Jarrahian, Khosro (Heriot-Watt University) | Sorbie, Kenneth (Heriot-Watt University) | Singleton, Michael (Heriot-Watt University) | Boak, Lorraine (Heriot-Watt University) | Graham, Alexander (Heriot-Watt University)
Scale inhibitor (SI) squeeze treatments in carbonate reservoirs are often affected by the chemical reactivity between the SI and the carbonate mineral substrate. This chemical interaction may lead to a controlled precipitation of the SI through the formation of a sparingly soluble Ca/SI complex which can lead to an extended squeeze lifetime. However, the same interaction may in some cases lead to uncontrolled SI precipitation causing near-well formation damage in the treated zone. This paper presents a detailed study of the various retention mechanisms of SI in carbonate formations, considering system variables such as the (carbonate) formation mineralogy, the type of SI and the system conditions. Apparent adsorption (Γapp) experiments, described previously (
For all SIs, both adsorption (Γ) and precipitation (�?) retention mechanisms were observed, with the dominant mechanism depending on SI chemistry, temperature and mineralogy. Differences were observed between the "apparent adsorption" (Γapp) levels of polymeric, phosphonate and phosphate ester scale inhibitors, as follows: For the polymeric SIs (PPCA, PFC and VS-Co), the highest retention levels were observed at low pH for all carbonate substrates, due to the increase in divalent cations (Ca2+ and Mg2+) available from rock dissolution for SI-M2+ precipitation. For phosphonate (DETPMP) and phosphate ester (PAPE) SIs, the retention level was greatest at higher pH values, as the SI functional groups were more dissociated and hence available for complexation with M2+ ions. The polymeric VS-Co showed the lowest amount of precipitation (Γapp ~ 1.2 mg/g) in contact with dolomite substrate due to the presence of sulphonate groups (low pKa); indeed this showed low Γapp which was predominantly pure adsorption. However, a small amount of precipitate was observed by ESEM/EDX and PSA. For polymeric inhibitors, the retention level (Γapp) was highest on calcite (highest relative calcium content), followed by limestone and then dolomite. Phosphonate and phosphate ester SIs showed the highest retention levels on dolomite (higher final solution pH and more SI dissociated), followed by limestone and calcite. For all SI species, higher retention (more precipitation, �?) was observed at elevated temperature. At lower temperatures, a more extended region of pure adsorption was observed for all SIs.
For the polymeric SIs (PPCA, PFC and VS-Co), the highest retention levels were observed at low pH for all carbonate substrates, due to the increase in divalent cations (Ca2+ and Mg2+) available from rock dissolution for SI-M2+ precipitation. For phosphonate (DETPMP) and phosphate ester (PAPE) SIs, the retention level was greatest at higher pH values, as the SI functional groups were more dissociated and hence available for complexation with M2+ ions.
The polymeric VS-Co showed the lowest amount of precipitation (Γapp ~ 1.2 mg/g) in contact with dolomite substrate due to the presence of sulphonate groups (low pKa); indeed this showed low Γapp which was predominantly pure adsorption. However, a small amount of precipitate was observed by ESEM/EDX and PSA.
For polymeric inhibitors, the retention level (Γapp) was highest on calcite (highest relative calcium content), followed by limestone and then dolomite. Phosphonate and phosphate ester SIs showed the highest retention levels on dolomite (higher final solution pH and more SI dissociated), followed by limestone and calcite.
For all SI species, higher retention (more precipitation, �?) was observed at elevated temperature. At lower temperatures, a more extended region of pure adsorption was observed for all SIs.
The information presented in this study will help us in SI product selection for application of squeeze treatments with longer squeeze lifetimes in carbonate reservoir based on mineralogy and reservoir conditions. In addition, this study provides valuable data for validating models of the SI/Carbonate/Ca/Mg system which can be incorporated in squeeze design simulations.
Arends, Olivia (Stepan Company) | Seymour, Brian (Stepan Oilfield Solutions) | Benko, Brandon (Stepan Company) | Elshahed, Mostafa (Oklahoma State University) | Yakoweshen, Lynn (Stepan Oilfield Solutions) | Ganguly-Mink, Sangeeta (Stepan Company)
Microbial-induced problems in oil and gas incur high costs and cause severe environmental and safety concerns. Most of these problems are directly caused by surface-adhered bacteria colonies known as biofilms. Distinct populations of bacteria within a biofilm can symbiotically alter surrounding conditions that favor proliferation to the extent that leads to corrosion, plugging, and H2S souring. Biocides are antimicrobial products used to eliminate and prevent bacterial growth. The purpose of this initial study is to measure performance of biocides against anaerobic planktonic and sessile bacteria. The three anaerobic conditions tested were biocide performance against planktonic bacteria, against established biofilm, and inhibition of biofilm growth.
Biocides containing two types of quaternary ammonium compounds and blends with glutaraldehyde were evaluated against sulfate reducing bacteria (SRB) and acid producing bacteria (APB) in both planktonkic and sessile forms. As expected, all of the biocides tested were effective against planktonic bacteria. Quaternary type biocides were found to be particularly effective at controlling sessile anaerobes. Surprisingly, the addition of glutaraldehyde did not appear to provide synergistic benefits and actually had a negative dilutory effect on the performance against biofilms. In all cases, dialkyl dimethyl ammonium chloride (DDAC) was the most efficient biocide in controlling all bacterial forms tested, both planktonic and sessile.
As the oil and gas industry continues to operate in more complex and deeper water environments downhole scale control via scale squeeze treatments becomes an ever-increasing technical challenge. It is therefore essential that effective scale management strategies are adopted which incorporate suitable scale inhibitor (SI) selection, analysis and treatment design procedures to provide optimal and cost-effective squeeze treatment lifetimes to maximise oil production and reduce well intervention costs.
In this paper key factors are evaluated in order to provide a guidance to selecting a suitable treatment strategy for downhole scale control in co-mingled sub-sea well and the impact of chemical retention, minimum inhibitor concentration (MIC), limit of quantifiable detection (LOQD) and well dilution factors on treatment design and strategy are discussed. The pros and cons of different treatment strategies are presented in this paper and consideration is given to following three treatment strategies: Treating all wells with the same chemical and over designing the chemical treatment lifetime ie 18 months and then re-treating all wells after 12 months; Treating individual wells with tagged versions of the same scale inhibitor chemical; Treating individual wells with different scale inhibitors.
Treating all wells with the same chemical and over designing the chemical treatment lifetime ie 18 months and then re-treating all wells after 12 months;
Treating individual wells with tagged versions of the same scale inhibitor chemical;
Treating individual wells with different scale inhibitors.
Options (ii) and (iii) offer the ability to design similar treatment lifetimes for each well but have the flexibility to monitor wells individually and re-squeeze when required.
Examples are provided for treatment options (ii) and (iii) based upon a field example to illustrate the design concepts for fluorescent (F) and phosphorus (P) tagged polymers in two co-mingled wells and a theoretical example for treating three co-mingled wells with different scale inhibitors, one of which could be a phosphonate with two tagged polymers.
This paper presents an overview of the key factors that influence chemical selection and treatment design for co-mingled wells in the same flow line. In addition, it will highlight important concepts to provide guidance for the design of effective treatment strategies for squeezing co-mingled wells in sub-sea and deepwater environments.
Paul, Ferm (Nouryon) | Jeff, Germer (Nouryon) | Kurt, Heidemann (Nouryon) | Stuart, Holt (Nouryon) | Andrew, Robertson (Nouryon) | Jannifer, Sanders (Nouryon) | Klin, Rodrigues (Nouryon) | John, Thomaides (Nouryon) | Nick, Wolf (Nouryon) | Lei, Zhang (Nouryon)
The controlled release of scale inhibitors (SI) and other treatment chemicals in the near-wellbore region is a key strategy to improving water management and extended well production. In addition, during some completion and stimulation operations, it is desired that robust particles providing controlled release be placed in gravel and sand packs. A novel controlled release scale inhibitor particle is presented which provides beneficial properties due to its unique chemistry and polymer processing methods. This technology provides extended feedback of scale inhibitor with tunable release rates.
Jordan, Myles (Nalco Champion, An Ecolab Company) | Temple, Erin (Nalco Champion, An Ecolab Company) | Sham, Anita (Nalco Champion, An Ecolab Company) | Williams, Helen (Nalco Champion, An Ecolab Company) | McCallum, Catriona (Nalco Champion, An Ecolab Company)
Inorganic scale control of sulphate and carbonate scales with polymer, phosphonate and phosphate ester scale inhibitors is well established within the oilfield service industry. The environments in which these chemical work best have been published such as vinyl sulphonates are known to be very effective for sulphate scale control in low temperatures whereas phosphonates are much less effective under these same conditions but improve at higher temperatures. What is less well understood is the potential for synergistic interaction with blends of polymers/phosphonates/phosphate esters to give reduced treatment rates, lower chemical discharge volumes and potentially lower treatment cost.
In this paper evaluation of two North Sea produced waters will be outlined. Both produced brines have a high barium sulphate scale tendency but differ in the temperature at which the fluids arrive and depart the topside process one case with a temperature of 20C and the other at 90C. Static bottle test data will be presented to evaluate the crystal growth performance of single scale inhibitors and the improvements observed when blends of these same inhibitors are applied. Select dynamic tube blocking tests data to evaluate nucleation inhibition will also be presented so that mechanism of inhibition for the blended chemicals can clearly be highlighted.
The generic inhibitor evaluated included vinyl sulphonates co polymer, phosphate esters, poly aspartic acid. In the lower temperature environment, it was observed that a vinyl sulphonate/phosphate ester blend was more effective than either of the components by themselves. Poly aspartic acid blende with phosphate ester also give a synergistic interaction but the performance of this chemical required higher treatment rates than the vinyl sulphonate co polymer blend. At higher temperature the overall treatment rates were reduced as the sulphate scale saturation values were reduced and the synergistic effects of the polymers and phosphate ester blends were evident.
As well as classic static bottle tests performance tests were carried out in the presence of reservoir solids with stirring to further understand if the interaction of the generic chemicals within the blends with suspended solids would reduce the observed performance in the solids free test solutions.
The current regulatory challenges with REACH mean that the methods outlined in this study offer the potential to reduce chemical treatment rate, cost and environmental impact by evaluating the synergistic interaction of the current range of commercially available scale inhibitors so cutting out the very high registration costs/ time delays to the market associated with new molecule development.
Zhao, Yue (Rice University) | M. Sriyarathne, H. Dushanee (Rice University) | Harouaka, Khadouja (Rice University) | Paudyal, Samridhdi (Rice University) | Ko, Saebom (Rice University) | Dai, Chong (Rice University) | Lu, Alex Yi-Tsung (Rice University) | Deng, Guannan (Rice University) | Wang, Xin (Rice University) | Kan, Amy T (Rice University) | Tomson, Mason (Rice University)
Silica is ubiquitous in oil and gas production water because of quartz and clay dissolution from rock formations. Furthermore, the produced water from unconventional production often contains high Ca2+, Mg2+ and Fe2+ concentrations. These common cations, especially iron, can form aqueous or surface complexes with silica and affect the nucleation inhibition of other scales such as barite. Thus, it is important to investigate the silica matrix ion effects on barite scale inhibitors efficiency to evaluate inhibitor compatibility with silica and common cations in produced waters.
In this study, experimental conditions were varied from 50 mg/L to 160 mg/L SiO2 in the presence of Ca2+ (1,000 and 16,000 mg/L), Mg2+ (2,000 mg/L) and Fe2+ (10 mg/L) at 70°C and neutral pH conditions, all with a background of 1 M NaCl. Our laser scattering apparatus was used to study the effect of silica matrix ions on barite nucleation inhibition [
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.
Static jar tests are widely known and used in the oil and gas industry for quantitative screening and determining the minimum effective dose (MED) for scale inhibitors. However, when dealing with very low saturated brines, challenges are faced in the laboratory to replicate the same scaling environment found in the oilfield facilities and often brines have to be stressed in order to induce scaling in the laboratory tests. This paper proposes an efficient approach for quick chemical selection and recommendation for low scaling environments.
The method proposed has been developed and successfully applied for the selection and recommendation of scale inhibitors in low to mild saturated brines. This technique involves the combination of the standard static jar test with Scanning Electron Microscopy (SEM) and UV-Visible Spectrophotometry (UV/VIS).
The two case studies presented here shows two fields with low to mild barium sulphate (BaSO4) and calcium carbonate (CaCO3) scaling issues. This novel approach of has been used to screen and identify the best scale inhibitor in terms of cost effective peformance. Post-experimental analyses such as the Scanning Electron Microscope/Energy Dispersive X-Ray Diffraction Spectrometry (SEM/EDXS) permitted the investigation and assessment of the type of scale formed, and the mechanisms of inhibiton for each scale inhibitor chemistry tested.
This combined approach removed any discrepancies obtained by visual observations and/or Inductively Coupled Plasma Optical Emission Spectroscopy (ICP-OES) efficiency measurements. Furthermore, the UV-Visible Spectrophotometry was used in conjunction to the static SEM/EDXS method, in order to reassess the MED for the scale inhibitor candidates using the kinetic turbidity test (KTT) method. Results obtained from the KTT method complimented those from the combined static with ICP and SEM imaging, providing a quick understanding of the scale formation kinetics and inhibition efficiency.
To summarise, results have shown that different techniques can be used as a fast screening process for the MED using different scale inhibitors at low scaling regimes. Therefore, the static SEM and KTT methods are recommended as a thorough screening process for determining the optimum MED and selection of the best fit for purpose scale inhibitor. This opposes the conventional dynamic scale loop (DSL) approach, which would require severe alterations to the brine chemistry in order to get a scaling blank within a minimum 2-hour-period.
Scale formation that can hinder continuous oil production is a serious problem in oilfield. Among all common scales, barite and calcite are two of the most important scales. Scale inhibitors have been widely added to prolong the induction time of scales. This study evaluates the methods and previous inhibition models to measure and predict scale formation in the presence of phosphonate and polymer inhibitors under common brine conditions. Turbidity measurement with laser light was used accurately and quickly to measure the induction time, and good reproducibility can be achieved between different sources of inhibitors. By conducting a set of independent inhibition experiments, previous models were evaluated and the demand for model improvement was carefully pointed out. On the basis of these evaluations, new ScaleSoftPizer (SSP) model was proposed by incorporating all available data under various simulated oilfield conditions (4-175 °C). The new SSP barite inhibition model was more internally consistent, and the new SSP calcite inhibition model expanded the applicable temperature ranges. The new SSP model was incorporated into SSP 2019. To prove the application of new SSP model, the predicted minimum inhibitor concentrations (MICs) were compared with lab observations and field data, which shows good consistence and improvements. This study improved the prediction of MIC over wide ranges of temperature and inhibitor types, which can significantly reduce the expenses and efforts to solve scale formation problems.
Iron sulfide scaling can pose a significant threat to flow assurance, especially in sour production systems that yields hydrogen sulfide (H2S). When compared to conventional carbonate and sulfate scales, iron sulfide is difficult to inhibit and various risks (liberation of H2S) are associated with chemical removal. Moreover, efficacy of chemical treatment is poor and often uneconomical; and there is currently no true nucleation inhibitor of iron sulfide identified.
A strictly anoxic static bottle test setup was developed and various traditional scale inhibitors, such as phosphonates, carboxylic acid polymers, as well as new chemistries were screened for iron sulfide nucleation and growth inhibition. Different concentrations of scaling ions (Fe+2 and S2-) were used to mimic the field to field variation in brine composition. The resulting aqueous phases as well as iron sulfide solid products were characterized using various analytical tools including ICP-OES, particle size analyser and Turbiscan.
As expected, conventional scale inhibitors did not show any inhibitory or dispersive effect towards Iron sulfide under tested laboratory conditions. However, a chemistry is identified which can prevent iron sulfide scale deposition at threshold quantities. Specifically, this novel chemistry showed partial iron sulfide nucleation inhibition at early stages and growth inhibition (as high as two orders of magnitude) later. This significant growth inhibition of iron sulfide resulted in excellent dispersion formation that prevents iron sulfide particle aggregation/deposition. Various studies were conducted to understand the chemical-iron sulfide particles interaction and mechanistic aspect of chemical-iron sulfide interaction is identified and discussed. Currently inhibitor packages are being developed for field trials and results will be the subject of future publications.
Efficient mitigation of iron sulfide scaling problem has huge industrial and economic importance in oil and gas production. Based on our current laboratory results, it is anticipated that this chemistry will provide a novel chemical treatment option for iron sulfide scaling control at threshold level whereas orders of magnitude more of conventional scale inhibitors may be required. In addition, this novel chemistry also showed promising outcomes on oil-water partitioning test by making finely dispersed iron sulfide particles water-wet thereby preventing the formation of iron sulfide-crude oil emulsion/pad.