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Iron sulfide deposition is a ubiquitous phenomenon in sour oil and gas wells and presents unique challenges for its control and management downhole. The majority of current FeS anti-scale chemical technologies tend to be ‘reactive’ rather than ‘proactive’ for downhole scale mitigation, and currently there are few FeS scale inhibitor squeeze options available. The following paper details work performed to modify an existing novel and unique sulfide scale inhibitor to further enhance its sulfide scale inhibition efficacy and to reconfigure the polymer molecule structure for improved adsorption / desorption behavior sufficient to allow squeeze application for control and mitigation of FeS scale downhole.
All new polymeric inhibitor chemistries were tailored for high total dissolved solid (TDS) and high downhole temperature chalk sour gas well application. Further ranking was performed via automated static adsorption tests, iron sulfide efficacy tests and high calcium brine compatibility jar tests to identify the best squeeze applicable candidates for final formation damage coreflood testing.
Introduction of new anchor group functionality into the polymer resulted in improved adsorption behavior (identified via the static adsorption test), while having minimal impact on the inhibitors high TDS / high calcium brine tolerance and also on its FeS scale inhibition performance. The kinetic adsorption study showed > 2 mg inhibitor/g rock adsorption on field analogous chalk rock, which is markedly higher compared to the original parent sulfide inhibitor molecule or other new polymeric variants synthesized without the new anchor groups. FeS scale inhibitor adsorption was further improved by optimizing the ratio of monomer and functional groups on the polymer. Simulated field squeeze coreflood testing revealed no appreciable formation damage to outcrop core analogue under simulated field application conditions and the new variant inhibitor chemicals also showed significant useful adsorption/desorption behaviour.
The new polymeric scale inhibitors are suitable for both continuous injection and squeeze application for control of FeS scale in high temperature and high calcium ion sour gas chalk wells. For squeeze application, testing revealed a low formation damage potential combined with significant chemical retention for potentially extended squeeze lifetime in the field. Ultimately this technology heralds a new era in downhole scale management for sour producer wells plagued by FeS scale via reduction of treatment frequency for assured well integrity.
Scale deposition is one of the most common challenges encountered in oil and gas wells. Mature fields tend to have these issues, but tackling scale removal requires tedious diagnostic and intervention work due to uncertainty in determining the exact location and source of scale.
Production decline was observed in a High-Pressure High Temperature (HPHT) gas producer. Well testing was performed to assess and diagnose the production impairment. The preliminary well test data interpretation highlighted positive skin which needed to be characterized. Scale and even sand were considered as a possible cause of production impairment due to the nature of production chemistry and reservoir type, but the hypothesis lacked physical evidence in the wellbore.
A structured approach was adopted to identify, qualify and rectify the situation. High Pressure Coiled Tubing (HPCT) technology capable of providing real time down hole communication was utilized along with coiled tubing mounted downhole camera (DHC) to determine if the wellbore conditions were contributing towards the production decline resulting in a positive skin. The real time images acquired during the downhole camera run revealed astonishing details of the scale that was causing an impact in the production and the flowing wellhead pressure. The high-resolution images obtained during the well intervention clearly pin-pointed at the root cause of production loss and aided in designing a focused treatment for the challenge at hand. Given the sensitive nature of reservoir and possible interaction between the scale dissolving chemicals and reservoir, a customized treatment was formulated. The treatment design exploited the benefits of scale dissolution while preventing reservoir damage. The treatment was pumped using coiled tubing with a high-pressure jetting and rotating nozzle to ensure 360 degree wellbore coverage.
The well was opened to flow immediately after execution of the treatment. The post treatment flowback results indicated a resounding success with production almost quadrupling. A production log was subsequently performed to understand and gauge reservoir performance. The results of production logging further endorsed the fact that skin damage due to scale had been successfully removed and wellbore skin was reduced.
Sour oil and gas production is commonly associated with sulfide scaling challenges originating from the produced aqueous phase. Iron sulfide (FeS) is one of the most common sulfide scales, and recent studies have shown promising dispersant chemicals are available to mitigate its deposition. In addition, successful applications have been reported in the literature, particularly from the North Sea. However, some of the limitations of these FeS chemical dispersants become evident under more severe (high H2S) sour conditions, such as those found in the Middle East, Russia and Canada.
The dispersant efficiency depends on the scale particle size, and larger particle sizes usually require higher dispersant dosages. Other factors that may influence the inhibitor dosage include reactant concentrations (cations and anions), pH, salinity and inhibition time. These factors were investigated using a newly developed anaerobic experimental setup that allows the careful addition and withdrawal of fluids from a closed anoxic system. Anaerobic vessels, such as vials and tubes, are deployed equipped with septa (thin membranes). Syringes were used to infiltrate the septum with minimal interference from sulfide retention while maintaining isolation from atmospheric oxygen.
Testing was performed over a sulfide concentration range from 100 to 1,000 mg/L. Higher levels of sulfide required higher loadings of scale inhibitor, essentially as a result of particle size increase. In addition, varying the salinity also had a significantly influence on the required dispersant concentration to maintain FeS suspension in solution. At lower pH condition, smaller FeS particles were produced and often inhibition was somewhat obscured by solubility effects. Also, suspending the FeS for longer periods of time required higher dispersant concentrations.
More severe sour conditions exceeding 1,000 mg/L of aqueous sulfide, have a detrimental effect on the both the efficiency and economics of the FeS inhibition treatments. In addition, the current high- performance dispersants cannot be squeezed into tight formations or shales, as their high molecular weight may cause severe formation damage. For such applications, alternative inhibition methodologies are required, and non-chemical inhibition may be considered.
Scale formation is mostly governed by scaling ion concentrations and fluid conditions (pressure, temperature, and pH). Sulfide scale formation is most commonly initiated through the mixing fluids containing scaling cations (Fe2+, Zn2+ and Pb2+) or sulfidic anions (H2S(aq), HS- and S2-), or, more rarely, in a single fluid containing both ions which is undergoing physical condition changes, such as a pressure drop or pH change. The literature has extensive reviews of sulfide scales formed by mixing two fluids in both static and dynamic tests. The self-scaling of metal sulfides in a single fluid, however, has been less investigated.
An experimental setup and procedure have been developed to investigate the impact of various factors, such as pH (0 - 10), sulphide and metal ion concentrations and salinity (3.5 - 20 wt. %), on the formation of sulfide scales in general and iron sulfide (FeS) in particular. This new setup provides anaerobic conditions to isolate and prevent the interference of atmospheric oxygen, while retaining aqueous and gaseous sulfide in solution. The setup is comprised of airtight vials and Hungate-type tubes equipped with septum-caps to facilitate the gas-tight liquid transfers required in such experiments. The concentrations of sulfide ranged from 100 to 1,000 mg/L, and iron, zinc and lead were studied at levels in the range of 50 - 100 mg/L.
The formation of sulfide scales was measured by monitoring the depletion of cation concentration in aqueous solution at various pH values. The excess amount of sulfide concentration significantly affected the formed iron sulfide by affecting the pH at which initial cation depletion occurred. The higher sulfide excesses gave an FeS precipitation onset at lower pH levels, and larger FeS particle size than lower levels of sulfide excess.
These findings directly affect the scale inhibition design, as most sulfide scale control chemicals are dispersants. Therefore, particle size is very relevant to these dispersants in terms of the inhibitor loading and efficiency. The assumption that sulfide scale is principally reliant on the cation concentration, particularly if limiting, is inaccurate, and sulfide excess must also be quantified and taken into consideration in the inhibition design.
Surfactant based foams are used as one of the most effective techniques in controlling gas mobility during gas injection processes. Foam reduces gas mobility in porous media by increasing the gas apparent viscosity and decreasing the gas relative permeability, and hence it helps in improving sweep efficiency. However, one of the critical encounters when using foam in reservoirs is the adsorption of the surfactant on the rock surface. The loss of surfactant to the rock surface will lead to destabilizing the foam and accelerating the collapse rate of foam films. The objective of this paper is to study the behavior of surfactant adsorption in carbonate.
The adsorption of various surfactants in contact with carbonate was evaluated. We compared two different techniques to evaluate the adsorption of surfactant components onto the rock surface. The first method is using a total organic carbon (TOC) analyzer to measure the carbon number in each surfactant over time after being in contact with rock. The second method is using UV-spectroscopy in which the light absorbance at a certain wavelength is measured. The measurements are then used to calculate the total surfactant adsorption onto the rock surface. This paper presents the adsorption behavior of each surfactant studied in detail.
The results obtained by the techniques were compared for two different surfactants. An amphoteric surfactant and an anionic surfactant were used in this study. Results illustrated that both surfactants were adsorbed by the rock minerals. Surfactant 1 showed a higher adsorption value than the surfactant 2. However, the two used techniques to measure the adsorption showed different adsorption values for both surfactants. Using TOC, surfactants 1 and 2 showed a total adsorption of 0.746 and 0.428 mg/grock, respectively. While, using UV-spectroscopy, surfactants 1 and 2 showed a total adsorption of 1.149 and 0.306 mg/grock, respectively.
Understanding the surfactant adsorption behavior is an essential step in the surfactant selection process. Selecting a surfactant with minimal loss to the rock surfaces will lead to keeping the generated foam stable for a longer time in the reservoir and therefore, result in having a higher sweep efficiency.
History matching field performance is a time-consuming, complex and non-unique inverse problem that yields multiple plausible solutions. This is due to the inherent uncertainty associated with geological and flow modeling. The history matching must be performed diligently with the ultimate objective of availing reliable prediction tools for managing the oil and gas assets. Our work capitalizes on the latest development in ensemble Kalman techniques, namely, the Ensemble Kalman Filter and Smoother (EnKF/S) to properly quantify and manage reservoir models’ uncertainty throughout the process of model calibration and history matching.
Sequential and iterative EnKF/S algorithms have been developed to overcome the shortcomings of the existing methods such as the lack of data assimilation capabilities and abilities to quantify and manage uncertainties, in addition to the huge number of simulations runs required to complete a study. An initial ensemble of 40 to 50 equally probable reservoir models was generated with variable areal, vertical permeability and porosity. The initial ensemble captured the most influencing reservoir properties, which will be propagated and honored by the subsequent ensemble iterations. Data misfits between the field historical data and simulation data are calculated for each of the realizations of reservoir models to quantify the impact of reservoir uncertainty, and to perform the necessary changes on horizontal, vertical permeability and porosity values for the next iteration. Each generation of the optimization process reduces the data misfit compared to the previous iteration. The process continues until a satisfactory field level and well level history match is reached or when there is no more improvement.
In this study, an application of EnKF/S is demonstrated for history matching of a faulted reservoir model under waterflooding conditions. The different implementations of EnKF/S were compared. EnKF/S preserved key geological features of the reservoir model throughout the history matching process. During this study, EnKF/S served as a bridge between classical control theory solutions and Bayesian probabilistic solutions of sequential inverse problems. EnKF/S methods demonstrated good tracking qualities while giving some estimate of uncertainty as well.
The updated reservoir properties (horizontal, vertical permeability and porosity values) are conditioned throughout the EnKF/S processes (cycles), maintaining consistency with the initial geological understanding. The workflow resulted in enhanced history match quality in shorter turnaround time with much fewer simulation runs than the traditional genetic or Evolutionary algorithms. The geological realism of the model is retained for robust prediction and development planning.
Enhanced oil recovery (EOR) techniques often involve delivering chemicals, macromolecules, or particles in oil reservoirs to improve oil mobility and production. The harsh environment typical to the reservoir poses a great challenge to maintaining long-term stability of these agents. Moreover, accessing constricted regions in the reservoir with extremely tight pores and pore throats, and where large volumes of resources exist, require more efficient delivery methods than diffusion.
We have developed an in-house EOR nano-agent (NanoSurfactant) platform using the inexpensive and abundant petroleum sulfonate salt surfactant. NanoSurfactants are chemically and colloidally stable at high salinity (> 56K ppm) and high temperature (> 90°C) conditions. Their structure, size, and surface properties suggest different transport mechanisms for enhanced delivery in oil reservoirs compared to conventional surfactants. We seek to improve the delivery of NanoSurfactants to regions in the reservoir that are inaccessible to conventional waterflood. Here, we explore diffusiophoresis (DP) as a mean to efficiently deliver NanoSurfactants to flow-restricted regions.
Direct microscopic visualization experiments are conducted to study the migration of NanoSurfactants in different chemical gradients. These transient gradients are established in microfluidic channels mimicking dead-end pores in the reservoir. In addition, we study the effect of adding dilute macromolecules to the NanoSurfactant solutions on their DP migration. NanoSurfactants are labeled with a fluorescent dye to enable microscopic visualization and quantification of DP migration. Results showed that salinity gradients yield faster and deeper delivery of NanoSurfactants into the dead-end channels compared to diffusion without any gradients. A more pronounced migration is observed when small concentrations of macromolecules are added.
Our findings expand the understanding of DP migration in an extremely high salinity environment. In addition, they provide insights into the utilization of natural or induced gradients in oil reservoirs to harness the DP migration for EOR applications.
Many oil reservoirs worldwide have cycle dependent oil recovery either by design (e.g. WAG injection) or unintended (e.g. repeated expansion/shrinkage of gas cap). However, to reliably predict oil recovery involving three-phase flow process, a transformational shift in the procedure to model such complex recovery method is needed. Therefore, this study focused on identifying the shortcomings of the current reservoir simulators to improve the simulation formulation of the cycle-dependent three-phase relative- permeability hysteresis.
To achieve this objective, several core-scale water-alternating-gas (WAG) injection experiments were analysed to identify the trends and behaviours of oil recovery by the different WAG cycles. Furthermore, these experiments were simulated to identify the limitations of the current commercial simulators available in the industry. Based on the simulation efforts to match the observed experimental results, a new methodology to improve the modelling process of WAG injection using the current simulation capabilities was suggested. Then the WAG injection core-flood experiments utilized in this study were simulated to validate the new approach.
The results of unsteady-state WAG injection experiments performed at different conditions were used in this simulation study. The simulation of the WAG injection experiments confirmed the positive impact of updating the three-phase relative-permeability hysteresis parameters in the later WAG injection cycles. This change significantly improved the match between simulation and WAG experimental results. Therefore, a systematic workflow for acquiring and analyzing the relevant data to generate the input parameters required for WAG injection simulation is presented. In addition, a logical procedure is suggested to update the simulation model after the third injection cycle as a workaround to overcome the limitation in the current commercial simulators.
This guideline can be incorporated in the numerical simulators to improve the accuracy of oil recovery prediction by any cycle-dependent three-phase process using the current simulation capabilities.
Reservoir simulation is becoming a standard practice for oil and gas companies, helping with decision making, reducing reservoir characterization uncertainties, and better manage hydrocarbon resources. The reservoir model sizes can reach multi-billion grid cells, which led Saudi Aramco to develop an in-house massively parallel reservoir simulator, as well as a pre- and post-reservoir simulation environment [Dogru et al. 2002]. Compared to structured grid modeling, unstructured grid modeling and billon cell pre- and post-simulation processing of reservoir simulation provides engineers with advanced modeling capabili- ties to represent complex well geometries and near wellbore modeling. Mapping between structured and unstructured (2.5D) domains is not a straightforward task. The indexing in unstructured grids makes cre- ating property modifiers, do near wellbore modeling, and local grid refinement (LGR) difficult.
We present a developed workflow to automatically transform the modeling of property modifiers, near wellbore modeling and LGR between the structured and unstructured domains. Several Computational Geometry algorithms were developed for efficiency and accuracy, which preprocess the corners of top layer cells into data structures. To map regions of interest (ROIs) between domains, the algorithms find all corner points inside them. The regions are translated using the algorithms and the results are exported in the unstructured format. The two challenges are that the number of corner points is massive, therefore, a brute-force search even for a simple ROI is expensive, and irregular ROIs result in very costly search complexity. We address these by preprocessing the input data in the form of range trees. We also propose a free-shape polygonal search strategy to find all corner points in the ROI.
The range tree algorithm provided a fast and robust workflow to perform the transformation from struc- tured to unstructured gridding domains, while providing ease of use with a visual component, to aid with property transformation, near wellbore modeling and LGR. The algorithm’s performance was measured using the time complexity of the preprocessing time, query time, and the space complexity. The range tree approach is fast compared to the other approaches, requiring only O(log(n)+k) operations, compared to the O(n) of linear search. It takes a costly O(nlog(n)) time to preprocess the data into the range tree, however, that is a one-time cost, as well as requiring O(nlog(n)) space in memory. This work is a major milestone to promote and support the unstructured grid modeling approach for large- and small-scale res- ervoir simulation models. The algorithm will provide engineers with a simplified workflow and smooth transitioning, allowing advanced capabilities to model complex well geometries and near wellbore mod- eling, while preserving complex geological features. In addition, this algorithm provides the building blocks in facilitating the migration and conversion of existing structured simulation models.
Seright, Randall S. (New Mexico Institute of Mining and Technology) | Wavrik, Kathryn E. (New Mexico Institute of Mining and Technology) | Zhang, Guoyin (New Mexico Institute of Mining and Technology) | AlSofi, Abdulkareem M. (Saudi Aramco)
The goal of this work was to identify viable polymers for use in the polymer flooding of high-temperature carbonate reservoirs with hard, saline brines. This study extensively examined recent enhanced-oil-recovery (EOR) polymers for stability, including new 2-acrylamido-tertbutylsulfonic acid (ATBS) polymers with a high degree of polymerization, scleroglucan, n-vinylpyrrolidone (NVP) -based polymers, and hydrophobic associative polymers. For each polymer, stability experiments were performed over a 2-year period under oxygen-free conditions (less than 1 ppb) at various temperatures up to 180°C in brines with total dissolved solids (TDS) ranging from 0.69 to 24.4%, including divalent cations from 0.034 to 2.16%. Use of the Arrhenius analysis was a novel feature of this work. This rarely used method allows a relatively rapid assessment of the long-term stability of EOR polymers. Rather than wait years or decades for results from conventional stability studies at the reservoir temperature, reliable estimates of the time-temperature stability relations were obtained within 2 years. Arrhenius analysis was used to project polymer-viscosity half-lives at the target reservoir temperature of 99°C. The analysis suggests that a set of ATBS polymers will exhibit a viscosity half-life over 5 years at 120°C and over 50 years at 99°C, representing a novel finding of this work and a major advance for extending polymer flooding to higher temperatures.
For five polymers that showed potential for application at higher temperatures, corefloods were performed under anaerobic conditions. Another novel feature of this work was that anaerobic floods were performed without using chemical oxygen scavengers, chemical stabilizing packages, or chelating agents (that are feared to alter rock properties). Using carbonate cores and representative conditions, corefloods were performed to evaluate polymer retention, rheology in porous media, susceptibility to mechanical degradation, and the residual resistance factor for each of the polymers at 99°C.