Hydrochloric acid (HCl) is the acid of choice for acidizing operations in most carbonate formations and is the base acid commonly paired with others such as hydrofluoric (HF) in most sandstone applications. However, high dissolving power, high corrosion rate, lack of penetration, and sludging tendency coupled with high temperature can make HCl a poor choice. Alternatively, weaker and less corrosive chemicals such as organic acids can be used instead of HCl to avoid these issues. The objective of this paper is to provide an intensive review on recent advancements, technology, and problems associated with organic acids. The paper focuses on formic, acetic, citric, and lactic acids. This review includes various laboratory evaluation tests and field cases which outline the usage of organic acids for formation damage removal and dissolution. Rotating disk apparatus results were reviewed to determine the kinetics for acid dissolution of different minerals. Additional results were collected from solubility, corrosion, core-flooding, Inductively Coupled Plasma (ICP), X-Ray Diffraction (XRD), and Scanning Electron Microscope Diffraction (SEM) tests. Due to their retardation performance, organic acids have been used along with mineral acids or as a stand-alone solution for high-temperature applications. However, the main drawback of these acids is the solubility of reaction product salts. In terms of conducting dominant wormhole tests and low corrosion rating, organic acids with low concentrations show good results. Organic acids have also been utilized in other applications. For instance, formic acid is used as an intensifier to reduce the corrosion rate due to HCl in high-temperature operations. Acetic and lactic acids can be used to dissolve drilling mud filter cakes. Citric acid is commonly used as an iron sequestering agent. This paper shows organic acid advances, limitations, and applications in oil and gas operations, specifically, in acidizing jobs. The paper differentiates and closes the gap between various organic acid applications along with providing researchers an intensive guide for present and future research.

Organic acids are commonly used to replace hydrochloric acid (HCl) in high reservoir temperature applications, as they are less corrosive and weaker than HCl. However, organic acids have shown some problems due to acid reaction product solubility. One such organic acid, lactic acid, produces calcium lactate when it reacts with calcite, which has a low solubility in water. However, reaction product solubility can be improved by up to five times when gluconate ions coexist with lactate and calcium ions. The objective of this research is to evaluate lactic and gluconic acid mixtures in term of dissolving calcite, reaction product, corrosion, wettability and generating dominant wormhole. Lactic and gluconic acids were mixed together using deionized water and seawater to conduct calcite solubility tests. Corrosion tests, between 4 and 8 hours, were also run under reservoir conditions. Zeta potential measurements were performed to determine alterations in rock wettability. A formation response test (FRT) apparatus was used to run different coreflood tests using different combinations of injection rates and temperatures. These tests were accompanied with analytical results from ICP and IC to measure calcium, iron and sulfate ions in solution. The results showed that mixing lactic and gluconic acids at a 1:1 molar ratio provided the optimal results as no precipitation occurred at total acids strengths of 10 wt% and up to 27 wt%. Seawater usage caused calcium sulfate precipitation; therefore, three scale inhibitors were evaluated to determine mitigation rates. Acid calcite-dissolving results were satisfactory when limestone was exposed to a 1:1 and 2:1 molar ratio of crushed core-to-acid ratios as at least 50% of the crushed core was dissolved. However, the two-acid mixture showed a corrosion rate that was higher than the acceptable rates and a trace of iron lactate precipitation occurred at 200 and 300°F. Five gpt from a sulfur-based corrosion inhibitor was enough to mitigate the corrosion rate to allow for eight hours of testing. Wettability alteration was noticeable due to the spent acid interaction with limestone rock and was the highest when high salinity seawater was used. Yet, the addition of corrosion inhibitor showed a reduction in the magnitude of zeta potential change. Coreflood tests showed that the mixture penetrated the tested core with minimal acid pore volume without any face dissolution or salt precipitation on the core faces. This research presents a set of diverse experimental data to confirm lactic acid accompanied by gluconic acid can penetrate carbonate formation without any by-product precipitation. The two organic acids are less corrosive and less hazardous which can provide a safe operation environment and can decrease replacement and maintenance costs.

When used for running sand control screens, low-solids, oil-based completion fluids (LSOBCF) maintain reservoir wellbore stability and integrity while minimizing the potential risks of losses, screen plugging, completion damage, and productivity impairment. Until now, using LSOBCF as a screen running fluid (SRF) has been limited by fluid density. The design, qualification, and first deployment of an LSOBCF that incorporates a newly developed, high-density brine as the internal phase to extend the density limit is discussed. The following parameters were examined as part of the preliminary qualification: rheology performance, long-term stability, fluid loss (filter-cake repair capability), reservoir fluid and drill-in fluid (RDIF) compatibility tests, emulsion breaking test, production screen test (PST) on 275 µm screen, crystallization temperature [true crystallization temperature (TCT) and pressurized crystallization temperature (PCT)], and corrosion rate. The fluid was then tested for formation and completion damage performance, where the high-density, brine-based LSOBCF exhibited minimally damaging behavior in the core-flow tests. As a result of the positive observations made during these wide-ranging laboratory tests, this new high density-based brine was deemed as a good candidate in an LSOBCF for high-density SRF applications. Viable LSOBCF with densities up to 1.50 SG have been designed. This paper details the design and field application of a 1.45 SG LSOBCF. Calcium bromide (CaBr 2 ) brine is commonly used during the discontinuous phase for LSOBCF applications that require fluid densities up to 1.38 SG. For higher density requirements, LSOBCF use a cesium formate brine as a discontinuous phase. Using the new developed brine in the discontinuous phase provides viable LSOBCF up to 1.50 SG. The base brine has a good environmental rating, is pH neutral, and provides improved safety during low-temperature/high-pressure conditions. As a standalone fluid, the new brine can achieve densities up to 1.80 SG, with acceptable TCT and PCT values for North Sea applications without using zinc or formate-based brines. After laboratory qualification, the final fluid formulation was deployed on a dual lateral oil producer well with 9.5 in. horizontal reservoir section lengths of 2315 and 1696 m. After drilling the sections using an engineered low equivalent circulating density (ECD) oil-based RDIF (OB RDIF), each section was sequentially displaced to 1.45 SG LSOBCF. The lower completion, consisting of 5.5 in. screens equipped with autonomous inflow control devices (AICD) and swellable packers, was successfully run to bottom without significant issues. The field application demonstrated evident operational efficiency gains. The positive pre-deployment formation response test (FRT) results have been verified by well productivity data. The process to qualify the brine for first-use application in LSOBCF is described, and laboratory testing (including FRT), mixing and logistical considerations, field execution, and well productivity are discussed.

The bulk "apparent adsorption" behavior (Γ app, vs. C f ) of 2 polymeric scale inhibitors (SI), PPCA and PFC, onto carbonate mineral substrates has been studied for initial solution pH values of pH 2, 4 and 6. The 2 carbonate minerals used, calcite and dolomite, are much more chemically reactive than sandstone minerals (e.g. quartz, feldspars, clays etc.) which have already been studied extensively. In nearly all cases, precipitates formed at higher SI concentrations were due to the formation of sparingly soluble SI/Ca complexes. A systematic study has been carried out on the SI/Ca precipitates formed, by applying both ESEM/EDX and particle size analysis (PSA), and this identifies the morphology and the approximate composition of the precipitates. For PPCA, at all initial solution pH values, regions of pure adsorption (Γ) ([PPCA] <100ppm) and coupled adsorption/ precipitation (Γ/Π) are clearly observed for both calcite and dolomite. PFC at pH = 4 and 6 also showed very similar behavior with a region of pure adsorption (Γ) for [PFC] < 500ppm and a region of coupled adsorption/precipitation (Γ/Π) above this level. However, the PFC/calcite case at pH 2 showed only pure adsorption, while the PFC/dolomite case at pH 2 again showed coupled adsorption/ precipitation at higher PFC concentrations. For both SIs on both carbonate substrates, precipitation is the more dominant mechanism for SI retention than adsorption above a minimum concentration of ~100 – 500 ppm SI. The actual amount of precipitate formed varies from case to case, depending on the specific SI, substrate (calcite/dolomite) and initial pH (pH 2, 4 and 6). Although the qualitative behavior of both PPCA and PFC was similar on both carbonate substrates, the apparent adsorption of PPCA was higher on calcite than on dolomite; PFC apparent adsorption was higher on dolomite than on calcite. It is discussed in the paper how these observations are related to the reactivity of the different carbonate minerals, the resulting final pH (which affects the dissociation of the SI), Ca-SI binding and the solubility of the resulting complex.

The Auca field, located in the Amazonian region of Ecuador, started production in 1970, reaching a peak of 75,000 BOPD in March 2015. By the end of 2015, production declined to 65,000 BOPD due to water cut increase, reservoir pressure loss, and progressive formation damage. In January 2016, Petroamazonas EP (PAM) and Schlumberger (SLB) initiated the Shaya Project with the objective of increasing production and reserves through infill drilling, secondary recovery, and well interventions. The Auca field produces from the Hollín Formation and the Napo U and T sandstones. The latter two normally suffer from pressure depletion due to weak aquifer support, whereas the Hollín formation maintains reservoir pressure due a strong aquifer acting from the bottom. In general, formation damage in the Auca field is caused during drilling and pulling activities due to invasion of drilling or control fluids, but it also happens naturally in form of scale precipitation which has been physically proved, and possibly fines migration which remains a theory yet to be verified. Several workflows, procedures, and research on the nature of the damage have been put in place to resolve the production loss and decline issues associated with the varios potential causes. The selection of the most appropriate damage-removal technique depends on the reservoir and fluid properties, reservoir architecture, production behavior, water diagnosics, well intervention history, well geometry, artificial lift system, and, most importantly, the nature of the formation damage. From the reservoir and production engineering perspective, understanding formation damage and identifying its root cause is a key for designing the appropriate solution. After 18 months of intensive activity with drilling and workover operations, the production of the Auca field is close to 72,000 BOPD. If the operator had decided to stop activities, the production baseline would be at 35,000 BOPD. This means that, at present, the project has contributed a net incremental of 37,000 BOPD, of which approximately 30% corresponds to damage-removal jobs. This is a case study on one of the largest producing oilfields in the Oriente Basin that shows the typical productivity issues to deal with siliciclastic reservoirs and provides an example of how to select the most appropriate damage-removal techniques.

Exploration for unconventional reservoirs has begun in various countries in the Middle East. Widely recognized as the bastion of conventional crude oil and gas production, the area's exploration for natural resources –– in particular unconventional resources –– is in its infancy. The lack of fresh water may derail some of the exploration and production of unconventional resources in the Middle East. One of the solutions is to use the abundant availability of nearby sea water for fracturing treatments. This paper will discuss the applicability of sea water for fracturing fluids for without the need for separate treatment of the water. Rheological data with synthetic sea water as well as source sea water from Saudi Arabia, identification of any potential precipitation and remediation and compatibility with produced water and proppant pack conductivity data, of applicable fluids to show the effectiveness of the systems to the high temperatures of the reservoirs in the kingdom, 325°F will also be presented. The concept of using seawater as a base fluid is not new. Because of the problems associated with substituting seawater for freshwater in polymer-based fracturing fluids, many operators are apprehensive about using seawater for fracturing. There have been noted attempts to mix polymer-based fluids on the fly with seawater, but treatment results have varied widely. Seawater contains dissolved inorganic salts, adversely affecting hydration and viscosity development of polymer-based fluids. High content of calcium and magnesium in seawater can reduce viscosity. These salts also buffer and strongly influence pH control and may inhibit or deactivate certain gel breakers. To gel effectively, polymer fluids need a specific mixing environment with distinct pH windows. Borate crosslinking normally requires a high pH. Rheology and breaker profiles will be shown that provide the desired properties and regain conductivity to establish the non-damaging clean-up of a properly designed fluid. The technology presented uses chemical chelation of the problem ions in the sea water, resulting in the fracturing fluids with enhanced fluid and proppant pack properties, including thermal stability, retained fracture conductivity, pH buffering capacity, scale inhibition and fluid loss control. Further, the addition of the novel additives to the fluid does not interfere with the crosslink delay time and does not complicate the preparation of the fluid. The technology discussed eliminates the need for traditional water treatment and nano-filtration of sea water and associated disposal issues.

Fracture conductivity degradation results from damage mechanisms and fluid interactions that occur during and after hydraulic fracturing treatments. Rock softening and associated proppant embedment are among the damage mechanisms affecting this degradation. The aim of this research study is to understand the physico-chemical interactions between fracturing fluid and formation to investigate the associated geomechanical property changes taking place in the Niobrara shale, a calcium carbonate rich formation, during and after hydraulic fracturing treatments. Experimental tests were carried out on Niobrara core samples to investigate the effects of chemical interactions between the formation, fracturing fluid, and proppant along with static and dynamic geomechanical property changes. The samples were characterized using X-Ray Diffraction (XRD), X-Ray Fluorescence (XRF), and Field-Emission Scanning Electron Microscopy (FESEM). Two sets of experiments were conducted: fluid chemical interactions with crushed rock and proppant, and geomechanical property variations in intact core samples. In the first set of experiments the changes in the composition of the solution were monitored as a function of saturation time. In the second set, the variations in the dynamic and static mechanical properties were examined in intact core plugs before and after they were saturated. Best practices for hydraulic fracturing fluid selection are established by incorporating the impact of the fracturing fluid on geochemical composition and geomechanical property changes in the formation. This study provides an insight into how each selected fluid formulation yields unique interactions with the mineral composition of the formation. Distilled water shows to be more prone to dissolve elements affecting the strength of the rock, whereas 2% brine solutions, especially 2% KCl, dissolve elements that could be the source of scales, fines migration, other types of undesired precipitations, as well as elements related to organic matter in the reservoir rock. A comparison of the dynamic and static elastic moduli and fluid chemistry data obtained pre- and post- treatment indicate that there is a correlation between softening of the formation and the chemical interactions taking place in the rock. FE-SEM images further support this interpretation. Hydraulic fracture treatment effectiveness in tight reservoirs can be improved by integrating multidisciplinary data. This study provides detailed geomechanical and geochemical analyses capturing associated changes in the rock and the fluid composition when they interact with each other. It also introduces a correlation between mineralogy and the mechanical properties of the rock proposing a simple approach to improve the fluid selection in hydraulic fracturing operations.

Stimulating offshore sandstone formations with depleted reservoir pressure is a challenge. The conventional practices for sandstone acidizing are to pump pre- and post-flush hydrochloric acid to minimize precipitates from the main hydrofluoric acid reacting with the carbonates, and to flow back the well immediately after the acid is pumped. However, in offshore wells, limited deck space for chemical mixing equipment and depleted reservoir conditions necessitated a retarded single-stage HCl/HF acidizing approach with nitrogen. Because cores were not available, solubility testing was performed using cutting samples with normal HCl/HF acid and retarded single-stage HCl/HF acid. The retarded single-stage HCl/HF acid outperformed the conventional HCl/HF acid in these tests. Because of the challenge in treating long perforated intervals with various permeability zones and depleted reservoir conditions, the operator chose to pump retarded single-stage HCl/HF acid with nitrogen as a diverting and lifting agent. The retarded single-stage HCl/HF acid system eliminated the requirement of pre- and post-flush HCl acid stages, reducing the treatment complexity and overall treatment time. The successful single-stage HCl/HF acid treatment resulted in a 225% increase in oil production and a 416% decrease in water cut. The decreased drawdown around the wellbore helped improve the oil-water ratio and deliver a lower water cut. This paper summarizes the challenges of testing, designing and pumping the single-stage sandstone acid system in one well offshore Vietnam.

An effective chemical treatment program should reduce the rate of well failures while enhancing well productivity and minimizing cost. The unique challenges to achieving these goals include the variation in the downhole conditions, fluid composition, completion types and number of wells. The execution of chemical programs often relies on third party vendors with a vast resource base and proven technology. These traits, however, must be coupled with knowledge of the well history and proper oversight from operations, facilities, and production engineering groups. Managing and effectively utilizing collected data helps to move from "blanket type" chemical programs to a more targeted well-by-well approach. This work uncovers several opportunities for improvement in already established chemical programs. It is especially beneficial for the onshore fields which are challenged with hundreds or even thousands of wells. The systematic improvement strategy applied in this study began by assessing existing data for identification of scaling, corrosion, and organic deposition problems. This allowed the Local Chemical Management Team (LCMT) to reveal gaps in the information needed for a more comprehensive understanding of formation damage and flow assurance issues. Proper identification of controlling damage type per formation and area of the field enabled redesigning of well completions, testing of water compatibilities for fracture stimulation, and customization of acid treatments with improved acid placement and production uplift. Early attempts to collect fluid samples and integrate water, gas and solid analysis in the scale prediction modeling software revealed the critical nature of quality checks in sampling procedures, field tests, and lab reports. The lab audits and chemical program data management led to reorganization of the database structure and improvement in measuring and reporting of the results to the LCMT. The value of information gained by laboratory tests offered by the chemical provider was assessed in current field settings and communicated to engineering and operations personnel. A better understanding of organic deposits also supplemented wellbore and sand face clean outs. Inclusion of a flow assurance focus in an established corrosion and well failure prevention program increased well productivity and decreased operating cost per well. Improvements in the database structure included utilization of historical data for treatment optimization, integration of oil, water, and gas with quantitative solids analysis, and the establishment of key performance metrics and reporting procedures. Customization of remedial treatments per zone and geographic location, in addition to a review of well histories and completions complemented production optimization practices. Awareness of flow assurance issues and chemical management programs was provided to operations and engineering staff through a number of on-site training sessions.

Scale inhibitor (SI) squeeze treatments are applied extensively for controlling scale formation during oil production. The current research involves phosphonate/metal precipitate studies in the context of precipitation squeeze treatments. The main focus here is on the precipitation and solubility behaviour of the SI_Ca_Mg complexes of HEDP (di-phosphonate), DETPMP (penta-phosphonate) and OMTHP (hexa-phosphonate) phosphonate Sis; these phosphonate/mixed Ca/Mg divalent precipitates are denoted as SI_Ca n1 _Mg n2 , where n 1 and n 2 are the stoichiometric ratios of Ca and Mg to SI. Precipitation experiments with SI_Ca n1 _Mg n2 species were carried out over the temperature range, 20–95°C, while varying the Mg/Ca molar ratio over a wide range from all Ca to all Mg. These precipitates were formed in MgCl 2 ·6H 2 O/CaCl 2 ·6H 2 O brine solutions with appropriate molar ratios of metals, then separated from supernatant by filtration. Subsequently, the solubility of the collected precipitate was found in a solution of the same Mg/Ca molar composition from which it was prepared. In this type of experiment, the solubility of the SI_Ca n1 _Mg n2 precipitate without any re-speciation is determined. In addition, another type of solubility experiment was carried out for a precipitate formed in a brine with one fixed Mg/Ca ratio and this was subsequently placed into a solution with different Mg/Ca compositions (from all Ca to all Mg). In these experiments, re-speciation of the precipitate may occur. We have been able to establish the solubility (Cs) of the precipitates of 3 SIs (HEDP, OMTHP and DETPMP) as a function of both temperature and Mg/Ca molar ratio. It has been shown, that the solubility ( Cs ) of precipitate is in equilibrium with Mg and Ca concentrations in solution and any change of these parameters leads to solubility (C s ) variation. All phosphonate/metal precipitates become less soluble with increasing temperature and much more soluble as the proportion of Mg increases. We have found, that any change in Mg/Ca ratio of brine does lead to a re-distribution of Ca, Mg and SI concentrations in a given precipitate and bulk solution, and hence leads to some variation in the precipitate solubility. In addition, the inhibition efficiency (IE) of precipitated and then re-dissolved HEDP, OMTHP and DETPMP SIs was tested and was compared with the IE of industrial stock products. We show that, unlike polymeric SI precipitates, the inhibition activity of phosphonate SIs does not depend very significantly on the precipitation process and the IE of precipitated and re-dissolved SI_Ca and SI_Ca_Mg complex is very close to that of the industrial stock solutions. These results can be used directly for modelling phosphonates precipitation squeeze treatments and the significance of these results for field applications is explained.

Started in the late 1800s in the US, water being relatively inexpensive and readily available in large volumes and as being very effective at significantly increasing oil recovery, waterflooding has been the most common secondary recovery method applied throughout the world, contributing to pressure maintenance in the reservoir and displacing the oil phase. While there are several parameters that influence the performance of a waterflood, water quality is one of the important factors as it may cause scaling in the injection wells as well as some formation damage through chemical phenomena such as cation exchange in the reservoir resulting in decreased the recoveries. As waterfloods continue over decades, prevention of scale formation becomes a more significant factor that needs to be properly treated. The precipitation of inorganic scale is a major issue in injecting brines with a high concentration of divalent ions. The scaling tendency of water is highly correlated with the hardness of the injection water. Following corrosion, insoluble iron precipitates can cause damage in injection wells where precipitates can lead to severe reductions in well injectivity. Water needs to be treated in a proper way if the water contains high concentrations of calcium, magnesium or iron. In most waterflood applications, seawater needs to be used and this phenomenon is also an issue when injecting seawater into formations that contains brines with high salinity. In this study, a comprehensive analysis of this common problem is provided by investigating the significance of parameters affecting the severity of the scale through utilizing a seawater scale buildup model to be simulated using a commercial simulator along with an in-depth review of previous studies.

Use of adsorption asphaltene inhibitors in mature oil fields in eastern Venezuela has reduced operating costs and deferred production. As is common in mature fields, some fields in the northern district of Monagas state, Venezuela, such as Furrial, Musipan, and Boquerón fields, have had increasing problems of asphaltene deposition for a number of years. Asphaltenes present in a crude oil under normal reservoir conditions will start to flocculate and precipitate in the critical near-wellbore matrix as the reservoir pressure drops, which greatly reduces the productivity of the reservoir. Conventional asphaltene treatment is a two-step process that involves removal of the deposits by pumping solvents and asphaltene dispersants into the formation using coiled tubing. The frequency of the treatments increases as the reservoir pressure drops, and, in some fields, it is common for wells to be treated every 30 days or less, resulting in deferred production and increased costs. Conventional asphaltene inhibitors precipitate in the pore spaces in the matrix of a formation and then slowly dissolve in the produced crude, preventing the flocculation of the asphaltene present in the crude. In contrast, the new generation of asphaltene inhibitors adsorb onto the surfaces of the pore spaces in sandstones or onto the fracture faces in carbonates, providing protection from asphaltene deposition in the formation, tubing, and flowlines over an extended period of time. These adsorption asphaltene inhibitors were first used in Venezuela to treat wells in the Boquerón field that historically had been treated every 60 days to maintain production. Wells treated with adsorption asphaltene inhibitors maintained their production for over 180 days, greatly reducing both operating costs and deferred production. Results from laboratory tests on the adsorption inhibitors, field operations experience, and lessons from treatment evaluations were incorporated into a workflow that enables optimizing asphaltene inhibition for new fields. The use of the adsorption inhibitors has reduced the logistics and time required to place these inhibitors in the formation and has greatly decreased the frequency of the treatments needed to maintain the overall production. The initial success of these treatments has led to additional asphaltene inhibition campaigns in other fields.

Asphaltene precipitation is a common phenomenon in mature reservoirs that seriously impairs oil production. In high-temperature (HT) fractured carbonate reservoirs, the situation becomes critical when asphaltene precipitates at reservoir conditions, blocking the fractured production channels and initiating a cycle of production decline in which additional pressure drop increases the precipitation of the asphaltene fraction. Therefore, it is essential to make an early diagnosis of the problem and deliver an optimal solution to avoid further production decrease. A proper diagnosis regarding the point of precipitation along the production path requires a complete analysis of the well's production behavior and reservoir characteristics. To avoid asphaltene precipitation inside the rock matrix, different methods can be applied: maintaining reservoir pressure above the asphaltene onset pressure, avoiding coproduction of incompatible reservoir fluids, adjusting artificial lift conditions, or injecting solvents with inhibitors or dispersants. In two mature fields located in southern Mexico that have been producing since 1995, an operator needed to determine where the asphaltene precipitation was occurring. An integrated diagnosis workflow that included the creation and analysis of the asphaltene phase envelope plus an asphaltene-onset screening test using a solids-detection system (SDS) was instrumented. After coupling screening results with a pressure-temperature flowing survey, it was identified that asphaltene precipitation occurred inside the reservoir when the bottom-hole flowing pressure dropped below a critical level. To address the organic deposits and unstable pressure behavior successfully, asphaltene precipitation characterization was essential. In some cases, a decrease in oil production after executing unsuccessful matrix cleanup treatments with solvents results from a misdiagnosis of organic precipitation or a lack of knowledge about flocculation and precipitation causes. To avoid this problem, a new methodology for the inhibition treatment design was added to the diagnosis workflow; this methodology includes a new adsorption-type asphaltene inhibitor as part of the matrix cleanup treatment. As a result of this diagnostic-solution workflow, an optimum bullheaded inhibition treatment was determined and applied to the candidate wells. In all study cases, the time lapse between inhibition treatments was extended by 60 days on average, resulting in steadier oil flowrates plus significant reduction in well intervention and deferred production costs. Additionally, the post-treatment results showed that in 50% of the documented interventions, the inhibitor treatment improved overall production performance by at least 10%. The systematic engineering workflow presented in this paper includes the diagnostic procedure, data from laboratory testing, chemical selection, and treatment application. Subsequent treatment results enhanced the field operator's understanding of asphaltene precipitation in the formation matrix and provided more insight into maximizing oil production with specialized technology solutions using a novel adsorption-type asphaltene inhibitor.

Scale Inhibitor (SI) squeeze treatments are commonly used to inhibit mineral scaling in reservoirs, hence preventing formation damage and other production problems. Conventional squeeze treatments comprise of five stages, namely: pre-flush, main treatment, post-flush, shut-in and back-production stages. In the pre-flush stage, a mutual solvent (MS) is often applied to the formation either neat or in a blend of water and/or other additives. This practice is believed to offer numerous benefits including: the prevention of emulsion formation, water-blocking avoidance and enhancements to SI adsorption through oil and water displacement. In applying a MS, any additional solid deposits formed due to this pre-flush stage are generally undesirable. The nature of these possible additional deposits and their potential to cause formation damage have not been studied systematically to date. This paper aims to characterise the predominantly inorganic scales formed in mixtures of oil, brine and a mutual solvent. This characterisation is very useful in developing an understanding of the possible risks associated with mutual solvent applications and it will ultimately enable us to the design of better optimised scale inhibitor squeeze treatments including MS pre-flush stages. For a range of mutual solvents, qualitative "pseudo" ternary phase diagrams were produced at room temperature and pressure; it is denoted "pseudo" ternary since the "components" are the MS, a mineral oil and a brine (all of which are actually multicomponent in nature). Two brine chemistries were investigated including a sulphate-free formation brine and normal seawater. These investigations aided the definition of inorganic precipitation regions on the phase diagram as a function of brine chemistry. For the two brine chemistries investigated, the precipitates were collected and analysed using two methods. The first method used ESEM-XRD analysis to produce an elemental composition of the precipitates. This enabled the determination of the abundant elements in the precipitates and the compounds forming these. In the second method, the precipitates were redissolved in de-ionised water, and ICP-OES analysis was performed to determine the relative elemental ratios. Using these two approaches, a decisive characterisation of the predominant precipitates and their proportions can be made. Significant mutual solvent driven precipitation was found to occur at almost all mutual solvent concentrations in seawater, whereas mineral precipitation occurred only at near-neat mutual solvent concentrations in formation brine. This indicates that the sulphate ion may be important. Indeed, in seawater, the precipitates were found to be predominately Na 2 SO 4 and CaSO 4 in approximately a 2:1 mix, respectively, with traces of other SO 4 2- and Cl – precipitates. In formation brine, the precipitates comprised almost entirely of NaCl with small traces of other Cl – salts. These findings provide practical means for preventing mutual solvent driven precipitation that can be tailored to specific squeeze treatment designs. In this regard, key considerations would be the use of sulphate-free brines in preparing the pre-flush, and the avoidance of mutual solvent and brine mixtures at near-neat mutual solvent concentrations.

Using hydrofluoric (HF) acid for the removal of clays and silica minerals impairing permeability in sandstone formations requires fluids free of sodium or potassium ions. High temperatures (> 300°F) further limit HF acid use and its effectiveness because of potentially damaging effects to the formation and its corrosivity. This paper discusses laboratory testing of an aminopolycarboxylic acid (APCA) fluid containing 1 to 1.5% HF acid and highlights its advantages and differentiating characteristics with respect to previous HF acid fluids. Core flow testing at 360°F was conducted on outcrops of two types of sandstone representing a heterogeneous (65% quartz and illite/kaolinite with feldspars) and a clean (95% quartz) type of mineralogy. The APCA fluid containing HF acid, which incorporates a modulating agent for the HF acid-secondary reaction on aluminosilicate minerals, was compared to the pure APCA (pH 2) fluid and formic acid. Effluent analysis of the spent fluid was completed by inductively coupled plasma (ICP) optical emission spectroscopy (OES). Corrosion inhibition testing was completed for coiled tubing (CT) and carbon steel (NT-95) up to 360°F, employing various classes of inhibitors. Using an APCA chelating agent in sandstone HF acidizing expands the temperature range of application and the type of minerals that can be exposed to such fluid. High-temperature HF acidizing is also delimited by the type of steel tubing that can be exposed to such fluid, placing significant demands on corrosion control. Laboratory results obtained in this investigation demonstrate that corrosion can be well managed for a fluid having a pH of 2.5 and HF acid concentrations of 1 to 2% from 250 to 275°F and at 300°F with a pH of 4. Testing results show that the APCA/HF fluid, having a pH of 2.5, can effectively be used to treat heterogeneous sandstone of moderate carbonate content at 360°F and is also compatible with a clean sandstone. The APCA/HF fluid stabilizes the most problematic ions in the spent fluid—Al 3+ , Fe 2+ / 3+ , Ca 2+ , and alumino-fluorides—without the need for acid preflushes and without maintaining highly acidic conditions. Comparison to formic acid and HF acid-free APCA fluid is presented. Using aminopolycarboxylic acid-type chelants is restricted by the materials commercially available, all of which contain sodium, with one exception, which has ammonium. Hence, HF acidizing has been restricted to ammonium-containing fluids. A differentiating characteristic of the fluid reported here is its ability to sustain Na + concentrations exceeding 1 M and K + concentrations in excess of 0.5 M. Furthermore, it is suitable for the treatment of carbonate-laden mineralogy formations up to 360°F.

Asphaltene precipitation during miscible CO 2 flooding can adversely affect the productivity of reservoirs during the course of oil recovery. The prevention of formation damage ensuing from asphaltene deposition in porous rocks often requires the use of chemical additives such as solvents or inhibitors. Effective additives are able to disperse asphaltene aggregates by curbing their growth in the bulk phase. While numerous dispersion studies have been performed in alkane solvents, very limited work currently exists in supercritical (sc) carbon dioxide. The main challenge stems from the inherent insolubility of a large number of additives in sc-CO 2 . The objective of this study is to investigate the molecular interactions between asphaltenes and two environmentally friendly additives in sc-CO 2 at 308 K and 300 bar using molecular dynamics (MD) simulations. The additives consist of a terpene solvent (d-limonene) and a common viscosifier (polyvinyl acetate or PVAc). Two similar asphaltene structures (with and without hydroxyl group) were designed in order to understand the role of hydrogen bonding in their aggregation behavior. The results indicate that d-limonene can only disperse non-hydrogen bonding asphaltenes when used in sufficient amounts (i.e., 30 wt%). The interactions between hydrogen bonding asphaltenes and PVAc polymer (5 wt%) significantly reduced their aggregation but lowered the solubility of the polymer in sc-CO 2 . Adding limonene to this mixture could remediate the phase change and maintain asphaltenes and PVAc completely dispersed in the system.

The Viking formation in southern Saskatchewan Canada represents an active area where steep production declines in the first year of production are common and are often attributed to wellbore or near-wellbore precipitation of paraffin. Excessive decline rates within the first year on production have been observed. A producer was experiencing paraffin deposition in the wellbore and suspected it to be the reason for production declines. Conventional treatments targeted at wellbore deposition were carried out with little effect on production rates. In an effort to improve production rates horizontal treatments were attempted. These treatments resulted in brief increases in production (up to 6 weeks). Horizontal treatment success led to investigation into other treatment options. Precipitation in the formation may contribute to reduced conductivity and, therefore, lower oil production rates. Solid paraffin inhibitors delivered via hydraulic fracturing offered the best potential for success in new wells. The chemical additive treatment was designed through product selection testing using cold finger deposition tests, compatibility testing with the hydraulic fracturing fluid system, and proppant crush prediction models. A baseline of the untreated oil characteristics was determined using offset wells. Pour point, carbon number distribution and wax percentage were analyzed in offset untreated wells and each treated well. Production trends were used to track the performance of the treatments. The solid inhibitor application effectively prevented conductivity restrictions due to paraffin precipitation issues in the proppant pack. Placement of solid paraffin inhibitors into the Viking formation with the proppant during hydraulic fracturing increased cumulative production by approximately forty percent in the first 350 days on production and reduced decline rates. Comparing 150 untreated wells with the 90 wells treated with the solid paraffin inhibitor in 2012 has increased revenue by about 15.8 million USD over the 350-day period. Wells drilled in the same area, with similar frac treatments, depths, horizontal lengths and stages were compared.

This paper presents the findings of a study into the impact of reservoir flow behaviour on both the scaling risk at production wells, and the options for managing this scaling risk, for a deepwater sandstone reservoir in the Gulf of Mexico. One significant feature in this field is that flow takes place through isolated formation layers, and choices made regarding the seawater injection wells have a great impact, not only on the BaSO 4 scaling tendency, but also on the placement of scale inhibitor squeeze treatments in the producers. In addition to seawater injection, oil production is supported by the aquifer. The first stage of this study involved identifying the split between connate, aquifer and sea water in the produced brine. This provided data that could be used to calculate the evolution of the scaling risk over the lifecycle of each well. The formation brines contain barium and the injection water is full sulphate seawater, and the relative proportion of each brine, the water production rate, and pressure and temperature conditions all determine the scaling risk. The evaluation of the extent of reactions between the injection water (sulphate) and formation water (barium) from injection to production well can result in a significant reduction in the available barium within the produced water, and hence the scale risk and scale inhibitor concentration required to prevent scale deposition. In this study, as the injection wells were completed with inflow control devices (ICD's) it gave the opportunity to manage the injection split via these ICD's, not only to improve sweep efficiency, but also to balance reservoir pressures and make squeeze treatments more efficient. The study will present the squeeze treatment volumes and estimated treatment lifetimes possible for two scenarios for the water injection application to this deepwater field. The implications of this type of study will be highlighted in terms of the options that this data allows an operator to consider prior to commissioning water injection in these challenging environments.

The pressing water concerns of tomorrow demand that we target our time and technology in order to improve the fluid mixtures applied in fracturing operations. This challenge is intensified by the concomitant need to make use of produced water. Compelled toward this alternative as we continue to extract our remaining resources from the ground, we must account for the fact that the water we use will invariably decrease the strength of the composite fluids. Therefore, new chemicals are required to ensure stable results when testing these fluids. Fresh Water scarcity across much of the Permian Basin is particularly critical and necessitates the pumping of produced water, thereby conserving dwindling reserves. The major problem with this approach is the need to balance the fluid recipe with chemical additives. Produced water is highly ionized and as such becomes less stable at heated temperatures, giving a smaller window to adjust chemicals for a precise formula. Hence, an innovative chemical solution is indispensable. A scale inhibitor was found to prevent scale deposition by sequestering the cationic scale-forming ions, and distorting the crystalline lattice structure. What is more, this product exhibits good thermal stability and is also very effective ion stabilizations. Accordingly the novel scale inhibitor was implemented and successfully pumped for more than 200 stages in West Texas.

Oil-field scales result from changes in the physicochemical properties (pH, temperature, pressure etc.) of the produced fluids and/or due to the chemical incompatibility between waters having different compositions (e.g., formation brine and injection brine). Nevertheless, the comprehensive modeling and prediction of such phenomena remains a challenge, due to the complexity of the precipitation kinetics and chemical reaction processes that occur in the reservoir. Hence, it is the case that often reactions in the reservoir are not considered on evaluation of the scaling tendency, probably because they are difficult to measure and also, to model the calculations considerable effort and expertise is required. Since no comprehensive geochemical-based modeling has been applied in this research area, in this work, a previously developed robust, accurate, and flexible integrated tool, UTCHEM-IPhreeqc, is used to model the comprehensive geochemistry to predict scales problem for field scale applications. IPhreeqc, the United States Geological Survey geochemical tool, is able to simulate both homogeneous and heterogeneous (mineral dissolution/precipitation), irreversible, and ion-exchange reactions under non-isothermal, nonisobaric and both local-equilibrium and kinetic conditions. Through coupling of IPhreeqc with UTCHEM, The University of Texas at Austin research chemical flooding reservoir simulator, the entire geochemical capabilities of IPhreeqc can be used in a multi-dimensional and multiphase reservoir simulator for comprehensive reactive-transport modelings. In this paper, the importance of ion activities, temperature, and pressure in the reactive-transport modeling is emphasized by performing several sensitivity analyses. Oilfield scale is quantified by including the effect of dissolution or precipitation of all possible minerals (either initially present or subsequently precipitated by injecting an incompatible water) on the reservoir petrophysical properties (e.g., porosity). Three common permeability-porosity approaches (Modified Fair-Hatch, Kozeny-Carman, and Verma-Pruess models) are then implemented in the UTCHEM-IPhreeqc simulation tool to model the effect of scalings on the reservoir permeability. To show how well this integrated tool can be applied for field scale applications, a synthetic five-spot pattern is presented using several water compositions.