet Berea cores are chemically treated to alter their wettability to oil wet and measured phase effective permeability curves are used to characterize the newly established core wettability. Treatment design should include filterability/injectivity and rheological studies of the DPR fluid to evaluate gelant interaction with the formation as well as gelation time and kinetics. Single-phase DPR fluid injectivity through Berea cores is excellent. At relatively high watercuts in water-wet cores, two-phase DPR-fluid/oil injectivity is good and even better in oil-wet cores regardless the watrecut. At relatively low watercuts in water-wet cores, the injectivity is not as good as in higher watercuts and the mobility reduction keeps increasing with the co-injection of the DPR-fluid/oil.
DPR-fluid/oil placement experiments conducted at the same saturation conditions and water/oil ratio (WOR) showed that the ultimate oil residual resistance factor in oil-wet cores is significantly lower than the one in water-wet cores. This is mainly due to more favorable oil-phase continuity and distribution in oil-wet media compared to the corresponding ones in water-wet formations. In water-wet cores, encapsulation of oil by gel may cause oil-phase discontinuities and porous medium conductivity reduction. Wettability tests have shown that silicate gel is strongly water-wet. Therefore, in oil-wet DPR treatments, formed gel in porous media yields a mixed-wet formation and a lower trapped oil saturation compared to the water-wet formation.
In either wetting state, relative permeability hysteresis was insignificant during the post-DPR treatment imbibition/drainage cycles. This also reflects stable gels during post-DPR treatment floods. DPR treatments conducted at high WOR in oil-wet cores have shown a minor gel "erosion" during the post-treatment two- and single-phase (water) injection; gel "erosion" ceased during oil injection. DPR treatments conducted at high WOR caused an increase in residual resistance factor (
They are also required to run their corrosion tests for the same duration as the proposed field operations, or as long as practically possible in the case of packer fluid applications. The need for more realistic and discriminatory corrosion testing was exposed by a series of well tubular failures in the field caused by stress corrosion cracking (SCC) of CRAs following exposure to halide brines [Mack et al, 2002; Mowat et al, 2001; Stevens et al, 2004; Ueda et al, 2003; McKennis et al, 2009]. The purpose of this paper is to review the current state of knowledge about the long-term compatibility of formate brines with metals under the conditions found in deep HPHT gas wells. The review starts by examining what is known about the chemistry of formate brines under hydrothermal conditions, and their interaction with metals, particularly when contaminated by influxes of oxygen and acid gases. The paper then moves on to look at how laboratories have attempted to reproduce well conditions in their predictive corrosion tests with formate brines. Finally the paper compares laboratory test results to date against observations from 20 years of field use of formate brines in predominantly HPHT wells. Formate Chemistry and Interactions with Metals In order to understand how formate brines interact with metals in corrosive HPHT environments it is necessary to be aware of the chemistry of formates and the carbonate/bicarbonate buffer used to maintain the brine pH at its natural alkaline levels.