Cause Of Formation Damage Research Articles

Model Characterizes Formation Damage Caused by Fines Breakage and Migration

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 208810, “Formation Damage Caused by Fines Breakage and Migration,” by Abolfazi Hashemi, Sara Borazjani, and Bryant Dang-Le, SPE, University of Adelaide, et al. The paper has not been peer reviewed. _ Fines migration is a major cause of formation damage; the detached clays migrate and impair well productivity. Two types of damaging clays are encountered in petroleum reservoirs: authigenic clays that grew on the grain surfaces during geological times, and detrital clays that have been broken off the grains because of local stresses. The aim of the work described in the complete paper was the development of a laboratory procedure to estimate formation damage by authigenic clays and the derivation of a mathematical model for core scale. Background Detrital particles are attached to a substrate by an electrostatic force and can be modeled using the DLVO theory. Most core samples, however, have some authigenic clay content (i.e., clay particles bonded to rock). To study formation damage caused by the detachment of authigenic clay, a new formulation should be presented. The formulation should be based on failure or breakage criteria of the contact bond between the particle and a substrate. To the best of the authors’ knowledge, the theory for detachment of a single authigenic particle is not available. The purpose of this study was the development of a laboratory-based mathematical model to estimate formation damage by authigenic clays. In the complete paper, the authors assumed that the bond between the authigenic clay and rock acts as a cantilever beam. The cohesive beam model (CBM) was applied to formulate the detachment of the particle because of the applied drag force. The stress state at the bond was governed by the Timoshenko beam theory. These equations are applicable for the elastic limit of both brittle (elastic) and ductile (elastic/plastic) materials, and only different failure criteria were applied. Kaolinite in porous media was assumed to be elastic/perfectly plastic. For defining failure for this type of material, yield criteria were applied. The von Mises yield criterion was used to define failure. For detachment of every particle, a specific drag force or a fluid velocity must be applied. Because a large number of particles with different random properties exist in porous media, by considering a distribution for each property, a distribution for detachment velocity can be obtained. By taking an integral from this distribution bounding to experimental velocities, the amount of detachment between two fluid velocities can be obtained. The same procedure can be followed for detrital particles and authigenic particles. Total detachment concentration is the sum of authigenic and detrital particles. The total detachment is matched with laboratory data. Having obtained the matching parameters, a maximum retention function curve can be plotted. This new maximum retention function takes into account the detachment of both authigenic and detrital particles. In the complete paper, the authors initially presented the assumptions of their models, then governing equations for detrital particle detachment and detachment of authigenic particles; finally, the formation damage formulation and solutions were provided, which are applicable for both detrital and authigenic particles.

RESERVOIR CHARACTERIZATION OF THE PLIOCENE RED SERIES, LAM FIELD AND SURROUNDING AREAS, OFFSHORE WESTERN TURKMENISTAN

The sedimentology, petrography and reservoir potential of Pliocene sandstones within the Upper Red Series in the offshore LAM field, Western Turkmenistan, have been examined. Depositional settings are interpreted within the framework of the Red Series palaeoenvironments across the entire Turkmen sector of the Apsheron‐Prebalkhan uplift zone, including its onshore extension to the east.Examination of 81 m of core from three separate intervals suggests that the Red Series in the LAM field is the product of a fluvial‐dominated delta system with associated floodplain deposits, periodically flooded by the saline waters of the South Caspian Lake. Relatively thick sandstones, up to around 5 m thick, are interpreted as channel and point‐bar deposits of a meandering river system, with thinner and finer‐grained sandstones and siltstones inferred to be crevasse‐splay and interdistributary floodplain deposits. Floodplain mudstones display signs of desiccation, soil formation, plant rootlets and occasional thin layers of anhydrite. Intervals with marine trace‐fossil assemblages record incursions of saline‐lake waters. Conglomeratic layers at the base of thicker mudstone intervals may be associated with abrupt transgressions of the lake. The best reservoir qualities are associated with the fluvial channel and point‐bar sandstones. Crevasse‐splay and other overbank sandstones are of poorer quality, while intercalated floodplain to lacustrine claystone/siltstone units may constitute local seals.Eighteen sandstone plug samples from the cored intervals were examined in thin‐section and by XRD and SEM to assess how mineralogy, grain size and diagenesis affect reservoir quality. The samples consist predominantly of lithic arkoses and feldspathic litharenites; higher porosities, and therefore better reservoir potential, are associated with the feldspathic litharenites. Primary controls on porosity include compaction, clay‐matrix content and calcite cementation. XRD data reveal the presence of illite, illite‐smectite and chlorite. The presence of swelling clays has been the main cause of formation damage in the field.The interpretation of meandering fluvial channels here is thought to represent the first published account of such channels within Pliocene reservoir rocks in the north of the South Caspian Basin. Previous accounts of the Red Series sandstones deposited onshore to the east have indicated deposition within braided channels of the palaeo‐Amu Darya river delta plain, and alluvial‐fan deposits sourced from uplands to the north. Deposition of the equivalent Productive Series by the palaeo‐Volga in the Azerbaijan sector to the west has also been interpreted as having taken place within braided systems, although mixed or suspended‐load fluvial channels ascribed to the contemporary Kura delta farther south may have been associated with a meandering system. Two palaeogeographic maps are presented to illustrate depositional environments for the Red Series during relative high‐ and low‐stands of the South Caspian Lake. The maps cover the area where the Productive Series of Azerbaijan passes into the Red Series of Western Turkmenistan.

A novel approach for pore-scale study of fines migration mechanism in porous media

The migration of fine particles in oil reservoir rock is the most important cause of formation damage and permeability impairment. The mechanism of this phenomenon includes fines detachment, mobilization, agglomeration, and re-attachment, which lead to throat clogging and/or blocking. Therefore, accurate modeling of this complex mechanism requires a model with high solver efficiency.In this work, based on the physical features of fines migration in pore throat, the conventional DPM model of ANSYS FLUENT software was initially modified by UDF code. Then, predetermined scenarios of suspension injection into a two dimensional (2D) microchannel were simulated for predicting pressure drop as a function of injected pore volume using the modified DPM model. Next, based on these simulation results, a proxy model using the artificial neural network (ANN) was developed for computational cost reduction of fines migration modeling in the microchannel (pore throat). Secondly, a dual pore scale numerical model by combination of proxy model and pore network modeling approach was developed to predict pressure drop as well as permeability impairment in a network of microchannels (porous media). Moreover, for rapid computation of pressure drop in the network model, a meta-heuristic method of rain optimization algorithm (ROA) has been used. Finally, for model validation, a series of laboratory tests including suspension injections into the glass micromodels were conducted.A comparison of simulation results using both proxy model and dual pore scale model with experimental data shows a good agreement and according to the obtained results, a decrease in the particles mean size, and Reynolds number as well as increase in particles concentration lead to increase in pressure drop and permeability reduction. On the other hand, use of a proxy model based on artificial neural network and a meta-heuristic method of rain optimization algorithm lead to significant computational cost reduction, while the accuracy of fines migration modeling is high enough. Hence, using our modeling approach for fines migration study in porous media as an accurate and fast computational tool can help for a better understanding of this phenomenon, which is very important in the petroleum industry.

DLVO Modeling to Predict Critical Salt Concentration to Initiate Fines Migration Pre- and Post-Nanofluid Treatment in Sandstones

Summary The critical salt concentration (CSC) of injected water used for various water-based oil recovery operations is the salt concentration below which fine particles are released and their migration starts within sandstone reservoirs containing clays. This phenomenon could be one of the potential causes of formation damage and associated injectivity and productivity declines. This paper proposes a novel method of quantifying surface forces between fines and sand grains and using DLVO (named after Derjaguin, Landau, Verwey, and Overbeek) modeling to predict a CSC pre- and post-nanofluid treatment. Furthermore, the effectiveness of varying concentrations of silica nanoparticles (SNPs) in controlling fines migration and reducing CSC was modeled by the DLVO approach and experimentally validated. The experimental CSC was determined by performing corefloods and analyzing effluent turbidity and absorbance under various salinities of the injected brine to validate the developed models. The zeta potentials of sand-fine-brine (SFB) systems were measured and ranged from −35.2 to 29.5 mV. The average size of fine particles was 800 to 900 nm based on scanning electron microscopy (SEM) results. Using DLVO modeling before the application of nanoparticles (NPs), the CSC was predicted to be 0.11 M (6,400 ppm) NaCl brine, at which the total DLVO interaction energy shifted from attraction to repulsion. Moreover, another DLVO model was developed considering the effect of SNPs. Models predicted 0.085 M (4,900 ppm) and 0.075 (4,400 ppm) NaCl CSC values after the application of 0.05 and 0.1 wt% SNPs, respectively. Afterward, corefloods were performed that showed that the experimental results of CSC with and without SNPs treatment were in close agreement with the DLVO models. Fines migration was observed at 0.08 M (4,700 ppm) and 0.07 M (4,100 ppm) salinity after nanofluid treatments. Many oil recovery processes, including but not limited to low-salinity waterflooding and alkaline flooding, require the estimation of the CSC to avoid formation damage. The proposed DLVO model is instrumental to predict the CSC for monovalent NaCl brine pre- and post-nanofluid application without requiring extensive experimental work. Moreover, the use of nanofluid showed promising results in terms of fines migration control and reduction in CSC.

Effects of reservoir rock pore geometries and ultrasonic parameters on the removal of asphaltene deposition under ultrasonic waves

Asphaltene deposition around the wellbore is a major cause of formation damage, especially in heavy oil reservoirs Ultrasonic stimulation, rather than chemical injection, is thought to be a more cost-effective and environmentally friendly means of removing asphaltene deposition. However, it seems to be unclear how crucial features like reservoir pore geometries and ultrasonic parameters affect this ultrasound treatment.In this work, five two-dimensional glass micromodels with different pore geometries were designed to assess the impact of pore geometries on the ultrasonic removal of asphaltene deposition. Experiments were undertaken in an ultrasound bath at a set frequency (20 kHz) and adjustable powers (100–1000 W). Direct image analysis before, during and after sonication was used to assess the impact of pore geometry and a change in ultrasonic parameter on the removal of asphaltene deposition. The effectiveness of ultrasound treatment at various sonication periods were found to be reliant on the pore geometries of the individual micromodels. For micromodels with throat sizes 300 µm and pore shapes as circle, square and triangle, an increase in ultrasonic power from 400 to 1000 W resulted in an increase in the percentage of removed asphaltene deposition after 2 h from 12.6 to 14.7, 11.5 to 14.63, and 5.8 to 7.1 percent, respectively.

Critical rate analysis for CO2 injection in depleted gas field, Sarawak Basin, offshore East Malaysia

This study aimed to address the challenges and strategies to determine the critical rate of CO2 injection into a carbonate depleted gas field. In this research, the critical rate is the maximum allowable injection rate before formation damage initiation. The cause of formation damage could be due to in-situ mobilization or trapping of migratory fines resulting in plugging the flow path. This study performed a thorough investigation of a different rock-fluid system to evaluate the safe injection limit, as the critical rate is different for each rock-fluid system. The geochemical effect of CO2 injection toward carbonate formation was also investigated in this research. Other than that, the porosity and permeability changes due to CO2-brine-rock multiphase flow characteristics were considered to understand the feasibility of CO2 sequestration into carbonate formation. This research discussed experimental design to mimic the CO2 injection scenario of CO2 into carbonate depleted gas field. Therefore, several core flooding experiments were conducted under reservoir conditions using representative native cores, CO2, and synthetic formation brine. Abrupt changes in differential pressure (ΔP), analysis of effluent collected after CO2 multi-rate flow, and pH reading are the key indicators to consider that the condition has reached a critical rate. The experimental result demonstrated the existence of fines migration, scale formation, and salt precipitation after the core was subjected to supercritical CO2 multi-rate flow. Considering these issues and challenges associated with injectivity, this study recommended a maximum injection rate prior to field scale injection.

Application of DLVO Modeling to Study the Effect of Silica Nanofluid to Reduce Critical Salt Concentration in Sandstones

Critical salt concentration (CSC) is the minimum salt concentration of injected water used for different oil recovery operations, below which fines migration initiates within sandstone reservoirs having clay contents and could be one of the potential causes of formation damage. This paper estimated CSC for Berea sandstone-NaCl brine system experimentally and by using DLVO modeling based on Van der Waals and electric double layer (EDL) surface forces. Furthermore, the effectiveness of silica nanofluid to reduce CSC and control fines migration was investigated. At different salinities of the injected fluid, the experimental CSC was determined by performing corefloods and analyzing effluent turbidity and absorbance. Attractive (van der Waals) and repulsive (EDL) forces were estimated by DLVO theory to predict the value of CSC. The experimental data were used to validate the model. The application of silica nanoparticles (NPs) was studied by injecting 0.1 wt% silica nanofluid and the resultant reduction in CSC was observed. During the injection of brines at different salinities ranging from 0.2 M to 0.05 M into the sandstone porous media, fines production was detected in the effluent after the injection of 0.1M NaCl solution, indicating that the CSC was 0.1M for this sand-fine-brine (SFB) system. The zeta potentials for SFB systems of different salinities were measured by zeta-sizer and were in the range of -32 mV to -24 mV. DLVO model based on attractive and repulsive forces was then used to predict the CSC, at which the total DLVO energy shifts from negative to positive and was around 0.1M for NaCl solution. The model prediction was in close agreement with the experimental results. Both the experiment and DLVO model showed the efficiency of silica nanofluid to mitigate fines migration as no fines production was observed for 0.1M NaCl case after the treatment with nanofluid. The estimation of CSC is critical to avoid formation damage during many oil recovery processes, included but not limited to low salinity waterflooding and alkaline flooding. The utilization of nanofluid provided promising results in controlling fines migration and reducing CSC. The proposed model based on DLVO theory can work as a useful tool to predict CSC without the need for extensive experimental work.

Experimental quantification of formation damage caused by the cross-linked gel in tight gas reservoirs

Evaluating the formation damage in tight rocks caused by the cross-linked gel is essential to estimate the hydrocarbon production after hydraulic fracturing. However, the steady-state measurement using the conventional core flooding experiment can be time-consuming in tight rocks with permeabilities below 0.01 mD. In this study, the pressure transmission test, an unsteady-state measurement, was applied to quantify the formation damaged caused by the cross-linked gel after fracturing. The potential damage mechanism was studied using the scanning electronic microscope, wettability tests and imbibition tests. Besides, the particle size of the gel residue was analyzed, and the impact of gel on the wettability of the rock surface, surface tension, and imbibition of the fracturing fluid was evaluated to understand the cause of formation damage by the gel. Results showed that the permeability depends on the pore-throat size rather than the pore-body size in the tight rocks. The content of illite is high, which is sensitive to the aqueous phase and pressure. The average permeability damage is 12.6% after the filtered fracturing fluid invasion. The particle in the pore can be observed through the SEM. The manuscript provides a new method to evaluate the formation damage induced by the cross-linked gel fracturing fluid in tight gas reservoirs.

A dynamic scale location monitor method to predict oilfield blockage during water flooding

Scale formation of oil and gas production is a serious problem as major causes of formation damage affecting recovery efficiency. Investigation the permeability reduction caused by scale formation of sandstone cores by mixing formation water and injection water with different ratio under various temperatures and differential pressure is conducted in this study. X-ray diffraction (XRD) technique is used to investigate to judge the types of inorganic scale by analyzing its crystalline composition. Scale prediction and beaker test results show that the inorganic scale produced by poor compatibility of formation water and injection water in XX oilfield is calcium carbonate. With the increase in the ratio of injection water to formation water, the scale of calcium carbonate scale first increases and then decreases. The scale of calcium carbonate is gradually increasing with the decrease of pressure and increase of temperature. The dynamic scale location monitoring method is proposed to predict the degree of oilfield blockage based on the pressure difference between multi-pressure measuring points of the core. Dynamic scale location monitor tests show that inorganic scale blockage occurs in the position range of 0–1/10 around injection well in the early stage of water flooding, and further increase of injection rate will result in migration leading the blockage occurs in the position range of 1/10–6/10 near the injection wells. The prediction results are consistent with the actual blockage in the oilfield, proving that this method guides significance of predicting blockage in water flooding. This method can be used in both onshore and offshore oilfields using water flooding as a secondary oil recovery.

Technology Focus: Formation Damage (February 2020)

Technology Focus One of the frustrating aspects of well-productivity analysis is identifying the causes of lower-than-expected productivity index (PI) during initial well lifetime. We are presented with a well that has a higher initial skin than expected with concomitant lower PI. Our task is to evaluate the multivariate aspects of well design, drilling and completion fluid design, geological characteristics (e.g., clay mineral type and abundance), permeability variation, net-to-gross ratio, and kh product among many other variables. The data are plotted, and we attempt to identify trends, if any. Out of all of this, we eventually come to the most-likely damaging mechanism (e.g., significant mud losses to the formation because of a poorly designed particle-size distribution or ineffective wellbore cleanup). Alternatively, the completion can be damaged, the most common mechanism of which, in a well completed with screens, is plugging. The key expression here is “likely damaging mechanism,” because we have no actual way of going downhole and identifying at close range the actual damaging mechanisms. Brant Bennion’s definition of formation damage, which I like to quote, aptly summarizes the conundrum when he said that it was “the impairment of the invisible.” A further complication is the situation where two or more damaging mechanisms are operating concurrently. For example, the previous examples of mud losses to the formation combined with screen plugging can contribute in the same well to lower the PI and increase the skin. However, we have no way of identifying which of these is the most significant factor in explaining the observed well productivity or, in fact, if they are contributory factors in the first place. Inference is the only tool we have, and even that is fraught with inaccuracy. Coreflooding can be used to determine the potential causes of formation damage by replicating the fluid sequence used in the damaged well. However, it is nonquantitative with regard to simulation of damaging effects along the production interval, especially if these are not uniformly distributed within a heterogeneous reservoir (i.e., in such cases, a coreflood represents a specific point along the production interval rather than representing the entire length). Reduced well productivity during later well lifetime is generally a result of a different set of damaging mechanisms than those seen in initial production. Damaging mechanisms typical for mid- to late-life wells include fines mobilization, scale, and asphaltene formation. A few years ago, I was involved in a mud-acid stimulation intervention where we were convinced that the explanation for reduced productivity in this well was fines mobilization (kaolinite). Many corefloods had been performed on this particular formation that showed kaolinite could mobilize under scaled-down reservoir flow rates. For the particular candidate well, we pumped diesel to see if we could flush kaolinite from the near wellbore and saw an increase in productivity for a few days before the PI returned to its previous value. Corefloods were performed to qualify mud acid and showed positive results. The intervention was planned thoroughly and executed as expected. However, when the well was started, the PI was the same as before the intervention. Formation damage can be so frustrating. Enjoy the papers I have selected, some of which touch on the comments I have made. Recommended additional reading at OnePetro: www.onepetro.org. SPE 197974 Raising the Bar of Productivity Improvement in an Abnormal and Distinctive Pressure and Temperature Environment: Niger Delta by Oyeintonbra Imbazi, Shell, et al. SPE 189562 Laboratory Preparatory Work of Cased-Hole Cleanup as Part of an Entire Remedy Program in Removing Damage Attributed to Oil-Based Mud by Hideharu Yonebayashi, INPEX, et al. OTC 28666 Completion-Fluids-Induced Formation Damage in High-Temperature Gas Wells: Causes and Mitigation by Bilel Hamzaoui, Saudi Aramco, et al.

Formation damage evaluation of a sandstone reservoir via pore-scale X-ray computed tomography analysis

The incompatibility between workover fluid and reservoir rock is one of the causes of formation damage. Fines migration and clay swelling are considered as the major mechanisms responsible for formation damage, which results in declining productivity. However, there has been limited visualized evidence of pore structural changes during formation damage. This paper establishes a formation damage evaluation method for sandstone reservoirs based on X-ray micro-computed tomography (CT) analysis. We presented conclusive evidence for clay swelling and fines migration during workover fluid flooding and formation liquid flooding. Water sensitivity and flow rate sensitivity tests were performed on a Dongying sandstone (heterogeneous argillaceous sandstone) plug. In addition, the plug was micro-CT imaged before and after flooding with workover fluid and formation liquid at medium resolution (24 μm voxel size); the changes in core permeability and the associated changes in 2D and 3D pore space were analyzed. We found that the sandstone pore space was partially blocked by clay minerals and moving particles, leading to significantly decreased porosity (5.17%–4.19% for sample 1, 5.38%–2.76% for sample 2) and permeability (3.38 × 10−3 μm2 to 1.28 × 10−3 μm2 for sample 1, 13.30 × 10−3 μm2 to 3.15 × 10−3 μm2 for sample 2). This permeability decrease was caused by a decrease in the average pore radius and coordination number. Moreover, increased micro-CT intensity was measured by comparison of initial and final tomogram images, representing clay swelling & blockage of pores during the displacement and a generally lower porosity. This work visualized microscale formation damage, which reminds that incompatibility between workover fluid and reservoir rock damages formation seriously and the fluid injection rate should be lower than the critical flow rate when developing a reservoir with a strong water sensitivity and flow rate sensitivity.

Fines surface detachment and pore-throat entrapment due to colloidal flow of lean and rich gas condensates

This paper describes about the lean and rich gas condensate effects on fines migration in porous rocks. Fines detachment from rock surface and pore throat entrapment are frequent causes of formation damage and well productivity loss. In condensate reservoirs, there is a large volume of liquid formation during reservoir pressure depletion. This will result in liquid loading and production decline. In this work, we critically discuss the fines migration and the permeability decrease mechanism in the gas condensate reservoir. For this purpose, we numerically simulated a condensate reservoir, which is capable of undergoing a phase transition from gas to liquid as a function of pressure depletion, temperature, and time. We have implemented CFD modeling to simulate this retrograde condensation process. The major results revealed that there is a high amount of heat release during phase transition. This heat release and condensed liquid flow detached the fines from the rock surface and finally, get trapped in the pore-throat. Our models have been validated against the experiments and showed good agreement. Overall, this work may serve as a base to re-examine the gas condensate reservoir behavior with fines transport in porous rocks.

Application of ultrasonic as a novel technology for removal of inorganic scales (KCl) in hydrocarbon reservoirs: An experimental approach

Inorganic scales are one of the most important causes of formation damage, which causes pressure drops near wellbores; these in turn impair permeability and severely reduce production in oil and gas reservoirs. This paper examines the effectiveness of ultrasonic waves in removing potassium chloride (KCl) scales. Twenty core samples with different permeabilities were exposed to KCl precipitation. After measuring the permeabilities of the saturated core samples, the samples were first subjected to water injection, and then to water injection with ultrasonic wave radiation. At each stage, sample permeabilities were measured and recorded. The results showed that water injection with two pore volumes did not significantly improve permeability, especially in low-permeability core samples. Ultrasonic wave radiation with water could efficiently improve permeability; this result is more obvious for samples with lower permeabilities. SEM images taken from thin sections of the core samples under water injection and water with ultrasonic waves showed that ultrasonic waves distorted the crystal lattice of the KCl scales, causing cracking and delamination. Creation of wormholes in KCl deposits within fractures also resulted from the application of ultrasonic waves. Analysis of chlorine in the output water from core samples in the core-flooding process showed that ultrasonic waves increased the solubility of scales in water, improving the recovery of permeability in the samples. Results of this study show that using ultrasonic waves can be considered a novel and practical method in the removal of inorganic scales in the near-wellbore region of oil and gas reservoirs.

Lost-Circulation Control for Formation-Damage Prevention in Naturally Fractured Reservoir: Mathematical Model and Experimental Study

Summary Drill-in fluid loss is the most important cause of formation damage during the drill-in process in fractured tight reservoirs. The addition of lost-circulation material (LCM) into drill-in fluid is the most popular technique for loss control. However, traditional LCM selection is mainly performed by use of the trial-and-error method because of the lack of mathematical models. The present work aims at filling this gap by developing a new mathematical model to characterize the performance of drill-in fluid-loss control by use of LCM during the drill-in process of fractured tight reservoirs. Plugging-zone strength and fracture-propagation pressure are the two main factors affecting drill-in fluid-loss control. The developed mathematical model consists of two submodels: the plugging-zone-strength model and the fracture-propagation-pressure model. Explicit formulae are obtained for LCM selection dependent on the proposed model to control drill-in fluid loss and prevent formation damage. Effects of LCM mechanical and geometrical properties on loss-control performance are analyzed for optimal fracture plugging and propagation control. Laboratory tests on loss-control effect by use of different types and concentrations of LCMs are performed. Different combinations of acid-soluble rigid particles, fibers, and elastic particles are tested to generate a synergy effect for drill-in fluid-loss control. The derived model is validated by laboratory data and successfully applied to the field case study in Sichuan Basin, China.

Characterisation of formation damage during reactive flows in porous media

Precipitation of solids due to chemical reactions or thermodynamic non-equilibrium is a common cause of formation damage in oil and gas wells. The traditional mathematical model for reactive flow in porous media contains two empirical parameters: the kinetics rate coefficient, which along with the reagent's concentrations determines the reaction rate; and the formation damage coefficient, which reflects the permeability reduction due to solid phase precipitation. These parameters are determined from laboratory coreflooding tests, which involve commingled injection of reacting fluids. A routine laboratory method determines the kinetics rate coefficient from expensive and cumbersome reagent concentration measurements at the core outlet, after which the formation damage coefficient can be calculated using inexpensive and robust pressure drop measurements. The current paper developed a laboratory method for determining both coefficients from pressure measurements only. The method utilised pressure measurements at the core inlet, outlet and some intermediate core port during commingled quasi-steady-state flow of incompatible fluids. The above data treatment was based on the analytical model for one-dimensional commingled flow of reacting fluids. The formulae for determining the model coefficients from pressure measurements have been derived. The intervals for inverse solution existence, uniqueness, and stability were established. The proposed method was validated by high agreement between the model constants determined by the customary method and the three-point-pressure method.

The Effect of Temperature on Calcium Sulfate Scale Tendency in an Iranian Oil Reservoir and Production Equipment During Water Injection

Scale formation in surface and subsurface oil and gas production equipment has been recognized to be one of the major operational problems. It has also been recognized as the major cause of formation damage either in injection or producing wells. Scale contributes to equipment wear and corrosion and flow restriction, thus resulting in a decrease in oil and gas production. This article presents the predicting of calcium sulfate scale tendency of formation water, injection water, and mixing of injection water with formation water at different temperatures. The experimentally measured chemical analyses of formation water and injection water were used by OLI ScaleChem software to determine the tendency of scale formation. This software has been applied to investigate the potential of calcium sulfate scale precipitation in Iranian oilfields, either in onshore or offshore fields, where water injection is being performed for desalting units' water disposal purpose or as a method of secondary recovery or reservoir pressure maintenance.

A Prediction of the Amount of Strontium Sulfate Scale Formation in Siri Oilfield at Different Temperatures and Pressures

Scale formation in surface and subsurface oil and gas production equipment has been recognized to be one of the major operational problems. It has also been recognized as a major cause of formation damage either in injection or producing wells. Scale contributes to equipment wear and corrosion and flow restriction, thus resulting in a decrease in oil and gas production. This article presents the amount of strontium sulfate precipitation of formation water, injection water, and mixing of injection water with formation water at different temperatures and pressures. The experimentally measured chemical analyses of formation water and injection water were used by OLI ScaleChem software to determine the amount of strontium sulfate scale formation at different conditions.

The Study of Calcium Sulfate Scale Formation during Water Injection in Iranian Oil Fields at Different Pressures

Scale formation in surface and subsurface oil and gas production equipment has been recognized to be one of the major operational problems. It has also been recognized as one of the major causes of formation damage either in injection or producing wells. Scale contributes to equipment wear and corrosion and flow restriction, thus resulting in a decrease in oil and gas production. This article presents the predicting of calcium sulfate scale tendency of formation water, injection water, and mixing of injection water with formation water at different pressures. The experimentally measured chemical analyses of formation water and injection water were used by OLI ScaleChem software to determine the tendency of scale formation. This software has been applied to investigate the potential of calcium sulfate scale tendency in Iranian oil fields, either in onshore or offshore fields where water injection is being performed for desalting units' water disposal purpose or as a method of secondary recovery or reservoir pressure maintenance.

姬塬油田储层注水伤害分析与化学增注技术研究

姬塬油田属特低渗油田，在注水开发过程中，因注入水与地层水严重不配伍，导致储层孔喉结垢，影响油田注水开发。本文通过对注入水与地层水分析、水管路流动结垢实验、注水储层伤害评价等，认为注入水与地层水不配伍是造成储层伤害的主要原因之一。开发了能够溶解硫酸钡锶垢的YHS-1清垢剂，有效解除储层结垢堵塞，恢复储层渗透率。 Jiyuan oilfield is an oil field with extremely low permeability. During the waterflooding process, because the injection water can not be concurrent with formation water, the scales at reservoir pore-throat will influence the waterflood development of oilfield. In this article, according to the analysis of injection water and formation water quality, scaling experiments of water flows, evaluations for water injection reservoir damage, it makes clear that the incompatibility of injection water and formation water is one of the main causes of formation damage. YHS-1 was employed as the cleaning agent of barium and strontium sulfate scale to relieve the reservoir scale blockage effectively and restore the reservoir permeability consequently.

The Design and Development of a Drilling Simulator for Planning and Optimizing Under-Balanced Drilling Operations

Summary Computer simulation technology has been widely applied in many drilling engineering areas to simulate drilling engineering problems and optimization, to train engineers with real drilling operations and/or to handle rare applications and accidents. Among the increasingly applied drilling operations is under-balanced drilling (UBD). UBD is the drilling process in which the wellbore pressure is intentionally designed to be lower than the pressure of the formation being drilled. This results in a higher rate of penetration (ROP) and prevents fluid losses and related causes of formation damage. This paper presents the design and development of a UBD simulator, which is computer software that simulates and integrates the effects of: Bottomhole pressure (BHP). Minimum volumetric gas and liquid requirement. Required backpressure (BP) for required cutting removal to surface and controlling BHP. Kinematic energy per unit volume used in the hole cleaning considerations. Stand pipe pressure (SPP). Rock drillability. ROP. Drilling costs per metre. The goal of the simulator is to enable the user to pre-simulate different scenarios of the UBD drilling operations; therefore, the ideal optimized combination of drill bit durability and drilling efficiency, integrating all UBD operational parameters affecting the overall cost, can be obtained before the fact. The UBD simulator is designed to simulate most of the basic technologies of UBD (air, aerated and foam drilling). The goal of the UBD simulator is to design an effective UBD program by linking the BHP to rock drillability, which takes into account the effect and degree of under-balance on the effective rock strength, ROP and $/m that can be optimized for the operation. The complete UBD optimization integration is shown herein with illustrations including flowcharts.