RESERVOIR DEFORMATION DURING OIL PRODUCTION

Introduction

Formation damage is an unfavorable operational and financial issue that can arise throughout the various stages of oil and gas recovery from underground reservoirs, including as production, drilling, hydraulic fracturing, and workover operations. Assessment, management, and rehabilitation of formation damage are among the most critical challenges to be tackled for effective hydrocarbon reservoir utilization. Permeability impairment, skin damage, and a decline in well performance are all symptoms of formation damage [1].

Formation damage is not always reversible, according to Porter (1989) and Mungan (1989). As a result, it is preferable to minimize formation damage rather than attempting to restore formation permeability using costly procedures that have a low success rate in many circumstances. Understanding, avoiding and/or regulating formation deterioration in oil and gas bearing formations requires the development of experimental and analytical methodologies. Laboratory investigations are crucial in gaining a better understanding of the physical foundation of formation damage. Realistic models that allow extrapolation outside the scaleable range can be built using this experimental foundation.

Current history matching methodologies for reservoir characterisation do not account for changes in reservoir formation features throughout petroleum production [1]. In actuality, formation features fluctuate, and a formation damage model can assist in incorporating this variation into the history matching process for correct characterisation of reservoir systems and, as a result, accurate future performance prediction.

When a reservoir of oil or gas is discovered under the ground, and reservoir engineers and drilling engineers are employed to tap that reservoir, often, they inadvertently amage it. Formation damage is an undesirable operational and economic problem that can occur during the various phases of oil and gas recovery from subsurface reservoirs including production, drilling, stimulation techniques and work over operations. The formation of a reservoir can be damaged by unforeseen rock, fluid, particle interactions etc and alterations caused by reservoir fluid, flow, and stress conditions. For example, the chemicals that the engineers have injected into the reservoir, the drilling mud used in drilling, or even by stress from the drill bit itself may cause formation damage. Control and remediation of formation damage are among the most important issues to be resolved for efficient exploitation of petroleum reservoirs and cost management. Formation damage seems to be inevitable and whether formation damage can be prevented, removed economically, or must be accepted as the price for drilling and producing a well will depend upon many factors.

In this research a general characteristics of formation damage during various stages of oil exploration are discussed.

1. Formation Damage in Oil and Gas Wells

Formation damage can occur at any time during a well’s history from the initial drilling and completion of a wellbore through depletion of a reservoir by production. Operations such as drilling, completion, workovers and stimulations, which expose the formation to a foreign fluid, may result in formation damage due to adverse wellbore fluid/formation fluid or wellbore fluid/formation reactions. When a well is producing below its optimum productivity, the source of the problem must be identified before corrective measures can be taken. In some instances, a systematic study of the entire producing system may be required. If formation damage is suspected to the cause of a well’s low productivity, there are many techniques available to evaluate a well in order to identify this problem.

Figure 1. Major Formation Damage Mechanism Associated with Fluid Invasion due to Borehole Filtration [2]

For many years the drilling industry focuses on practices, which gave high rates of penetration and minimum wellbore problems. The cementing industry focuses most of the time on designing slurries, which will not bridge up or prematurely set within the casing. As a consequence, drilling and cementing fluids were often formulated to drill and cement the well cheaply and quickly with little thought of the impact on well productivity. Drilling department focus the design of drilling fluid on volume and cost minimization. For the cementing operation, special care is given for reducing additive and spacer pre flush usage. The production department has to deal with maximizing production. These objectives are very often not complementary and even sometimes opposite [3].

1.1 Formation Damage during Drilling

Drilling is the first instance, in the life of a well, of formation damage. It is the first well operation, which brings formation in contact with foreign material. The formation is exposed to drill bit and drilling mud during drilling operations. To overcome inflow of formation fluid and to lay down a thin, low permeability filter cake on the walls of the hole, the pressure of the drilling mud column must exceed the pore pressure by at least 200psi [4]. The horizontal drilling requires more concern for formation damage, as it makes the formation to be exposed to mud for longer period requiring more time drilling within the targeted productive formation than do vertical wells. Under pressured reservoirs are also significantly more susceptible to formation damage.

Figure 2. Drilling Process (From ONGC Data Files)

Figure 3. Drilling Damage (From ONGC Data Files)

1.2 Formation Damage during Completion & Workover Operations

Poor completion and workover fluids and practices may cause considerable damage to a formation long after the formation was drilled, cemented and perforated. Many forces tend to change the natural virgin permeability of producing formation during initial completion and or workover operations.

Perforating

Perforating process initiates the flow of formation fluid to the wellbore. Perforations are the entry point from the formation to the wellbore, and all flow in a cased, perforated completion must pass through these tunnels. Negligence during perforation may lead to formation damage. Anytime that formation damage is suspected the perforation should be examined first. The overbalance/under balance, perforation diameter, perforation penetration, penetration density etc all should be adequately given attention [5].

Workover

The workover process makes the wellbore condition more or less like the drilling condition. The loss of filtrate and the fluid particle invasion may lead to formation damage and therefore care should be paid during workover operation to avoid the damage.

Figure 4. Damage during Perforation due to Overbalance (From ONGC Data Files)

1.3. Formation Damage Due to Acidizing

Acid reactions can produce several side effects which can decrease formation permeability. During acid treatment following mechanisms are responsible for formation damage.

1. Fines migration
2. Reaction and precipitation
3. Sludge formation
4. Emulsion formation
5. Wettability alteration
6. Water block
7. Iron ion precipitation

Acids used in Well Stimulation [3], Inorganic, organic and combinations of acids along with surfactants are used in a variety of well stimulation treatments.The basic types of acid used are: Hydrochloric, Hydrochloric –Hydrofluoric, Acetic, Formic and Sulfamic. Also various combinations of these acids are employed in specific applications. HCl acid used in the field is normally 15% by weight; however acid concentration may vary between 5% and about 35%. HCl will dissolve limestone, dolomite and other carbonates.

1.4. Formation Damage during Fracture Treatment

Hydraulic fracturing is the creation of highly conductive path in the reservoir, which connects far reservoir with wellbore and allows the untapped hydrocarbon to flow into the well. Damage resulting from hydraulic fracturing takes two distinct forms: damage inside the fracture itself (proppant –pack damage) and damage normal to the fracture intruding into the reservoir (fracture-face damage). The first generally occurs because of inadequate breaking of the fracturing fluid polymer, the second occurs because of excessive leak off. Depending on the reservoir permeability, the impact of these two damages varies. For low reservoir permeability neither one is much of a factor. As the permeability increases, proppant –pack damage becomes increasingly important, whereas damage to the reservoir face is relatively unimportant. At high permeability, both are important, with fracture-face damage dominating at very high permeability. The selection of fracturing fluids, polymer concentrations and breakers is critical in addressing these issues. Incomplete breaking of the polymers in fracturing fluid is the most obvious cause of damage within hydraulic fractures, as well as the poor selection of proppant fracturing fluids and formation rock creeping into the proppant pack. True damage in the formation rock is the consequence of excessive leak off in high permeability reservoirs when polymer-base gels are used in combination with inefficient fluid loss agents.

1.5. Formation Damage Expert System

Development and application of knowledge and simulator-based expert systems for diagnosis, analysis, and mitigation of various formation damage and restoration processes are of continuing interest to the petroleum industry. Formation damage occurs by many processes in complicated manners that are not yet fully understood. Efforts are being made to understand and theoretically describe the governing processes. Quantitative determination of the various theoretical parameters at near in situ conditions will take a long time. Modeling of various formation damage processes is an ongoing process for the petroleum industry. Therefore, a truly useful formation damage advisor and expert program is a dream to accomplish in the future. However, companies and research institutions are developing proprietary expert systems with emphasis on certain specific applications.

Concerns for formation damage have been with our industry from the early days. In the past, numerous experimental and theoretical studies have been carried out for the purpose of understanding the factors and mechanisms that govern the phenomena involving formation damage. Although various results were obtained from these studies, a unified theory and approach still does not exist. Modelling formation damage in petroleum reservoirs has been of continuing interest. Although many models have been proposed, these models do not have the general applicability. However, an examination of the various modeling approaches reveals that these models share a common ground and, therefore, a general model can be developed, from which these models can be derived.

Glen et al., 1952 [6] discussed the various factors affecting well productivity. Mungan in1965 [7] conducted experiments to examine the role of pH and salinity changes in core damage. He concluded that the primary cause of permeability reduction was blocking of the pore passages by dispersed particles. Permeability reduction due to salinity changes occurred regardless of the type of clay. Cores that were essentially free of clays were damaged by flow of acidic or alkaline solutions. Yassin in 1980 [8] in his research report discussed formation damage during drilling and completion operations. Groesbeck et al.,1982 [9] conducted an experimental study to determine entrainment and redeposition of naturally occurring fine particles in porous media. They have shown that fines entrainment and redeposition are mechanisms that can cause abnormal productivity decline and are phenomena restricted to the near-well bore region. Gabriel et al., 1983 [10] conducted an experimental study to comprehensively analyze both the chemical and mechanical interactions. In linear core tests, the flow of a chemically compatible, wetting fluid resulted in severe permeability loss when the fluid velocity exceeded a critical value. The flow of chemically incompatible, wetting fluid resulted in a total loss of permeability, which exhibited no dependency on fluid velocity. Baghdiklan et al., 1989 [11] investigated the transient behavior of particulate plugging of porous media. Experiments included injection of clay suspensions under different conditions into sand packs, measurement of pore size distribution, and monitoring of permeability and effluent particle concentration. Permeability reduction occurred more rapidly as the pH decreased and the ionic strength increased. In addition, for bentonite, permeability reduction increased as the clay concentration increased. Kwan et al., 1989 [12] investigated permeability impairment due to the fines migrating in extracted core material from the Clearwater formation of Cold Lake, Alberta. Todd et al., 1990 [13] investigated the influence of core-plug preparation of particle invasion, the effects of particle penetration, flow rate and particle concentration on formation damage and depth of invasion characteristics rather than overall permeability variation. Dahab et al., 1992 [14] experimentally investigated the relative permeability reduction due to the difference in salinity between connate and injected brines in cores having different lithology. The effect of temperature and pressure on relative permeability was also investigated. Formation damage, due to incompatibility between formation and injected water–water salinities, decreased oil and brine relative permeability, increased residual saturation’s and decreased oil recovery. Shock effects of sudden water injection resulted in an increase in formation damage. Rising temperature decreased the degree of permeability reduction, while pressure had a slight effect on formation damage. Eleri et al., 1992 [15] conducted an experimental study of more than 17 core plugs involving 25 linear runs. Their purpose was to study the different physical and mechanical aspects of the processes leading to formation damage caused by movement and entrapment of suspended particles. Particle movement through porous media was not just a function of pore and particle size but depended also upon the initial flow rate and the linear velocities attained within the porous medium. The results of their study have indicated that significant permeability impairment can be caused by suspended particles in the injection water, even in very dilute solutions. Pang et al., 1994 [16] have predicted the injectivity decline in wells with various types of completions such as perforated, gravel packed and fractured wells. Feliciano et al.,1995[17] presented a report which summarizes studies conducted to improve the control techniques and prevention of formation damage particularly in the area of organic deposition and focuses on problems related to near wellbore permeability changes around injection or production wells during secondary and tertiary oil production operations. Experiments were conducted to evaluate the effectiveness of commercially available paraffin treatment chemicals to remove paraffin related formation damage. Bennion et al.,1996 [18] discussed the various types of formation damage common to horizontal wells, such as fluid–fluid and fluid–rock incompatibilities, solid invasion, effect of overbalance pressure, aqueous phase trapping, chemical adsorption, wettability alteration, microbiological activity and fines migration. Laboratory testing of fluids and representative core samples was highlighted as a potential diagnostic tool to select the optimum fluids for drilling, completion, and stimulation and work-over treatments. Zhang et al.,1997 [19] presented a new method for formation damage characterization based on a constant head hydraulic solution which considers formation alteration effects. The solution uses a power permeability model to simulate the effect of formation damage. Jack et al.,1998 [20] evaluated the formation damage due to frac stimulation of Saudi Arabian reservoirs and presents a case study of a stimulation scenario demonstrating the potential pitfalls that were avoided by an integrated study effort using petrophysical and mineralogical data. Bagei et al., 2000 [21] conducted a study to determine the formation damage in limestone reservoirs and its effects on production. Also the role pH in promoting formation damage is discussed. High pH promotes formation damage by particle deposition within the porous media and consequently particle plugging at the pore throats. Permeability reduction is used as the quantitative measure of formation damage. Jilani et al., 2002 [22] investigated the influence of overbalance pressure on formation damage during drilling operations. An innovative ultrasonic method was employed to measure the mud invasion depth and observed that mud invasion depth decreases with increasing overbalance pressure until it reaches a critical pressure. Beyond that invasion depth increases with overbalance pressure. Andreas et al., 2010 [23] studied the permeability alterations adjacent to the newly created fracture face. Sbai et al., 2011 [24] developed a finite volume simulator to predict the injectivity decline near CO2 injection wells and also for production wells in the context of enhanced oil recovery.

Conclusion

Formation damage is an exciting, challenging, and evolving field of research. It is an undesirable operational and economic problem that can occur during the various phases of oil and gas recovery from subsurface reservoirs including production, drilling, hydraulic fracturing, and workover operations. Formation damage assessment, control, and remediation are among the most important issues to be resolved for efficient exploitation of hydrocarbon reservoirs.

Such damage is caused by various adverse processes, including chemical, physical, biological, and thermal interactions of formation and fluids, and deformation of formation under stress and fluid shear. Formation damage indicators include permeability impairment, skin damage, and decrease of well performance. The properly designed experimental and analytical techniques can help understanding, diagnosis, evaluation, prevention and controlling of formation damage in oil and gas reservoirs.

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