Reservoir Formation Damage Episode 2 Part 10 pot

Laboratory Evaluation of Formation Damage 457 bearing formations under actual scenarios of field operations, and for evaluation of techniques for restoration and stimulation of damaged formations are essential for efficient exploitation of petroleum reservoirs. Experimental systems and procedures should be designed to extract meaningful and accurate experimental data. The data should be suitable for use with the available analytical interpretation methods. This is important to develop reliable empirical correlations, verify mathematical models, identify the governing mechanisms, and determine the relevant parameters. These are then used to develop optimal strategies to mitigate the adverse processes leading to formation damage during reservoir exploitation. As expressed by Thomas et al. (1998): Laboratory testing is a critical component of the diagnostic pro- cedure followed to characterize the damage. To properly char- acterize the formation damage, a complete history of the well is necessary. Every phase, from drilling to production and injection, must be evaluated. Sources of damage include drilling, cementing, perforating, completion and workover, gravel packing, production, stimulation, and injection operations. A knowledge of each source is essential. For example, oil-based drilling mud may cause emulsion or wettability changes, and cementing may result in scale formation in the immediate wellbore area from pH changes. Drilling damage in horizontal wells can be very high because of the long exposure time during drilling (mud damage and the mechanical action of the drill pipe on the formation face); thus, the well's history may indicate several potential sources and types of damage. For meaningful formation damage characterization, laboratory core flow tests should be conducted under certain conditions (Porter, 1989; Mungan, 1989): 1. Samples of actual fluids and formation rocks and all potential rock- fluid interactions should be considered. 2. Laboratory tests should be designed in view of the conditions of all field operations, including drilling, completion, stimulation, and present and future oil and gas recovery strategies and techniques. 3. The ionic compositions of the brines used in laboratory tests should be the same as the formation brines and injection brines involving the field operations. 4. Cores from oil reservoir should be unextracted to preserve their native residual oil states. This is important because Mungan (1989) says that "Crude oils, especially heavy and asphaltenic crudes, provide a built-in stabilizing 458 Reservoir Formation Damage effect for clays and fines in the reservoir, an effect that would be removed by extraction." Fundamental Processes of Formation Damage in Petroleum Reservoirs Formation damage in petroleum-bearing formation occurs by various mechanisms and/or processes, depending on the nature of the rock and fluids involved, and the in-situ conditions. The commonly occurring processes involving rock-fluid and fluid-fluid interactions and their affects on formation damage by various mechanisms have been reviewed by numerous studies, including Mungan (1989), Gruesbeck and Collins (1982), Khilar and Fogler (1983), Sharma and Yortsos (1987), Civan (1992, 1994, 1996), Wojtanowicz et al. (1987, 1988), Masikewich and Bennion (1999), and Doane et al. (1999). The fundamental processes causing formation damage can be classified as following: 1. Physico-chemical 2. Chemical 3. Hydrodynamic 4. Mechanical 5. Thermal 6. Biological Laboratory tests are designed to determine, understand and quantify the governing processes, their parameters, and dependency on the in- situ and various operational conditions, and their effect on formation damage. Laboratory tests help determine the relative contributions of various mechanisms to formation damage. For convenience, the frequently encountered formation damage mechanisms can be classified into two groups (Amaefule et al., 1988; Masikewich and Bennion, 1999): (1) fluid- fluid interactions and (2) fluid-rock interactions. The fluid-fluid inter- actions include: (a) emulsion blocking, (b) inorganic deposition, and (c) organic deposition. The fluid-rock interactions include: (a) mobiliza- tion, migration and deposition of in-situ fine particles, (b) invasion, migration and deposition of externally introduced fine particles, (c) altera- tion of particle and porous media properties by surface processes such as absorption, adsorption, wettability change, swelling, and (d) damage by other processes, such as counter-current imbibition, grinding and mashing of solids, and surface glazing that might occur during drilling of wells (Bennion and Thomas, 1994). Laboratory Evaluation of Formation Damage 459 Selection of Reservoir Compatible Fluids Figure 15-1 by Masikewich and Bennion (1999) outlines the typical information, tests and processes necessary for laboratory testing and optimal design, and selection of fluids for reservoir compatibility. Hence, Masikewich and Bennion (1999) classify the effort necessary for fluid testing and design into six steps: 1. Identification of the fluid and rock characteristics 2. Speculation of the potential formation damage mechanisms 3. Verification and quantification of the pertinent formation damage mechanisms by various tests 4. Investigation of the potential formation damage mitigation techniques 5. Development of the effective bridging systems to minimize and/or avoid fluids and fines invasion into porous media 6. Testing of candidate fluids for optimal selection Experimental Set-up for Formation Damage Testing The design of apparata for testing of reservoir core samples with fluids varies with specific objectives and applications. Typical testing systems include core holders, fluid reservoirs, pumps, flow meters, sample col- lectors, control systems for temperature, pressure or flow, and data acquisition systems. The degree of sophistication of the design of the core testing apparatus depends on the requirements of particular testing conditions and expectations. Figures 15-2, 15-3, and 15-4 by Doane et al. (1999) describe, respectively, the typical designs of a primitive system that operates at ambient laboratory temperature, and overbalanced and underbalanced core testing apparata that operate at reservoir temperature. High quality and specific purpose laboratory core testing facilities can be designed, constructed, and operated for various research, develop- ment, and service activities. Ready-made systems are also available in the market. The schematic drawing given in Figure 15-2 indicates that primitive core testing systems consist of a core holder, a pressure transducer controlling the pressure difference across the core, an annulus pump to apply an overburden pressure over the rubber slieve containing the core plug, a reservoir containing the testing fluid such as a drilling mud or filtrate, a displacement pump to pump the testing fluid into the core plug, and an effluent fluid collection container, such as a test tube. There is no temperature control on this system. It operates at ambient laboratory conditions. 460 Reservoir Formation Damage El H H H Q El a 0) c/) SI = s 03 Q. C -i Q. © Laboratory Evaluation of Formation Damage 461 Pressure Transducer Core Holder H Core •Vacuum Drilling Mud or Filtrate Displacement Pump I Fluid Collection <D Figure 15-2. Primitive drilling fluid evaluation system (after Doane et al., ©1999; reprinted by permission of the Canadian Institute of Mining, Metallurgy and Petroleum). The schematic drawing given in Figure 15-3 shows the elements of a typical overbalanced core testing apparatus. This system has been designed for core testing at near-in-situ temperature and stress conditions, although other features are similar to that of the primitive system shown in Figure 15-2. The schematic given in Figure 15-4 shows the elements of a typical underbalanced core testing apparatus, which also operates at near-in situ temperature and stress conditions. Special Purpose Core Holders Core flood tests can be conducted in one-dimensional linear (Figures 15-2, 15-3, and 15-4) and radial modes. Figures 15-5a-d by Saleh et al. (1997) show a schematic of typical radial flow models. Radial models (text continued on page 466) High Pressure N2 or Air Source Reservoir Fluid Source Vacuum To Annulus Pump Figure 15-3. Current reservoir condition fluid leak-off evaluation system (after Doane et al., ©1999; reprinted by permission of the Canadian Institute of Mining, Metallurgy and Petroleum). High Pressure N2 or Air Source Reservoir Fluid Source (at Pres) Vacuum H Constant Pressure Displacement Pump (@ Pdrc < Pres) Wet Test 1 Wet Test 2 To Annulus Pump o 3 o ^ m I o o O P P era Figure 15^4. Underbalanced reservoir condition fluid leak-off evaluation system (after Doane et al., ©1999; reprinted by permission of the Canadian Institute of Mining, Metallurgy and Petroleum). £ 464 Reservoir Formation Damage FIGURE is not to scale welded flanges with a rubber gasket (a) Berea core with a horizontal wellbore core holder can accommodate 3" diameter, piston with' 4 feet long cores double 0-rlng nof|2Oflta| we |, bore di am eter = 0.25" or 0.5" rubber gasket required to seal off the core faces Pr*Mur*R*guUtor (b) Figure 15-5. Systems for horizontal wellbore studies: (a) core holder design, (b) overall productivity evaluation, (c) overall injectivity evaluation, and (d) drilling fluid evaluation (reprinted from Journal of Petroleum Science and Engineering, Vol. 17, Saleh, S. T., Rustam, R., EI-Rabaa, W., and Islam, M. R., "Formation Damage Study with a Horizontal Wellbore Model, pp. 87- 99, ©1997; reprinted with permission from Elsevier Science). (c) Laboratory Evaluation of Formation Damage 465 Figure is not to scale _. _J Constant iBrjneB pressure I Brine Supply Reservoir Sma« annular clearanct allows Hula movement to production ports Collected brine (d) Collected Filtrate In graduated cylinders Figure 15-5 continued 466 Reservoir Formation Damage (text continued from page 461) better represent the effect of the converging or diverging flows in the near-wellbore formation. However, linear models are preferred for con- venience in testing and preparation of core samples. The majority of the core flow tests facilitate horizontal core plugs because the application of Darcy's law for horizontal flow does not include the gravity term and the analytical derivations used for inter- pretation of the experimental data is simplified. This approach provides reasonable accuracy for single-phase fluids flowing through small diameter core plugs. However, when multi-phase fluid systems with significantly different properties and paniculate suspensions are flown through the core plugs, an uneven distribution of fluids and/or suspended particles can occur over the cross-sectional areas of cores. This phenomenon compli- cates the solution of the equations necessary for interpretation of the experimental data. In particular, errors arise because, frequently, the transport phenomena occurring in core plugs are described as being one- dimensional along the cores. In order to alleviate this problem, it is more convenient to conduct core flow tests using vertical core plugs. Conse- quently, the gravity term is included in Darcy's law, but errors associated with uneven distribution of fluid properties over the cross-sectional area of the core plugs are avoided. Therefore, Cernansky and Siroky (1985) used a vertical core holder. The dimensions of the core plugs are important parameters and should be carefully selected to extract meaningful data. Typically 1 to 2 in (2.54 to 5.08 cm) diameter and 1 to 4 in (2.54 to 10.58 cm) long cores are used. The aspect ratio of a core plug is defined by the diameter-to-length ratio. Small diameter cores introduce more boundary effects near the cylindrical surface covered by the rubber slieve. This, in turn, introduces errors in model-assisted data interpretation and analysis when one- dimensional models are used, as frequently practiced in many applications for computational convenience and simplification purposes. On the other hand, short cores do not allow for sufficient distance for investigation of the effect of the precipitation and dissolution processes and depth of invasion (Fambrough and Newhouse, 1993; Gadiyar and Civan, 1992; Doane et al., 1999). Longer cores are required for measurement of sec- tional or spatial porosity and permeability alteration. As described by Doane et al. (1999), a number of special purpose core holders have been designed. Figure 15-6 shows a single core for which only the pressures at inlet and outlet ports can be measured. This type of system is usually used with small core plugs. It only yields core response, integrated over the core length. As shown in Figure 15-7, long cores equipped with intermediate pressure taps can provide information [...]... permission of the Canadian Institute of Mining, Metallurgy and Petroleum) 470 Reservoir Formation Damage Guidelines and Program for Laboratory Formation Damage Testing Recommended Practice for Laboratory Formation Damage Tests* Introduction The following procedure has been designed to provide a methodology for assessing formation damage in a variety of testing situations Consequently, it is not rigorous... Kerosene or inert mineral oil should be filtered to 0.45 micron Formation Brine Formation brine, if available, should be filtered to 0.45 micron at reservoir temperature Alternatively, simulated formation water (SFW) should be freshly prepared as discussed in Section "Simulated Formation Water," given above 474 Reservoir Formation Damage Crude Oil It is usual to use dead crude but since it may contain a... process Laboratory Procedures for Evaluation of Formation Damage Problems The laboratory procedures required for evaluation of common formation damage problems are described in this section according to Keelan Laboratory Evaluation of Formation Damage 479 Table 15-1 List of Elements to be Included in Report* Section Headings Date of issue Reporting authors Type of formation material used in tests Objectives... the residual oil from its original 0 .2 (Sw = 0.8) to about 0 .26 (Sw = 0.74) Hence, the line BB' shifts to the line CC" The permeability to water also decreases As a remedial action, Keelan and Koepf (1977) recommend treatments inferred by the capillary pressure equation: Pc = 2ocos0 (15-1) 10 20 30 40 50 60 70 80 WATER SATURATION:PER CENT PORE SPACE 90 100 Figure 15 -10 Effect of water block on relative... is applied and then formation brine is introduced and sufficient pressure is applied to ensure 100 % formation brine saturation (as determined by weighing) b If the samples have been cleaned by flowing solvents in a core holder ending with 100 % methanol saturation (as determined by effluent composition) then the methanol can be exchanged by miscible flooding with formation brine to 100 % water saturation... unconsolidated sands into the wellbore Laboratory Evaluation of Formation Damage 481 The Liquid Block Problem As explained in Figure 15 -10 by Keelan and Koepf (1977), "liquid block reduces effective permeability to the hydrocarbon." Before damage, the original mobile water saturation range in 0 .20 < Sw < 0.80 After extraneous water incompatible with the formation invades the porous media, the irreducible water... and the comparative suitability of duplicates must be made using expert judgement Laboratory Evaluation of Formation Damage 473 Plug Saturation 100 % saturation is defined as being within 2% of base saturation Saturation With Formation Brine Cleaned samples should initially be saturated with formation brine This may be achieved using one of the following methods as determined by the cleaning process... mud filtrate should be injected at the reservoir temperature through the core in the "wellbore to formation" direction at 1 ml/min and the pressure differential measured Completion Fluid Placement—Solids-Free Completion Fluid 10 pore volumes of the solids-free completion fluid should be injected through the core in the wellbore to formation direction at the static reservoir temperature The fluid should... the zone from which it is derived should be used; i.e formation brine or crude oil for an oil well and formation brine * Reproduced with permission of the Society of Petroleum Engineers from SPE 38154 paper by Marshall et al., 1997 SPE Laboratory Evaluation of Formation Damage 471 for a gas well (using gas as a lubricant may cause precipitation from formation brine inside the core) b Poorly preserved... encountered formation damage problems into four groups: 1 The blocking of pore channels by solids introduced by drilling or by completion, workover, or injection fluids, 2 Clay-water reaction that yields clay hydration and swelling, or clay particle dispersion and pore plugging by movement with produced or injected water, 3 Liquid block that normally is caused by extraneous water introduced into the formation . Metallurgy and Petroleum). 470 Reservoir Formation Damage Guidelines and Program for Laboratory Formation Damage Testing Recommended Practice for Laboratory Formation Damage Tests* Introduction The . on formation damage. Laboratory tests help determine the relative contributions of various mechanisms to formation damage. For convenience, the frequently encountered formation damage. fluid and rock characteristics 2. Speculation of the potential formation damage mechanisms 3. Verification and quantification of the pertinent formation damage mechanisms by various