Produced water composition analysis provides evidence of what geochemical reactions are taking place in the reservoir. This information can be useful for predicting and managing oilfield mineral scale resulting from brine supersaturation.
This paper presents results of a study of the produced brine compositions from three wells in a field operated in the North Sea, with geochemical modelling complementing the analysis. The findings presented in this work provide evidence of magnesium depletion and sulphate retardation in a sandstone reservoir at 130° C.
This adjusted formation water composition was then used for calculations of the injection water fraction in each of the produced water samples. The Reacting Ions Toolkit was used to plot data in a variety of formats, including ion concentration vs. ion concentration, ion concentration vs. injection water fraction and ion concentration vs. time to identify trends and to examine the extent of involvement of the various ions in geochemical reactions.
The breakthrough of sulphate, a component primarily introduced during seawater flooding, was retarded during injection water breakthrough. Observed sulphate concentrations were lower than predicted for the case of brine/brine interactions only. The implication of this sulphate reduction was lower minimum inhibitor concentration required to control scale formation and longer squeeze treatment lifetimes for the operator.
A brine/rock interaction mechanism was proposed that involves magnesium depletion and is reproduced in the reactive transport model. 1D reactive transport modelling was performed to match possible
The practice of squeeze treatments to oil/gas production wells to prevent inorganic scale formation has been applied for over 30 years and during that period different mechanisms to retain the inhibitor chemical have been evaluated. The simple mechanism of inhibitor retention, adsorption/desorption has been complemented over the years by enhanced adsorption via mutual solvent and full precipitation of the active inhibitor onto the mineral surface of the reservoir.
Previously published studies have shown that the retention of phosphonate scale inhibitors in sandstone reservoirs can be enhanced through the addition of a ‘squeeze life enhancer’. This chemical, typically, a highly charged, low molecular weight polymer can be applied in either the preflush or overflush stage of the scale squeeze treatment. To date these studies have been conducted using low temperature (85°C) sandpack testing.
This paper details the laboratory work carried out under high temperature (146°C) field conditions to qualify the use of the squeeze life enhancer for field application.
The results of the formation damage/inhibitor return corefloods using an MEA phosphonate (EABMPA, Ethanolaminebis(Methylene Phosphonic Acid)) and polymeric squeeze life enhancer additive are presented. The coreflood results indicated that the addition of the additive within the overflush stage of the squeeze program resulted in a 19% extension of the inhibitor lifetime. The ability to extend the squeeze treatment was translated into reduced injected squeeze fluid treatment volume as injected fluid volumes was an issue for the wells being treated and therefore reduced associated oil deferment costs.
The paper will also present field data obtained from the initial two field trial treatments which were carried out in a North Sea field. The trial well had been treated more than ten times previously with the same MEA phosphonate as applied in the enhancer trial making direct comparison of the treatment performance possible. The treatment program applied to the wells resulted in no change to the clean-up rates of the treated well and no process upset during well reflow. The initial scale inhibitor returns from the field trial treatments showed the expected improvement suggested from the coreflood study.
The study brings value to the industry by providing the process to follow for qualifying and trialling a new technology in a challenging high temperature scaling environment with the results from the field supporting the carefully designed chemical selection and evaluation program.
The effects of H2S on system integrity, sulphide scaling potential and health and safety in oil and gas production is well recognized and understood. However, as part of a wider study on pH dependent scale predictions, the authors have identified an additional challenge associated with the presence and/or development of H2S in reservoirs containing carbonates: higher H2S concentration reflects in higher calcium carbonate scaling potential. The intention of this work is to demonstrate the impact of H2S using a real field case scenario and investigate how the variability in water cut, aqueous phase composition, CO2 and H2S concentration can impact the well carbonate scaling potential and ultimately its productivity.
To model pH dependent scales correctly, it is necessary to integrate PVT calculations with the aqueous phase thermodynamic mineral scaling calculations. This has been extensively discussed in previous publications by the authors. For this work, a commercial integrated PVT and scale prediction software package was used to determine the scale prediction profile from reservoir to the first stage of topside separation. In addition, to investigate the impact of PVT on the final results, a second PVT software employing a different equation of state (EOS) is used and the results obtained from this calculations are coupled with the same aqueous phase model using the Heriot-Watt scale prediction workflow.
The well selected for this study shows productivity issues as well as signs of presence of calcium carbonate scale. However, scale prediction calculations carried out in the past did not show any potential for carbonate scale formation at the given conditions. After rigorously accounting for variations in water cut over time, as well as for increased H2S due to reservoir souring, our work clearly shows a correlation between a gradual loss of well productivity and carbonate scaling potential.
This work clearly demonstrates the impact of H2S on calcium carbonate scaling potential and highlights the importance of correctly modelling CO2 and H2S partitioning in gas/oil/water at the different stages of production, from reservoir to topside separation. Following this study, it has also been possible to offer specific well treatment and testing recommendations to verify the results and try to obtain improvements in production efficiency.
Moreover, the application of our approach to a real field scenario shows how some field findings associated with carbonate scale problems can be explained only by correctly modelling the full three phase system (oil, gas and water). Some aspects of this approach are frequently overlooked and not linked correctly to carbonate scale formation.
An Excel-based tool was developed that uses cubic-equation-of-state (EOS) and thermodynamic electrolyte-chemistry modeling to assess sour-production streams from a reservoir, through production tubing, pipelines, and facilities to an export pipeline within a range of temperature and pressure conditions. The approach is need to assess the integrity risk posed to system components in the Alba field in the North Sea. To accurately determine multiphase sulfide concentrations, and therefore hydrogen sulfide (H2S) partial pressures and the resulting integrity threat in sour-production streams, it is first important to understand the pH-dependent distribution of the three species of sulfide that may be present in an aqueous solution. Many commercially available EOS software packages do not take into account aqueous pH- and speciation-driven aqueous sulfide solubility. They merely assume that the gas-phase and oil-phase H2S remains as H2S in all three phases and, as such, that the aqueous solubility is limited by the solubility of the H2S species in water.
Standard history matching workflows use qualitative 4D seismic observations to assist in reservoir modeling and simulation. However, such workflows lack a robust framework for quantitatively integrating 4D seismic interpretations. 4D or time-lapse seismic interpretations provide valuable inter-well saturation and pressure information and quantitatively integrating this inter-well data can help to constrain simulation parameters and improve the reliability of production modeling. This paper outlines technologies aimed at leveraging the value of 4D for reducing uncertainty in the range of history matched models and improving the production forecast.
The proposed 4D Assisted History Match (4DAHM) workflows utilize interpretations of 4D seismic anomalies for improving the reservoir simulation models. Design of Experiments (DOE) is initially used to generate the probabilistic history match simulations by varying the range of uncertain parameters. Saturation maps are extracted from the Production History Matched (PHM) simulations and then compared with 4D predicted swept anomalies. An automated extraction method was created and is used to reconcile spatial sampling differences between 4D data and simulation output. Interpreted 4D data is compared with simulation output, and the mismatch generated is used as a 4D filter to refine the suite of reservoir simulation models. The selected models are used to identify reservoir simulation parameters that are sensitive for generating a good match.
The application of 4DAHM workflows has resulted in reduced uncertainty in volumetric predictions of oil fields, probabilistic saturation S-curves at target locations, and fundamental changes to the dynamic model needed to improve the match to production data. Results from adopting this workflow in two different deep-water reservoirs are discussed. They not only resulted in reduced uncertainty, but also provided information on key performance indicators that are critical in obtaining a robust history match. In the first case study presented, the deep-water oil field 4DAHM resulted in a reduction of uncertainty by 20% in OOIP and by 25% in EUR in the P90-P10 range estimates. In the second case study, 4DAHM workflow exploited discrepancies between 4D seismic and simulation data to identify features necessary to be included in the dynamic model. Connectivity was increased through newly interpreted inter-channel erosional contacts, and sub-seismic faults. Moreover, the workflow provided an improved drilling location which has the higher probability of tapping unswept oil and better EUR. The 4D filters constrained the suite of reservoir simulation models and helped to identify 4 out of 24 simulation parameters critical for success. The updated PHM models honor both the production data and 4D interpretations, resulting in reduced uncertainty across the S-curve and, in this case, an increased P50 OOIP of 24% for a proposed infill drilling location, plus a significant cycle-time savings.
This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Houston, Texas, USA, 23-25 July 2018. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC.
The practice of scale squeeze treatments to oil/gas production wells to prevent inorganic scale formation has been applied for over 30 years and during that period different mechanisms to retain the inhibitor chemical have been evaluated. Many of these studies have focused on sandstone reservoir with less extensive studies carried out on carbonate substrates. This paper details work carried out using'squeeze life enhancer' chemicals within the Preflush and Overflush stages utilising a copolymer containing a quaternary amine group to evaluate this chemicals effect on phosphonate scale inhibitor retention process. Phosphonate scale inhibitors are known to provide excellent squeeze lifetimes in carbonate reservoirs due to their strong interaction with the negatively charged formation using hydrogen ion bonding at low pH or calcium ion bridging at higher pH however with the aid of an enhancer chemical it was hoped to help the retention/release process and so provide further improved squeeze lifetimes. The location of the enhancer chemical within the squeeze process was the focus of the study. Enhancing adsorption of the scale inhibitor is not objective of this application study rather ensuring that the retained chemical is released into the flowing brine during production which is a challenge in carbonate reservoirs. Laboratory work will be presented which evaluates the effect of using a polyaspartate enhancer within either the preflush or overflush stages to extend the lifetime of a commonly applied phosphonate scale inhibitor. These tests have been carried out using pack floods at 85 C with synthetic Middle East produced water and the details of the extension in treatment life observed are correlated to the inhibitor type tested and the sequence of application of the polymer enhancer utilised. The study shows how the different functional groups within the scale inhibitor interact with the carbonate mineral surface and polymer enhancer to extend treatment lifetimes and so potentially reducing the frequency of squeeze treatments and therefore total cost of operations and it is order of application of these chemicals to the rock surface that prove to be critical to the extension observed.
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.
In the United Kingdom Continental Shelf (UKCS), a significant heavy oil prize of 9 billion barrels has been previously identified, but not fully developed. In the shallow unconsolidated Eocene reservoirs of Quads3 and 9, just under 3 billion barrels lie in the discovered, but undeveloped fields, of Bentley and Bressay. Discovered in the 1970s, they remain undeveloped due to the various technology challenges associated with heavy oil offshore and the presence of a basal aquifer. The Eocene reservoirs represent significant challenges to recovery due to the unconsolidated nature of the hydrocarbon bearing layers. The traditional view has been that such a nature represents a risk to successful recovery due to sand mobility; reservoir and near wellbore compaction; wormhole formation; and injectivity issues.
We propose improving the ultimate oil recovery by a combination of aquifer water production and compaction drive. By interpreting public domain data from well logs, the range of geomechanical properties of Eocene sands have been determined. A novel approach to producing the heavy oil unconsolidated reservoirs of the UKCS is proposed by producing the aquifer via dedicated water producers situated close to the oil-water contact. The location was determined by sensitivity analysis of water producer location and production rates. By locating water producers at the OWC with a production rate of 20,000 bbls/day of fluids, the incremental recovery at the end of simulation is increased by 4.1% OOIP of the total modelrelative to the ‘no aquifer production’, casesuggesting a significant increase in recovery can be achieved by producing the aquifer. A rate of 30,000 bbld/day located at the OWC was found to increase incremental recovery by 5.8 %OOIP relative to the ‘no aquifer case’. In all cases, as the reservoir fluid pressure is reduced, oil recovery increases via compaction and reduced water influx into the oil leg. This reduced pressure leads to a higher tendency towards reservoir compaction which is expressed as a change in mean effective stress and porosity reduction.
Beldongar, Maye (Schlumberger) | Agee, Daniel (Schlumberger) | Kumar, Amrendra (Schlumberger) | Offenbacher, Matthew (Schlumberger) | Flamant, Nicolas (Schlumberger) | Lees, Ashley (Schlumberger) | Gadiyar, Bala (Schlumberger) | Parlar, M. (Schlumberger)
At some stage after drilling to target depth and before pumping the gravel-packing treatment or before putting the well on production, the drilling fluid is typically displaced from the wellbore. Practices in the industry vary significantly depending on the primary drivers of the completion engineers, sometimes with undesirable results. Inefficient wellbore displacements can cause a variety of problems, including increased nonproductive time, reduced well productivity, and incomplete gravel packing through various mechanisms.
In this paper, we detail our best practices to ensure efficient wellbore displacements for sand-control completions on the basis of learnings from more than 500 openhole completions throughout the world from 2013 through 2016. In the design phase, these involve various compatibility tests, some of which are not commonly performed, and/or potential problems that cannot be identified easily when they are performed using conventional test procedures. Additional considerations include the modeling of fluid/fluid displacements and determining the fluid properties, pump rates, and fluid volumes required for effective displacements in a given wellbore geometry and flow paths. On the rigsite, they involve several quality-control tests, some of which have not been implemented previously.