Evaluation Of Formation Damage Research Articles

Evaluation of Formation Damage of Oil-Based Drilling Fluids Weighted with Micronized Ilmenite or Micronized Barite

SummarySolids found in drilling fluids, particularly weighting materials, can cause significant formation damage by plugging of formation pores. This study investigates formation damage caused by using oil-based drilling fluid systems weighted by micronized ilmenite or micronized barite. Rheological properties of the oil-based-mud (OBM) systems were measured. High-pressure/high-temperature (HP/HT) static filtration experiments were conducted. A coreflood system was used to simulate dynamic conditions, allowing for drilling fluid circulation at the face of the core and measuring permeability damage. Computed-tomography (CT) scan analysis revealed formation damage and depth of solid invasion. The paper presents field applications of nondamaging micronized-ilmenite-based OBM, illustrating its advantages.

Fracturing fluid retention in shale gas reservoirs:mechanisms and functions

Shale gas reservoirs are characterized by nano-Darcy permeability, rich organic matter, ultralow water saturation, developed bedding, and micro-fractures, leading to multi-scale transportation of shale gas. Multistage fracturing of horizontal wells is the main development technology to stimulate shale gas reservoirs, and tens of thousands of cubic meters of fluids are injected into the reservoir. Retention and flowback of fracturing fluids on gas transfer plays an important role on the effect of hydraulic fracturing. Through the analysis of geological and engineering factors controlling water imbibition and diffusion in shale gas reservoirs, the mechanisms of low recovery of fracturing fluids and the reasons that some shale gas wells with low recovery of fracturing fluids have high gas production rate were revealed. This paper carried out a series of experiments of the fluid imbibition and fracture initiation in the shale selected from the Longmaxi Formation in Sichuan basin. In detail, this paper investigated imbibition and dispersion the fluid in shale and analyzed the mechanisms of the shale-water interactions causing the reduction of shale strength and fracture initiation and propagation. Based on the field case studies of well shut-in after fracturing, its influence on the well production was assessed. Formation damage caused by fracturing fluid is multi-scale, and the evaluation of formation damage caused by fracturing fluids should take the influence on the gas transmission capacity into consideration, and residual fracturing fluids may have a positive effect on gas transfer. It should take the long-term stable production of shale gas well and the effect of fracturing fluids transmission on gas multi-scale transport into consideration when determining the timing and pressure difference of fracturing fluids flowback from shale gas reservoirs.

An Integrated Method To Evaluate Formation Damage Resulting from Water and Alkali Sensitivity in Dongping Bedrock Reservoir

Summary Dongping Field with low porosity and permeability, located in the Qaidam Basin, is the largest bedrock reservoir in China. Because of its high content of clay minerals and poor physical properties, the reservoir tends to suffer from formation damage caused by water or alkali sensitivity, which significantly affects production. Therefore, it is crucial to understand the formation-damage mechanisms for reservoir protection and efficient development. In this paper, we propose a new method that integrates pressure-transmission tests (PTTs) with a fixed-point scanning electron microscope (SEM) and nuclear magnetic resonance (NMR) to investigate mechanisms of formation damage. From the macroscopic perspective, PTT, a time-saving and accurate method of measuring permeability for tight rocks, is applied to evaluate the permeability-damage degree of core samples. From the microscopic perspective, the change of pore structure for a specific region and the variation of the fluid volume in the core sample before and after damage are obtained by fixed-point SEM and NMR experiments, respectively. In water-sensitivity damage experiments, the results of PTT show that the permeability-damage rate is approximately 60%, demonstrating that the damage degree of water sensitivity is moderate to severe. The results of the fixed-point SEM demonstrate that the pore sizes suffer from obvious reduction as a result of water-sensitivity damage. NMR experiments demonstrate that the main damage mechanisms vary, depending on the pore sizes. Small pores [0.1 milliseconds ≤ transverse relaxation time (T2) < 10 milliseconds] are damaged by swelling of mixed-layer illite/smectite, and the large pores (10 milliseconds ≤ T2 <100 milliseconds) suffer from the combined damage of swelling of smectite and migration of illite. Using a similar method, the alkali-sensitivity damage test demonstrates that there is no alkali-sensitivity damage in target reservoirs. This novel integrated method is an efficient means to investigate the formation-damage mechanisms for the Dongping bedrock reservoir from comprehensive perspectives. In addition, this method can be widely applied to evaluate formation damage for tight low-permeability reservoirs.

Diseño experimental para la evaluación del daño de formación por contaminación microbiana en procesos de inundación de agua. Un caso de estudio colombiano

Microbial contamination is well known in the oil and gas industry and it occurs in most processes where water processing systems are involved. Microorganisms are spread everywhere, even in the subsurface, where operations of oil exploration and production are developed. For this reason, different genera of microorganisms can affect the Oil & Gas Industry. One of the major problems in oil mature fields undergoing secondary recovery is the contamination with sulfate reducing bacteria (SRB), caused generally by the injection water system (fresh and/or production) and/or of the reservoir (natural or by drilling fluids, completion, stimulation, etc.). This problem causes formation damage and microbiological induced corrosion (MIC) in the injection-production system. In many producing wells, formation damage by microbiological contamination is initially masked by a decline in reservoir pressure; however, initial production of H2S does provide a possible microbial contamination of water production, water injection and eventually petroleum reservoir. In some producing wells, H2S concentrations have exceeded the lethal limits of 250 ppm and there are cases of producing wells with levels above 1000 ppm. In this work, both a conceptual study and an experimental protocol were developed for the evaluation of formation damage by microbial contamination in water flooding processes. It is focused on finding the best stimulation treatment with biocides to H2S and corrosion control in Producer Wells of Oil Fields Undergoing Secondary Recovery as part of the comprehensive strategy to implement in the injection-reservoir-production system of the Chichimene field in Colombia. This study included the following stages:1. State of the art to define main bactericides, matrix stimulation treatments to H2S and corrosion control, removal of biomass (biofilm) and iron sulfide, etc. in producers wells. 2. Conceptual study of the formation damage by growth of sulfate-reducing bacteria.3. Experimental protocol for the evaluation of formation damage due to microbial contamination in water flood processes.4. Experimental evaluation of formation damage due to microbial contamination in cores of the Chichimene field, in Colombia. Finally, the main findings, conclusions and recommendations obtained in this study are shown.Keywords: microbial contamination, microorganisms, secondary recovery, stimulation, formation damage, sulfate-reducing bacteria, water production, waterflooding.

Data-driven approach for evaluation of formation damage during the injection process

Waterflooding is among the most common oil recovery methods which is implemented in the most of oil-producing countries. The goal of a waterflooding operation is pushing the low-pressure remained oil of reservoir toward the producer wells to enhance the oil recovery factor. One of the important objects of a waterflooding operation management is understanding the quality of connection between the injectors and the producers of the reservoir. Capacitance resistance model (CRM) is a data-driven method which can estimate the production rate of each producer and the connectivity factor between each pair of wells, by history matching of the injection and production data. The estimated connectivity factor can be used for understanding the quality of connection between the wells. In the waterflooding operation, the injected water always has the potential of causing formation damage by invasion of foreign particles deep bed filtration (DBF), mobilization of indigenous particles (fines migration), scale formation, etc. The formation damage can weaken the quality of connection (connectivity factor), between the injectors and producers of the field, increasing the skin of injection well. In this paper, DBF is used for creation of formation damage in synthetic reservoir models. Then, it has been tried to find the existence and amount of formation damage by evaluating the connectivity factor of CRM. Finally, the results of that have been used for prediction of skin variation in a real case by using the connectivity factor of CRM.

Evaluation of secondary formation damage caused by the interaction of chelated barite with formation rocks during filter cake removal

Filter cake formed by barite-based drilling fluid are often removed using chelating agents such as Diethylenetriaminepentaaceticacid (DTPA) in combination with other catalysts. During the removal process, the filter cake is soaked with the chelating agent for approximately 24 h, after which they absorb barite from the filter cake to form a barite chelate (BaDTPA). The filter cake thickness may not be homogenous along the wellbore surface, especially in directional wells. As a result, the chelating agent will dissolve the thinner filter cake faster and earlier than the thicker filter cake. Thus, for a given treatment period, the thin filter case is quickly dissolved and the resulting barite chelate will have more time to invade the formation. This paper investigates the interaction between the barite chelate and the rock formation after filter cake dissolution. A suite of lab scale experiments was conducted to simulate filter cake formation on the face of four rock samples (limestone and sandstone) using a High-Pressure High Temperature (HPHT) filter loss apparatus. DTPA (20 wt %) was then used to dissolve the filter cake. A core flooding apparatus was used to inject the effluent barite chelate into the rock samples to simulate its invasion and interaction with the rock. NMR spectroscopy and x-ray micro CT images of the samples revealed interesting changes in the pore size distributions of the samples. Barite chelate released barite precipitates into the pores of the rock and then absorbs cations from the rock minerals. In sandstones, the barite chelates released barites into the small – intermediate pores and absorbed cations ions from the large pores. In carbonates, the barite chelates released barites into the big pores and absorbed cations from small – intermediate pores. Micro-CT scan and spatial T2 NMR analysis also showed that no wormholes were generated during filter cake dissolution. A detailed explanation of the observed results is presented with supporting results.

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.

Applications of fully coupled well/near-well modeling to reservoir heterogeneity and formation damage effects

Applications of a new well/near-well fluid flow modeling scheme to heterogeneous reservoirs and formation damage are presented in this paper. This well/near-well model is based on an analytically solution of an axial-radial productivity model for steady state flow in wells and near-well reservoirs, in which wellbore hydraulics and heterogeneity in the near-well region are incorporated. The numerical model includes a reservoir region describing both radial and axial reservoir flow. It can be used as a stand alone simulator, or it can be coupled with a reservoir simulator, using a new iterative coupling scheme described in this paper. When coupling with the reservoir simulator, the reservoir region in the well/near-well model is shared by and computed in both models, which ensures the stability and convergence of the iterative coupling scheme. A new coupling approach is presented without needing to determine any partial derivatives.The capabilities of the modeling methodology are demonstrated through applications in three challenging cases: highly heterogeneous reservoir, well/reservoir crossflow, and formation damaged reservoirs. In the highly heterogeneous near-well reservoir case, results show that the model is stable for a wide range of permeabilities with large contrasts. The detailed permeability information from well logging can be fully taken into account in this model. The model determines pressure distribution and volumetric flow rates including flow directions, therefore enabling the model to estimate crossflow as negative flow rates, for example when the well is producing from several non-communicating regions. Furthermore, the well/near-well model is iteratively coupled with a reservoir simulator such that the well completion effects are taken into consideration in large scale simulations. The transient case of this coupling to evaluate formation damage along a horizontal well is then presented. The model is not limited to single phase flow. A two phase flow example coupling the well/near-well model and a streamline reservoir model is finally presented.

Evaluation of the near fracture face formation damage caused by the spontaneously imbibed fracturing fluid in unconventional gas reservoirs

In the present study, spontaneous imbibition experiments, steady-state permeability measurements, and numerical simulation were integrated to quantify the changes in the effective water permeability, capillary pressure, and water relative permeability curves due to the polymer adsorption of the spontaneously imbibed fracturing fluid. The effect of the nonionic surfactant and core bedding plane on the fluid spontaneous imbibition volumes were also investigated.The researchers considered the impact of the spontaneous imbibition of a friction reducer fluid in tight sand and shale core samples. Three comparative systematic spontaneous imbibition experiments were conducted for each of the core samples using brine, anionic friction reducer fluid, and brine again. The core sample water permeability before and after the imbibition experiment was measured using a constant rate steady-state permeability apparatus.The polymer adsorption from the spontaneously imbibed fracturing fluid significantly reduced the brine spontaneous imbibition volumes in tight sand samples and in shale samples, though to a lesser degree. Moreover, the effective water permeability was decreased because of the polymer adsorption effect. Therefore, the polymer adsorption during hydraulic fracturing reduces the fluid leak-off into the formation and also the fluid flowback.The nonionic surfactant increased the fluid spontaneous imbibition volumes in both tight sand and shale samples. Thus, adding a nonionic surfactant to the friction reducer pad fluid during hydraulic fracturing leads to enhance both of the fluid leak-off and fluid flowback. The results also showed that the effect of polymer adsorption on the imbibition rates is less when the rock-fluid contact surface is parallel to the bedding plane.The imbibition potentials and imbibition capillary pressure curves were calculated before and after polymer adsorption. The polymer adsorption led to a slight increase in the capillary pressure; moreover, the tight sand samples had higher capillary pressure than the shale samples. The imbibition water relative permeability curves were calculated using ECLIPSE commercial simulator. The polymer adsorption significantly reduces the water relative permeability curves for tight sand samples and in less degree for shale samples.

Screening of inhibitors for remediation of asphaltene deposits: Experimental and modeling study

Abstract One of the most severe problems during production from heavy crude oil reservoirs is the formation of asphaltene precipitation and as a result deposition in the tubing, surface facilities and near wellbore region which causes oil production and permeability reduction in addition to rock wettability alteration in the reservoir. So one of the economical ways to prevent such incidents is using the chemicals which are called asphaltene inhibitor. In this study, the influence of three commercial inhibitors, namely; Cetyl Terimethyl Ammonium Bromide (CTAB), Sodium Dodecyl Sulfate (SDS), Triton X-100 and four non-commercial (Benzene, Benzoic Acid, Salicylic Acid, Naphthalene) inhibitors on two Iranian crude oils were investigated. This study extends previous works and contributes toward the better understanding of interactions between asphaltene and inhibitor. Effect of functional groups and structure of inhibitors on asphaltene precipitation were studied and it seems clear that the nature and polarity of asphaltene (structure and amount of impurities presented) has a significant impact on the selection of inhibitors. asphaltene dispersant tests and Core flood tests were designed for evaluation of inhibitors in static and dynamic conditions. The results revealed distinguished mechanisms for asphaltene solubilization/dispersion (such as hydrogen bonding, π–π interaction and acid-base interaction) and influence of additional side group (OH) on inhibition power of inhibitor. During the experiments, it was found that increasing inhibitor concentration may lead to the self-assembly of inhibitor and declining of asphaltene stabilization. So, finding optimum concentration of inhibitor with high efficiency and available at a reasonable price is very important. The results suggest that 600 ppm of CTAB and 300 ppm of SDS were approximately optimum concentrations for the studied crude oils. One of the most important findings that differ from previous studies is the revelation of the mechanism behind the SDS/asphaltene behavior in various concentrations of inhibitor. Effect of chosen inhibitors on asphaltene precipitation and consequently deposition in porous media was studied, and then experimental data were modeled for evaluation of permeability impairment mechanisms. Permeability revived after inhibitor squeezing and cake formation mechanism played an important role in permeability reduction before and after treatment in porous media. The findings can also be applied to prediction of future behavior of reservoirs in oil field scale and evaluation of formation damage in the different period of production if needed any treatment process.

Systematic evaluation of asphaltene formation damage of black oil reservoir fluid from Lake Maracaibo, Venezuela

One of the most concerning areas for asphaltene deposition is the near-wellbore region, where such deposition may cause formation damage. The reservoir fluid of the Lake Maracaibo region is known to cause operational problems such as production losses due to asphaltene deposition. In this paper, we focus on the systematic evaluation of the asphaltene formation damage using stacked composite core samples and live oil samples from Lake Maracaibo area and study the formation damage due to asphaltene deposition inside the composite core stack.A special coreflood system was designed for an asphaltene formation damage study using reservoir core samples and sour–live reservoir fluid samples. The phenomenon of asphaltene precipitation and deposition in porous media and subsequent permeability impairment was evaluated while the fluid pressure decreased below the asphaltene onset pressure (AOP). Live fluid samples were collected and flooded through the stacked composite core plugs under reservoir conditions. Progressive pressure reductions were performed to induce asphaltene precipitation and deposition in the composite core. Changes in the absolute permeability of the composite core assembly due to asphaltene precipitation and deposition were calculated in the context of the pressure depletion process. Significant permeability impairment occurred from the depressurization of the reservoir fluid below the AOP. The upstream inlet pressure of the composite core stack was maintained just above the AOP while the outlet pressure was regulated approximately 50 psig above the saturation pressure throughout the coreflood experiment so that the onset of asphaltene precipitation occurred along the length of the composite core.Following the coreflood experiment, the core stack was depressurized and the remaining fluid was extracted from individual core plugs. Various analytical techniques such as asphaltene content measurement, simulated distillation and optical density were used to perform detailed post-trial analyses of the residual fluids extracted from each individual core plugs. Analyses of the thin sections extracted from various core plugs were also performed to investigate the microstructure of the residual hydrocarbon as well as the distribution of the flow pathways plugged with asphaltene aggregates in the pore structures. The results associated with these post-trial analyses confirmed that the observed permeability impairment was indeed due to the plugging of the flow pathways of the core plugs by asphaltene aggregates, and that the asphaltene-induced permeability loss was somewhat more extensive in the tighter plugs associated with the stacked core assembly. We present the systematic approach to perform asphaltene formation damage study using composite core and live reservoir fluid samples above the saturation pressure.

Technology Focus: Formation Damage (February 2017)

Technology Focus In a corresponding article from 2015, I quoted the title of Brant Bennion’s 1999 article “Formation Damage—The Impairment of the Invisible, by the Inevitable and Uncontrollable, Resulting in an Indeterminate Reduction of the Unquantifiable.” I would like to think that, given the considerable effort spent on drilling- and completion-fluid development since the article was written, we have a much better control of the “inevitable and uncontrollable.” Likewise, with respect to a “reduction in the unquantifiable,” much of the uncertainty can be minimized by performing representative corefloods using plugs of different permeability value to reflect the values expected downhole. It is permeability that is often the most difficult to quantify; therefore, focusing on permeabilities in coreflooding to cover the span of those likely to be encountered can improve our understanding of the potential formation damage that could be expected. In this short article, I would like to focus on “the impairment of the invisible” because it is here that the greatest uncertainty exists with regard to formation-damage evaluation. One of the challenges for those involved with understanding an unexpected decline in well performance is identifying the exact causes for the reduced productivity because we cannot see downhole what type of damage has occurred and where. Production engineers can use significant amounts of time in attempting to identify a cause for poor productivity. This process involves evaluating all that has happened in the well, which includes the fluids used, losses during drilling and completion, lower-completion type and potential for plugging, and how effective well cleanup was. Consideration of all data available can eventually point toward one factor that could explain productivity decline. Core-flooding can also be used to simulate the sequences performed in the well, to try to identify the damaging mechanism. Regardless of those factors, the key take-home message is that prevention is much better than cure. Recommended additional reading at OnePetro: www.onepetro.org. SPE 178963 Laboratory Simulation and Damage in Openhole Water Injectors by Michael Byrne, LR Senergy, et al. SPE 178018 Evaluation of Damage Mechanisms in Tight Gas Reservoirs: Field Example From Perth Basin by Nick Bahrami, SGS Netherlands, et al. SPE 179007 Ability of a Filter-Cake Breaker To Diffuse Into Completion Brine and Packed Gravel by Clotaire-Marie Eyaa Allogo, Schlumberger, et al.

Formation Damage Evaluation of Produced Water ReInjection Using an Advanced Software in Vertical and Horizontal Wells

Formation Damage Evaluation of Produced Water ReInjection Using an Advanced Software in Vertical and Horizontal Wells

Apparent Permeability and Gas Flow Behavior in Carboniferous Shale from the Qaidam Basin, China: An Experimental Study

Shale can act as an unconventional gas reservoir with low permeability and complex seepage characteristics. Study of the apparent permeability and percolation behavior of shale gas is important in understanding the permeability of shale reservoirs, to evaluate formation damage, to develop gas reservoirs, and to design wells. This study simulated methane percolation at 298.15 K under inlet pressures ranging from 0.2 to 4 MPa and a constant outlet pressure of 0.1 MPa to investigate shale gas percolation behavior and apparent permeability. Five representative shale cores from the Carboniferous Hurleg and Huitoutala formations in the eastern Qaidam Basin, China, were analyzed. Each experiment measured the volume flow rate of methane and the inlet pressure. Pseudopressure approach was used to analyze high-velocity flow in shale samples, and apparent permeability at different pressures was calculated using the traditional method. A nonlinear apparent permeability model that considers diffusion and slippage is established from theory and experimental data fitting, and the shale gas flow characteristics affected by slippage and diffusion are analyzed. The results indicate that the pseudopressure formulation that considers the effect of gas properties on high-velocity flow produces a more accurate linear representation of the experimental data. The apparent gas permeability of shale consists of contributions from Darcy permeability, slippage, and diffusion. The apparent permeability and gas flow behavior in the studied shales strongly depended on pressure. The diffusion contribution increased greatly as pressure decreased from 2 to 0.2 MPa, and the smaller the shale permeability, the greater the relative contribution of diffusion flow. At pressures greater than 2 MPa, slip flow contributes $$\sim $$ 20% of the total flux, Darcy flow contributes up to 70%, and diffusion makes only a minor contribution. This study provides useful information for future studies of the mechanism of shale gas percolation and the exploration and development of Qaidam Basin shale gas specifically.

Formation damage during alkaline-surfactant-polymer flooding in the Sanan-5 block of the Daqing Oilfield, China

Alkaline-Surfactant-Polymer (ASP) flooding is an emerging chemical Enhanced Oil Recovery (EOR) technology which has significantly enhanced oil recovery of Daqing Oilfield. ASP flooding benefits from the synergy effects of alkali, surfactant and polymer to improve both volumetric and displacement efficiencies and meanwhile lower surfactant adsorption. However, ASP flooding also induces some negative formation damage effects such as scaling, adsorption, and mineral dissolution. In this paper, we investigated the formation damage caused during ASP flooding in Block Sanan-5 in Songliao Basin – one of the most productive blocks of Daqing Oilfield in China.It was found that the distribution of formation damage caused by ASP flooding followed flow paths of chemical solutions and was dependent on well locations. The severity of damage varies as distance increases from the near-injection-well area to the near-production-well area. Understanding the effects of well locations on formation damage during ASP flooding could provide more accurate evaluation of formation damage and helped to guide reservoir development strategies. To analyze the well location factor, we collected scaling samples and more than 970 m of core samples from Block Sanan-5 of Daqing Oilfield covering different wells on various flow paths before and after ASP flooding. The changes of some key petrophysical parameters such as porosity and permeability before and after ASP flooding were investigated. A series of experiments, including Scanning Electron Microscopy (SEM), Casting Thin Sections (CTS), X-Ray Diffraction (XRD) and ion analysis of produced water were performed to test properties of core samples. In addition, absorption of different components in the ASP solutions was also measured.Experimental results indicate that the ASP flooding has considerably different influences on different parts of flow paths. After ASP flooding, permeability distribution of core samples exhibits different variability trends from the near-injection-well areas to near-production-well areas. Due to absorption of alkali and polymer, grains migration and scaling of calcium and magnesium, permeability decreases at the near-injection-well area, then increases at an intermediate distance and decreases again at the near-production-well. Moreover, porosity of samples shows a similar tendency with variability of permeability, which is interpreted by the strong mineral corrosion due to high concentration of alkali in the near-wellbore area, while its extent of variation is smaller than permeability.

Study on the model of contaminant ions reaction and diffusion near wellbore

During the development of oil field, well operation fluids will inevitably invade the formation, and insoluble is produced when contaminant ions contained in operation fluids react with formation fluids, which will easily plugs the pores, consequently affecting the flow of formation fluids. It is of remarkable significance for formation damage evaluation to study the laws of contaminant ions transportation and distribution near wellbore. In this study, the characteristics of highspeed percolation and contaminant ions diffusion near wellbore are reasonably considered, and then we established the non-Darcy flow reaction-diffusion equations, from which the contaminant ions distribution and transportation will be illustrated, thereby, the effects of pollutants migration and reaction on porosity and permeability are further studied. Thus, the newly developed model can provide theoretical basis and practical reference for plug removal.

Comprehensive evaluation of formation damage induced by working fluid loss in fractured tight gas reservoir

Western Sichuan tight gas reservoir is characteristic of developed natural fractures and ultra low matrix permeability. Developed fracture is beneficial for the economic and efficient development of tight gas reservoir. But it will lead to lost circulation of working fluid and induce formation damage. Lost circulation has frequently occurred during drill-in, completion and test process. Formation damage degree and damage range are the key indexes for the formation damage evaluation. To our best knowledge, few papers have been published on the comprehensive consideration of the above two indexes. In this paper, we conduct laboratory experiments and develop a mathematical model to evaluate the formation damage degree and determine the formation damage range. Based on the study results a formation damage pattern is established to analyze the mechanism and process of the formation damage induced by working fluid loss. The study results show that the average formation damage degree induced by drill-in fluid loss is 68.51% and increases to 78.70% when the kill fluid loss damage is taken into consideration. The radius of formation damage zone induced by working fluid loss is 15.8 m. The formation damage pattern is as follows: First the loss of drill-in fluid induces serious formation damage including sensitive damage, particle plugging and water phase trapping. Then the subsequent loss of kill fluid in the process of completion and test further aggravates the formation damage degree. Finally in the acidizing treatment the acidizing radius cannot exceed the damage zone radius so that the formation damage cannot be completely removed. The comprehensive evaluation and pattern of formation damage are necessary for designing reasonable reservoir protection and damage removal measures for the fractured tight gas reservoir.

Evaluation of damage to horizontal wells through equivalent horizontal well length

Abstract The skin factor and additional pressure drop which are used to evaluate the formation damage of vertical wells can not accurately be applied to horizontal wells. A new model for evaluating formation damage of horizontal wells is presented. This method is derived by utilizing and modifying the concept of equivalent horizontal well length presented by Malekzadeh, where the permeability anisotropy is considered and a new calculation method of the equivalent productivity ratio is proposed. The results show that for a damaged horizontal well, the equivalent horizontal well length is shorter than the completed horizontal interval, while for a stimulated horizontal well the equivalent horizontal well length is longer than the completed horizontal interval. The fact that the longer the horizontal well is, the smaller the equivalent vertical well skin factor indicates that the horizontal well is more advanced than the vertical well in oilfield development. A longer horizontal well is more subjected to productivity loss when the well is damaged and it is more productive after stimulation. The application in the Bohai Oilfield indicates that the new method can directly and efficiently determine the magnitude of formation damage around horizontal wells and its impaction on productivity. It also sheds light on reservoir development and its evaluation standard.

Evaluation and prevention of formation damage in offshore sandstone reservoirs in China

Reduction in water injectivity would be harmful to the waterflood development of offshore sandstone oil reservoirs. In this paper the magnitude of formation damage during water injection was evaluated by analyzing the performance of water injection in the Bohai offshore oilfield, China. Two parameters, permeability reduction and rate of wellhead pressure rise, were proposed to evaluate the formation damage around injection wells. The pressure performance curve could be divided into three stages with different characteristics. Analysis of field data shows that formation damage caused by water injection was severe in some wells in the Bohai offshore oilfield, China. In the laboratory, the content of clay minerals in reservoir rock was analyzed and sensitivity tests (including sensitivity to water, flow rate, alkali, salt and acid) were also conducted. Experimental results show that the reservoir had a strong to medium sensitivity to water (i.e. clay swelling) and a strong to medium sensitivity to flow rate, which may cause formation damage. For formation damage prevention, three injection schemes of clay stabilizer (CS) were studied, i.e. continuous injection of low concentration CS (CI), slug injection of high concentration CS (SI), and slug injection of high concentration CS followed by continuous injection of low concentration CS (SI-CI). Core flooding experiments show that SI-CI is an effective scheme to prevent formation damage and is recommended for the sandstone oil reservoirs in the Bohai offshore oilfield during water injection.

A new laboratory method for evaluating formation damage in fractured carbonate reservoirs

Natural carbonate core samples with artificial fractures are often used to evaluate the damage of fractured carbonate formations in the laboratory. It is shown that the most frequent error for evaluation results directly from the random width characterized by the artificial fractures. To solve this problem, a series of simulated fractured core samples made of stainless steel with a given width of fracture were prepared. The relative error for the width of artificial fracture decreased to 1%. The width of natural and artificial fractures in carbonate reservoirs can be estimated by image log data. A series of tests for formation damage were conducted by using the stainless steel simulated core samples flushed with different drilling fluids, such as the sulfonate/polymer drill-in fluid and the solids-free drill-in fluid with or without ideal packing bridging materials. Based on the experimental results using this kind of simulated cores, a novel approach to the damage control of fractured carbonate reservoirs was presented. The effective temporary plugging ring on the end face of the simulated core sample can be observed clearly. The experimental results also show that the stainless steel simulated cores made it possible to visualize the solids and filtrate invasion.