Machine Learning to Predict Scale Inhibitor Squeeze Treatments Lifetime

Effect of surfactant composition on reservoir wettability and scale inhibitor squeeze lifetime in oil wet carbonate reservoir

Scale inhibitor squeeze (SISQ) treatment is an established method for offshore fields which allows an extended effectiveness of the scale inhibitors in preventing scale deposition over time. Some of the main issues in SISQ campaign is the short squeeze lifetime being less than 1 year which may be contributed by operational and well integrity issues as well as ineffective design of the pre-flush system. This study proposed graphene nanoplatelets as pre-flush system to extend the lifetime of a conventional scale inhibitor squeeze treatment. This carbon-based nanomaterial known for its high specific surface area provided an excellent pre-coating on the rock matrix, allowing an enhanced adsorption of the phosphonate-based scale inhibitor. Special attention was given to the study on stability of the graphene nanoplatelets (GNP) in high divalent injection water and its functionalization with biopolymer to provide good dispersibility in the seawater at high temperature condition. This paper focuses on the compatibility evaluations of GNP in seawater, its dispersion and thermal stability assessment up to 96oC temperature, followed by an innovative static adsorption experiment using Berea crushed cores which served to establish the improvement in scale inhibitor adsorption at different GNP concentrations. For in-depth performance evaluations in downhole porous media, injectivity and adsorption-desorption scale squeeze treatment coreflooding experiments using Berea and reservoir native cores at high temperature conditions were then tmperformed. Finally, prediction on the field squeeze lifetime were simulated using Place-iT™ software. Results shown that the scale inhibitor's adsorption increased by more than 100% when 200 ppm of modified GNP was used as pre-flush compared to conventional pre-flush system. Good injectivity profiles, showing Residual Resistance Factor (RRF) of less than 3, coupled with slower desorption rate of scale inhibitor were observed from the coreflooding results. The simulated scale squeeze lifetime improved up to additional 14 months compared to baseline. Graphene nanoplatelets have demonstrated its versatility as nanocoating agent in enhancing scale inhibitor squeeze lifetime, extending its application as downhole high temperature production enhancement chemical.

Scale inhibitor squeeze treatment is often used to control mineral scales in the oilfield. However, the performance of scale inhibitor squeeze treatment is sometimes not satisfactory due to low inhibitor retention in the formation and a short squeeze life. It has been previously found that the addition of transition metal ions increased the retention of phosphonate and carboxylate polymeric inhibitor in carbonate formation. In this study, laboratory squeeze experiments were conducted to evaluate squeeze treatment by the addition of metal ions (zinc) in Berea sandstone and oil field core materials. Several scale inhibitors including phosphonate, phosphinopolycarboxylic acid (PPCA), and phosphonated carboxylate polymer were investigated, and these scale inhibitors were mixed with metal ions in the inhibitor pill for squeeze application. Experimental results demonstrated that zinc ions in the inhibitor pills improved retention of scale inhibitors and increased squeeze life significantly. It is proposed that the metal-inhibitor precipitate or complex formed, and the formation of the precipitate/complex enhances the adsorption of scale inhibitor in the mineral matrix. It was also found that chemical composition of the mineral may have an impact on the performance of squeeze treatment, and high concentration of iron may limit the effectiveness of this treatment. The demonstration of metal ions to improve scale inhibitor squeeze will have significant implications on scale control in the oilfield.

Effective chemical deployment is an important factor in the efficient management of a producing field. Ideally, chemical addition should be as far upstream as possible in order to allow effective control of processes such as scale formation and corrosion. One approach to effecting control early in the production is through so-called squeeze treatments, during which inhibitor chemicals are squeezed under pressure into the near well-bore region of a producing well. Upon lifting the well, the inhibitor will be returned with the produced fluids. Clearly, the effectiveness of oilfield chemical squeeze treatments relies on the ability to control the rate of inhibitor return in the produced fluids. Moreover, since the chemical is immobilized in the near well-bore region, the immobilisation process must itself be controlled in order to govern the subsequent rate of chemical release. Off-shore, the scale inhibitor is normally squeezed as an aqueous solution in sea water, the latter selected because of its obvious availability and also to reduce formation damage which may occur with lower ionic strength solutions. However, the effectiveness of this approach is not totally satisfactory for all reservoirs. For example, during scale inhibitor squeeze treatments on the Magnus field, problems with post squeeze oil productivity have been identified. These have been attributed to changes in the near well-bore relative permeability arising from the influence of the injected fluids. The squeeze treatments, moreover, often have short return lifetimes. Both of these effects can arise as a result of injecting purely aqueous solutions into the near well-bore region. First, if injected water enters an oil bearing zone, the water can become trapped reducing permeability to oil. Secondly, the water-wet nature of the sandstone reservoir means that the penetration depth of the scale inhibitor solution is low (in addition, placement of the inhibitor is retarded by adsorption of the chemical too close to the well-bore). A range of emulsion-based packages containing oilfield scale inhibitor squeeze chemicals have been developed. These have been evaluated as deployment systems designed to both overcome the problems described above and to reduce posttreatment well clean up times. It is envisaged that such an approach will have a significant impact on well productivity.

A strategy combining fracturing and downhole scale inhibitor squeeze treatments was employed in an extremely tight high-temperature gas reservoir (200°C) with calcite and sulfate scaling problems. Challenges included developing a scale inhibitor that is thermally stable at this high temperature, fully compatible with the fracture fluid used, extremely beneficial with a low minimum effective concentration, with good adsorption/desorption properties for a long squeeze treatment life. Literature survey verifies that few reports are published discussing application of a combined fracture and downhole scale inhibitor squeeze treatment under such high-temperature reservoir conditions. Multiple laboratory tests were performed to qualify the scale inhibitor, including inhibitor dynamic tube blocking, static beaker, and fracture fluid property testing. Standard inhibition tests were adapted to confirm tests were designed to confirm that the scale inhibitor was thermally stable under application conditions (i.e., the scale inhibitor was blended with the fracture fluid (including breaker) at given concentrations and aged together at 200°C for a certain period). The aged scale inhibitor sample was then tested for its performance against scale and results compared to the unaged inhibitor sample. Further tests were designed for fracture fluid rheology and breaking time with the blended scale inhibitor to help ensure the scale inhibitor was fully compatible with the fracturing fluid and would not interfere with its properties. Laboratory test results demonstrated that the scale inhibitor is fully compatible with the fracturing fluid and formation brine. An extremely low minimum effective concentration of the scale inhibitor was determined to be 5 ppm with the aged and unaged scale inhibitor samples. With the addition of the scale inhibitor, the breaking time and rheology property of the fracture gel met all application requirements. The chemistry of the amine-containing polymer inhibitor and advantages of using this chemistry as a downhole squeeze product are discussed. Successful field treatment with the combined scale inhibitor and fracture fluid was conducted. A new scale inhibitor chemistry was developed for a high-temperature reservoir for combined fracture and downhole inhibitor squeeze treatments.

This paper presents results of a reservoir and near wellbore modelling study to assist with the evaluation of inorganic scale risk management for a cold sandstone reservoir in the Norwegian sector of the North Sea. Reservoir temperature is in the range 32-48°C and poses a challenge to manage the scale risk. The field is heavily supported by aquifer water, and the development includes five production wells and seven seawater injection wells. The small number of high-cost, highly productive subsea multilateral wells with long horizontal sections, some with sliding sleeves to enhanced flow management, coupled with a high barium sulphate scaling tendency (up to 350ppm barium concentration in the formation water) requires effective scale management. This paper addresses questions of timing and nature of seawater breakthrough, when scale inhibitor squeeze treatments will be required, what is the impact of any reservoir reactions between the formation water and injected seawater on the scale risk at the production wells, what squeeze placement profiles look like under a range of squeeze treatment scenarios (various injection rates and sleeve position options). The treatment of multilateral wells by bullhead scale squeeze treatments is not a subject extensively covered in the literature, so the focus of this paper is to understand the impact on squeeze treatment life of bullhead deployment as a function of pump rate with both laterals open and the impact on treatment lifetime and treatment cost of selective placement into each lateral by treating one lateral at a time via activation of the sliding sleeve mechanism. The paper draws on a wide range of technical inputs to make scale management decisions including: thermodynamic modelling techniques, reservoir simulation of fluid mixing and reaction, laboratory-generated coreflood data to assess chemical selection for scale inhibitor squeeze, and squeeze treatment design drawing on all the information outlined above. Sharing the scale management technical challenges associated with such low temperatures and treating multilateral wells provides an example of the factors that should be taken into account during project design in similar fields under development in Northern Norway, offshore West Africa and offshore Brazil.

Scale inhibitor squeeze treatment is a widely used to prevent inorganic scale deposition in oil and gas production operations. Squeeze treatments consist of three steps: firstly, a bullheading of a scale inhibitor (SI) solution in a producer well. Secondly, an overflush stage pushes the SI deeper into the formation, and the well is subsequently shut-in for some time to allow the inhibitor to further retain into the formation. Third and finally, the well is put back in production, and the SI is slowly released in the production brine. The treatment will protect the well if the concentration in the produced brine is above a certain concentration, known as MIC (Minimum Inhibitor Concentration), normally a few ppm. The retention level is crucial in determining the squeeze treatment lifetime, particularly at low concentrations. It is generally accepted that the retention is governed by adsorption and precipitation mechanisms, which will depend on temperature, pH, and divalent ions concentration such as Ca and Mg. Recent experiments concluded that adsorption is more dominant than precipitation at low concentrations. Traditionally, adsorption/precipitation experiments have been performed at the macroscale using bottle test, analyzing the supernatant after filtering through inductively coupled plasma (ICP) spectroscopy, and applying scanning electron microscopy (SEM) imaging to analyze the SI retention on particulates. Although these techniques provide very valuable information, they are not capable of detecting surface deposits occurring when the SI retention is governed by an adsorption and adsorption /precipitation regime. High-resolution X-ray CT scanning is used in an in-house built mini coreflood system, which consists of a plug flow reactor filled with sandstone (0.25-0.5mm grain size, internal diameter of 4 mm). Coverage and volume deposited were detected through advanced imaging processing. The results show the surface deposit morphology, differentiating between regimes of pure adsorption or adsorption/precipitation. In addition, the retention level and release rate were estimated. This study results will lead to more effective scale inhibitor squeeze treatments.

Substantial buildup of CaSO4 and CaCO3 scales downhole contributed to a loss of 10,000 BOPD and the shut-in of 12 of the 70 wells in a Middle East field. The mineral encrustation occurred on electrical submersible pumps (ESPs), motors, and throughout the entire downstream production systems. The root cause was identified to result from water injection of sulfate-containing seawater into calcium-rich formation waters of Burgan and Mauddud reservoirs. This paper presents a case history from scale prediction and laboratory evaluations to the squeeze intervention to demonstrate how an effective scale treatment strategy was set up and implemented. To mitigate the risk of scale deposition during production, a scale inhibitor squeeze treatment was designed and implemented in the field. The design process started with a comprehensive field survey conducted by a field-experienced technologist. Scaling risks were assessed using water chemistries not only from Upper and Lower Burgan and Mauddud reservoirs, but also under all mixing scenarios with seawater. The systematic performance, fluid compatibility, and stability testing were conducted to formulate a cost-effective, custom scale inhibitor that considered the water chemistry and conditions of the specific horizontal well. A collaborative effort between the chemical supplier and coiled-tubing team engineered an effective application procedure to minimize the loss of squeeze fluid due to refilling in the annulus and to deliver the scale inhibitor to targeted zones. This application technique maximized the effectiveness and lifetime of the squeeze treatment. The approach to squeeze treatment design combines extensive field experience and application engineering with custom, cost-effective chemistry to meet well-defined key performance indicators (KPIs). In this case, the product candidate demonstrated a superior minimum effective concentration (MEC) of 5 ppm, as determined by dynamic loop tests and static bottle tests, as well as a full range of brine compatibility at any given mixing condition in the reservoirs. Once the intervention was executed, continuous monitoring of the squeeze application demonstrated that the inhibitor residual concentration in the produced brine remained above MEC for ten months, effectively inhibiting scale during that period. A 55% increase in the treatment lifetime was achieved relative to the target of 180 days while recovering the oil production rate of the well, resulting in an increase of 1,000 BOPD. A revisit to the field confirmed that the scale treatment was effective and found no sign of scale deposition in the previous well locations. Modelling simulation was performed before the intervention and matched the field operation results. Future treatment design was also optimized. The squeeze treatment was carried out for the first time in the field with significant cost savings for the operator in comparison to the previous frequent chemical interventions for the wells involved.

Since the middle 1980s, seawater breakthrough has been observed for a number of wells in a major offshore Field operated by Statoil. This Field has also several tie-ins. Both sulphate and carbonate scale deposition has been identified in the near well bore area and tubing. Inhibitor squeeze treatments were regularly carried out to prevent wells from damages due to scale precipitation. The conventional phosphonate scale inhibitor (DETA-phosphonate) was often used. Some of the sandstone formations in the oil field are relatively "clean" with very little amount of clay materials i.e. Etive and Tarbert formation. As a result, a relatively short inhibitor squeeze life was seen in these formations after the squeeze treatments with a phosphonate scale inhibitor. Other reservoirs had acceptable squeeze life, but due to environmental requirements a wide set of inhibitors was studied. In order to reduce the well intervention frequency and extend an inhibitor squeeze life, a method involving a polymer interaction between a polymer scale inhibitor and polymer additive has been developed. In addition to the enhanced adsorption; attributed by the surface charge modification by the adsorption of the positively charged polymer additive on the sandstone surface, the interactions between polymer inhibitor and additive further increase the inhibitor retention in the formation. This polymer interaction approach is different from a conventional precipitation squeeze where calcium chloride was used. Also, unlike the conventional precipitation squeeze, the polymer additive can be pre-injected and rapidly adsorbed onto a rock surface. The subsequently injected inhibitor will react with the additive on the rock surfaces, resulting in a precipitation on a rock surface. This avoids the bulk precipitations where a permeability reduction was often caused by a conventional precipitation squeeze. During the production, the precipitated polymer inhibitor was released through a hydrolysis process. This paper presents a detailed method and field results based on the treatments using the polymer inhibitor and additive package in the oil field. The application of polymer interaction package significantly improved the inhibitor squeeze life. Satisfactory results have been achieved from the field trials. The unique polymer reaction package satisfies the stringent Norwegian environmental regulations of low toxicity, high biodegradation and low bioaccumulation.

The most common method for preventing scale formation is by applying scale inhibitor squeeze treatments. In this process, a scale inhibitor solution is injected down a producer well and into the near wellbore formation. Generally, reservoir formations consist of a number of layers or zones of different permeability which may or may not be in pressure communication. When the zones are non-communicating within the reservoir, they are often at different pressures. When this is the case, then this can have a strong influence on the flow and placement of any injected fluids. Indeed, it can dominate the dynamics of the placement process and can also cause wellbore crossflow during the shut-in period following the squeeze treatment. In order to design a successful squeeze treatment, it is very important to know where the injected fluid goes; i.e. where the slug of scale inhibitor is placed in the formation. Therefore, our squeeze design and prediction models must incorporate these layer pressure effects along with the other models for the scale inhibitor transport and retention mechanisms. In this paper, we develop the analytical expressions for calculating the flow partition in radial layered formations, where the layers are non-communicating. This is not in itself original and these equations are "well known". However, we have incorporated them into our multi-layer, two phase scale squeeze design software (SQUEEZE VI) to simulate situations where layers are at different pressures. We demonstrate that this has an important effect on the scale inhibitor slug placement in a heterogeneous system and it drives crossflow between layers at production or injection stages. Furthermore, we go on to show what the consequences of these placement effects on the squeeze lifetime are. We also present a wide sensitivity study of this effect showing how a number of ancillary parameters affect the squeeze lifetime e.g. the magnitude of the differential pressure between layers, the permeability contrast, the retention mechanism. Finally, we give some general field guidelines for various specific situations where formation zone pressures are not equal in terms of squeeze applications.

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 (Kahrwad et al. 2008), are used to show when the SI/substrate interaction is pure adsorption (Γ) or coupled adsorption (Γ)/precipitation (∏). Experiments were performed for different SIs at various operational conditions, i.e. initial pH values, minerologies - calcite, limestone and dolomite - and temperatures; the overall results from these coupled Γ/∏ experiments are summarised in Table 3. The SI species used in this study included 1 phosphonate (DETPMP), 1 phosphate ester (PAPE) and 3 polymeric scale inhibitors (PPCA, PFC, VS-Co); the full names of these SIs are given in the paper. All precipitates were studied using Environmental Scanning Electron Microscopy/Energy Dispersive X-Ray (ESEM/EDX) and Particle Size Analysis (PSA). These measurements confirmed that when precipitation occurred, it was mainly in the bulk solution and not on the rock surface. 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. 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.

Automatic optimization of oilfield scale inhibitor squeeze treatment designs

This paper describes field application of a novel scale inhibitor squeeze treatment to mitigate downhole scale (calcium carbonate) present in several oil producing wells in a sandstone reservoir in central Saudi Arabia. The sandstone reservoir is weakly consolidated, water sensitive, and sanding problems were noted in several wells. The water cut in the scaled wells ranges from 3 to 80 vol%. To avoid sanding problems, most of these wells were gravel packed. In addition, the reservoir pressure and gas oil ratio are low and, as a result, electrical submersible pumps (ESPs) are used to produce these wells. The sandstone reservoir is heterogeneous and contains up to 14 wt% clay minerals in some zones. The bottom hole temperature is nearly 160°F. A thorough investigation was undertaken to develop a suitable scale squeeze treatment to mitigate the scale, and to assess the effectiveness of the treatment in the field. Based on extensive lab studies, a new emulsified scale inhibitor treatment was designed and applied in more than fifteen wells. These wells were descaled prior to the squeeze treatment as was detailed by Nasr-El-Din et al.1 All scale squeeze treatments were conducted using 1.75 or 2 in coiled tubing. Because the formation is water-sensitive, the main treatment, the pre and post flushes were designed to minimize formation damage due to fines migration and clay swelling. Following the treatment, the well was shut-in for two days to give ample time for various reactions to occur. Chemical analysis of well flow back samples was used to estimate the lifetime of the squeeze treatment. In addition, a downhole video camera was used to follow scale formation following the treatment. The scale squeeze treatment was conducted in more than fifteen wells. The emulsified inhibitor was mixed in the field and was injected into the target zones without encountering any operational problems. Analysis of flowback samples indicated that the treatment did not affect well productivity or water cut in any of the treated wells. Based on field data, it is known that the treatment lifetime is greater than two years. The minimum scale inhibitor concentration, presented as phosphorus, is nearly 1 mg/L.

Systematic literature review of machine learning based software development effort estimation models

Geothermal energy refers to the heat stored in the subsurface that can be extracted by producing the hot fluids (water and/or steam) in contact with the hot formation. A major issue that may restrict the extraction of geothermal energy is precipitation of mineral scales which can occur within the reservoir, inside the wellbore, or surface facilities. The objective of this paper is to find the most efficient scale treatment strategy to prevent mineral scaling. Continuous injection of chemical scale inhibitor (SI) downhole in the production well, is the most common method to prevent mineral scale in geothermal plants. This method although effective does not protect the near-wellbore area, where the highest pressure drop is expected. To address this issue, two methods will be studied, bullheading the production well with SI, commonly known as squeeze treatment, and injecting SI in the injection well. Optimum designs for both methods were identified considering different levels of SI adsorption, and also permeability variation in fractured and non-fractured formations. As expected, the volume of SI required in continuous injection in producer was lower than the other two methods. However, in cases where the highest risk of precipitation is in the near-wellbore area or it is below the continuous injection point, it is necessary to apply one of the suggested methods. While the squeeze treatment protects only the formation around the producer well, treatments deployed in injector wells will protect the whole system and this extra protection may offset the extra volume of chemical necessary. The application of SI in injector well was studied in both continuous and batch mode with different injection frequencies. It was shown in continuous injection that even though less SI volume is used, the SI breakthrough time in producer can be so long that a series of squeeze treatments might be required to protect the well. The simulation results showed that in high adsorption formations, squeeze treatment is more efficient than deploying SI in the injector well. However, in cases of low adsorption and fractured reservoirs, the scenario commonly found in geothermal plants, SI injection at the injector is more optimal. Two different scale treatment methodologies were studied in geothermal wells, including squeeze treatment in producer and SI injection in the injector and the results were compared with the continuous SI injection in producer, which is the most current treatment in geothermal wells. It was illustrated in fractured geothermal reservoirs with relatively low levels of adsorption, that SI injection in the injector is the most optimum treatment that can effectively protect the whole plant from scaling.