Workover Fluids Research Articles

Experimental and modelling studies on static sag of solid weighting powders in Polysulfonate workover fluids at high temperature and high pressure

The solid weighting material in a high-density workover fluid is prone to static sag. Existing experimental methods cannot predict the parameters of the settling stability of workover fluids at high temperature and high pressure (HTHP). Therefore, in this study, static settlement experiments were carried out using a novel experimental setup. The experimental setup enables the measurement of the density profile of heavy workover fluids at HTHP. A multi-parameter correlation equation between the sag factor and particle diameter, particle density, base fluid density, workover fluid density and rheological parameters, aging time, temperature, and pressure was obtained using dimensional analysis and multivariate nonlinear regression methods. The results reveal that the settlement stability of the workover fluid decreases with the increase in temperature and pressure. Based on the multi-parameter correlation, the predicted and the measured values were compared and verified. The error between the predicted value and the measured value was within 5%. The average prediction error was 1.68%, and the maximum prediction error was 3.8%. These results reveal that the model proposed in this study can effectively predict the static sedimentation stability of the solid weighted Polysulfonate workover fluids. Furthermore, the proposed correlation can guide the properties adjustment of the workover fluids to achieve the required sag stability. This work provides a new approach to predict and control the sag stability of the solid weighted workover fluids.

Anti-aging and rheological behaviors, and supra-molecular structures in water for the composite of a biopolymer with nano-SiO2 applied in workover fluids of ultra-deep wells

A biological polymer S-657 (namely BLG) was compounded with nano-SiO2 to obtain a workover fluid thickener applied in ultra-deep wells. This composite system is expected to improve the thermal stability of single BLG in brines containing high salinities and multi-valent salts at high temperatures. The thickening properties of the unaged BLG/nano-SiO2 brines were slightly enhanced compared with the BLG brines. However, the anti-aging ability and the salt resistance of BLG could be reinforced significantly by the introduction of nano-SiO2 at 140 °C in brines with high salinities, especially in mixed brines containing mono- and multi-valent salts. After aging at the high temperature for the BLG/nano-SiO2 aqueous solution, stretched polymeric chain bundles and integrated aggregating structures complexed with nano-SiO2 were still observed by TEM, resulting in a significant enhancement of the thickening property. The compound of nano-SiO2 could keep the pseudoplastic and thixotropic performance of the BLG brines during the aged process at a high temperature. In contrast to the single BLG mixed brine, the viscoelastic property of the BLG/nano-SiO2 mixed brine was still remarkable after aging for 16 h at 140 °C.

Strength-enhanced nanocomposite foamed gel as a temporary wellbore plugging fluid: formulation design and working performance

When working over wells with low-pressure reservoirs, loss of workover fluids into the reservoirs has been a problem that must be resolved. To resolve this problem, on the basis of theoretical knowledge and application characteristics of foamed gels, we developed a strong, stable, nanocomposite foamed gel as a temporary plug. The gel has high stability and low density and exhibits low fluid loss compared with traditional workover fluids. The foamed gel comprises 0.5%wt to 0.7%wt partially hydrolyzed polyacrylamide, 1.4%wt foaming agent, 0.25%wt nanosilica, 0.03%wt to 0.05%wt metallic-ion crosslinking agent, and 0.02%wt deoxidant. The temporary plugging simulation experiment shows that, for the core with low permeability, pressure drawdown across cores under a 15 MPa positive pressure differential was less than 1.2 MPa in 60 min and the rate of filtration of fluid through the cores was almost zero. The result shows that the nanocomposite foam gel has a certain capacity for compression and a low filtration rate and can effectively plug reservoir rocks temporarily. Therefore, the prosed foamed gel offers good application prospects in preventing loss of workover fluids in low-pressure reservoirs.

Research on Protecting Formation Low-Damage Workover Fluid in Low Permeability Reservoir

During the workover treatment process, poorly compatible workover fluids infiltrating into reservoir could cause serious formation damage. To tackle the aformentioned issues, in this work, low-damage workover fluid was systematically studied. By investigating reservoir damage mechanisms, chemical property study, compatibility evaluation test and core flow test, we obtain three kinds of workover fluids suitable for different blocks in Nanpu oilfield. Attractively, JRYL workover fluid which contains antiswelling agents can effectively prevent water sensitivity, and the permeability recovery values of JRYL workover fluid to NP1-5 and PG2 core are 95.3% and 86.9%, respectively. JRYD workover fluid which contains antiswelling agents and anti-waterblocking agent can prevent both water sensitivity and water blocking damage, and the permeability recovery value of JRYD workover fluid to NP403X1 core is 89.4%. JRYJ workover fluid suitable for high pressure formation can prevent water sensitivity and water blocking damage, and the permeability recovery value of the JRYJ workover fluid to NP403X1 core is 95.1%. The actual field application in Nanpu oilfield indicates that these workover fluids can not only reduce the oil well recovery time after workover treatment, but also increase production recovery rate. These results display great potential to efficiently develop low permeability reservoirs.

High-Performance Brine Viscosifiers for High Temperatures

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 183964, “High-Performance Brine Viscosifiers for High Temperatures,” by Peter J. Boul, Suhaib Abdulquddos, and Carl J. Thaemlitz, Saudi Aramco, prepared for the 2017 SPE Middle East Oil and Gas Show and Conference, Manama, Bahrain, 6–9 March. The paper has not been peer reviewed. Many viscosifiers currently used in high-density solids-free reservoir drilling fluids (RDFs) and completion fluids (CFs) are incompatible with high-density brines or require the use of prohibitively expensive brines to achieve target densities. There is substantial commercial benefit to developing a brine viscosifier with a higher temperature tolerance than is currently offered. A supramolecular viscosifier package has been developed that uses noncovalent associations between additives to enhance the thermal resilience of divalent brine fluids. Static aging-test data indicate that the supramolecular viscosifier outperforms high-performance, commercially available starch/xanthan brine viscosifier. Background The exploitation of oil and gas reservoirs found at increasing depths and the development of horizontal and slimhole drilling have increased the demand for high-density solids-free RDFs, CFs, and workover fluids (WFs). The use of divalent brine-based drilling fluids and CFs in well sections with temperatures exceeding 260°F is limited because of degradation of the polymers used to viscosify the fluid and suspend drill cuttings. Effective drilling fluids have numerous functions in well construction. They must have the physical properties required to carry cuttings from beneath the drill bit up the annulus of the well for separation at the surface. They must also provide cooling for the bit and be able to reduce-friction between the drillstring and the formation being drilled. This must be accomplished without damaging the formation. The inflow of fluids or solids from the drilling mud can cause formation damage, which can reduce the rate of penetration during drilling and can also decrease the rate of hydrocarbon production from a producing well. RDFs, CFs, and WFs must be density-adjusted to provide the hydrostatic head to preserve the integrity of the wellbore walls and to prevent blowouts. Although drilling through much of the well can be accomplished with oil- or water-based fluids weighted by solid particles of such minerals as barite, the reservoir sections offer a different challenge because of the concern that these solids could plug pores in the formation and reduce hydrocarbon-flow rates. It is for this reason that operators look to brines to provide density in RDFs. Recently, research in nanomaterials has revealed the potential of low-solids nanofluids for the prevention of formation damage.

Piston-like plugging of fuzzy-ball workover fluids for controlling and killing lost circulation of gas wells

During well-killing operations for the workover of low-pressure gas wells, formation pressure should be balanced so as to guarantee well control safety by preventing natural gas overflow. In this paper, a laboratory evaluation was conducted with fuzzy-ball fluids as killing fluids. The results show that, the fuzzy-ball fluid, with a density of 0.5–1.5 g/cm3 and a viscosity up to 78,50,000 mPa·s at a low shear rate, realizes controllable performance and forms piston-like plugging slugs of solid-free high structural strength on natural gas wellbore after bonding. During well workover, multiple fluid column pressures were set up by injecting fuzzy-ball fluids with different densities at various rates. Owing to high structural strength of the fluids at a low shear rate, natural gas breaks through only inside the piston-like slug and cannot flow upwards to the ground, so the pathways of natural gas in the wellbore are isolated from the ground surface. Moreover, the fluid can wholly move up and down like a piston-like plug, with the change of formation pressures or the tripping of pipe strings. Like the conventional operations, the production can be restored after the workover, so long as the fluid in wellbore is cleaned by means of gas lift. In a natural gas field in NW China, where the formation pressure coefficient dropped to 0.60–0.82, three wells were fully filled with fuzzy-ball workover fluids for 7 days and another three wells were treated with the piston-like plugs of fuzzy-ball workover fluids for only 3 days. They all presented better technical results. The technology provides a new way for low-pressure gas well workover.

Characterization of terpolymers containing 1,2,4‐oxadiazolic pendant groups with potential application as workover fluids

AbstractPresence of planar, bulky heterocyclic pendant groups, attached to polymer chains, alters the thermal properties and, once gelled, they modify their rheological properties as well. The authors report generation of stiff gels coming from terpolymers containing 1,2,4‐oxadiazolic pendant groups, obtained by chemical modification of commercial polyacrylonitrile. The gels formed in basic aqueous solutions were compared and the effect of substituents linked to the heterocycles on thermal stability and viscoelastic properties was also analyzed. The structural modifications were followed by FTIR. The potential use of these terpolymers as workover fluids is discussed. © 2010 Wiley Periodicals, Inc. J Appl Polym Sci, 2011

Study on the Workover Fluid Formula and Performance of the Prevention Reservoir

In the workover treatment of Yakela condensate gas field, the workover fluids are easily leaked, and many problems such as clay expansion, rate sensitivity, migration of fines, and change of wetting property will occur, which will induce serious reservoir harms. In the article, the performances of the existing workover fluid of the Yakela condensate gas field with high temperature and high pressure are evaluated, and the influencing factors harming the reservoir are analyzed and obtained, and the effective measures and methods preventing the reservoir harm are confirmed. The technical principle, material composing, performance index, and the evaluation of stratum liquid compatibility are introduced in the article. The result of performance evaluation indicates that the core return permeability of the workover liquid system can achieve above 80%, and it is an ideal low-harm workover fluid system.

Polymer‐acid solutions: Their use for the enhancement of oil reservoir stimulation

AbstractA reduction in permeability occurring around the wellbore resulting from drilling, completion and/or workover fluids increases the flow resistance to the petroleum reservoir fluids and is defined as formation damage. Acidizing process removes near‐wellbore damage and enhances hydrocarbon production from producing wells. This study investigates the effect of adding polymer as a retarding agent to acid solutions to slow and control the reaction in matrix acidizing treatment of carbonate rocks. Two different polymers, polyacrylamide (PAA) and polysaccharide (xanthan) and two different acids, acetic acid and formic acid, were used through this study. The results revealed that the presence of PAA did not change the viscosity of the acid solution significantly, while the viscosity of xanthan‐acid solutions was decreased with increasing the acid concentration. Additionally, the reaction of polymer‐acid solutions with the rock material was monitored under microscope. Original rock samples obtained from Saudi reservoirs containing mainly carbonate were used in the reaction. The PAA‐acid solution did not show any decrease in the reaction rate compared to that of acid solution. Thus, the PAA solution applied in this study is not recommended as a retarder. However, xanthan‐acid solutions showed a significant decrease in the reaction time. Therefore, xanthan was selected to perform further investigations in Rotating Disk Reactor at different pressures. Scanning electronic microscopy (SEM) was conducted on pretreated and posttreated rock samples. This provides the opportunity to perform a detailed description of the rock surface and facilitates the identification of the changes occurring due to polymer‐acid treatment. © 2008 Wiley Periodicals, Inc. J Appl Polym Sci, 2008

Acid Stimulation of High-Temperature Sandstones in Eastern Venezuela

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 98318, "Effective Stimulation of High-Temperature Sandstone Formations in East Venezuela With a New Sandstone-Acidizing System," by S.A. Ali, SPE, and C.W. Pardo, SPE, Chevron Energy Technology Co., and Z. Xiao, SPE, F.E. Tuedor, SPE, A. Boucher, SPE, S.A. Al-Harthy, B. Lecerf, and G. Salamat, SPE, Schlumberger, prepared for the 2006 SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, 15–17 February. Wells in this eastern Venezuela oil field have a bottomhole temperature of approximately 230°F and varied mineralogical composition from interval to interval. Near-wellbore fines damage and carbonate-scale damage have been reported. A novel chemical system was developed to stimulate these high-temperature sandstone reservoirs. Introduction Most of the wells in this field in Maracaibo, Venezuela, have several perforated intervals covering up to 1,000 ft, with a net perforated interval of up to 500 ft. The mineralogy varies from interval to interval, with 4 to 16% calcium carbonate (CaCO3), 6 to 18% clays (mainly kaolinite), 5 to 10% feldspars, and 2 to 5% siderites in some wells. Reservoir pressures range from 800 to 2,500 psi, and skin values vary across the zones. Permeability varies from 1 to 200 md among the zones. The main formation-damage mechanisms were identified as fines migration (80 to 90% production decline after treatment) and CaCO3 scales, mainly from loss of workover fluids. Various formulations of mud acid, organic-clay acid, and solvents are used to treat these wells, with mixed results. The new sandstone-acidizing system was developed to treat multilayered high-temperature (200 to 375°F) reservoirs with long production intervals and complex mineralogy. The new sandstone-acidizing fluid uses a single-stage placement process, has less precipitation tendency and reduced tubular and production-equipment corrosion, and reduces exposure of hazardous fluids to wellsite personnel and the environment. A comprehensive laboratory study, which included acid-solubility tests, X-ray diffraction (XRD) analysis, batch reaction kinetics, fines-migration tests, and core-flow tests, was conducted on field cores to evaluate the performance of this sandstone-acidizing system and compare it with currently used systems. Experiment Twelve core plugs were used from the formation sand in the oil field. Six plugs were from the 7,951- to 7,953-ft interval, five from the 7,723- to 7,727-ft interval, and one from the 7,757- to 7,758-ft interval. All samples were 1 in. in diameter and approximately 2 to 3 in. long. These core samples were classified into groups of high- and low-permeability sands, although a slight difference in physical appearance was observed in the laboratory. Acid solubility tests were run on 10 samples. Mineralogical information is very important in sandstone-acidizing treatments. XRD was used to quantify the mineralogical composition of the core samples. Typical minerals in sandstone rock include silica (quartz), feldspars (plagioclase, K-feldspar), clays (kaolinite, illite, chlorite, smectite, and mixed-layered illite and smectite), zeolites, micas, carbonates (dolomite, calcite), sulfides, and sulfates (gypsum, anhydrite, and barite).

Completion Operations in Low Permeability Deep Basin Gas Reservoirs: To Use or Not to Use Aqueous Fluids, That is the Question

Abstract Many tight gas formations are water-wet and undersaturated where the initial water saturation in the reservoir is less than the capillary equilibrium irreducible water saturation. Using aqueous-based stimulation and workover fluids causes water to be trapped in the near wellbore region, thereby significantly impairing the ability of gas to flow. Therefore, hydrocarbon fluids are better suited for completion operations in such reservoirs. Laboratory data revealing the sensitivity of one such formation to aqueous fluid invasion are discussed and actual field examples are provided in three different formations. Introduction As the oil and gas industry matures and known reserves continue to be depleted, the focus moves towards more challenging environments. One such environment is the Deep Basin area of West Central Alberta where vast reserves of natural gas and associated liquids are present in a number of low permeability reservoirs(1). Similar areas also exist in the U.S., such as the Powder River Basin, Permian Basin, and the Green River Basin. In situ effective gas permeabilities in such reservoirs are in the 0.1 mD range or less. It should be noted that while routine core measurements in the laboratory may indicate permeabilities of up to 1 mD for such reservoirs, the effective gas permeability in the reservoir will be significantly less(2, 3). Although horizontal wells are being used with increasing frequency in exploiting such reservoirs, the vast majority of the wells drilled are vertical wells in the Deep Basin. This is mainly due to the differences in the cost of drilling. A typical horizontal well can be as much as two to four times more expensive than a vertical well for such deep targets. Also, because most horizontal wells are completed barefoot in tight gas reservoirs, the drilling induced damage becomes quite important for the performance of these wells. Therefore, it is critical that a suitable drilling fluid be used in drilling horizontal wells. This was discussed in an earlier article(4). The gas flow rate from a vertical well can be maximized by stimulation. Vertical wells in tight gas formations are usually stimulated by hydraulic fracturing after drilling. Hydraulic fracturing is accomplished by pumping a large volume of fluid mixed with additives and a solid proppant (usually sand) into the formation at high injection rates, cracking the reservoir rock. The fluid is used as a carrier so the proppant can be pumped, and once the proppant has been placed in the fracture, the well is usually flowed back to a tank to recover the carrier fluid. The permeability of the proppant is very high. However, some of the carrier fluid will be imbibed into the freshly exposed matrix rock and remain in place. Depending on the characteristics of the fluid, the permeability of the fracture face may be impaired. The same can also be said for fluids used in workover operations as well. In many low permeability gas reservoirs aqueous fracturing fluids are used due to their cost advantage and safety considerations(5, 6).

Dynamic Modeling of Invasion Damage and Its Effect on Production in Horizontal Wells

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 95861, "Dynamic Modeling of Invasion Damage and Impact on Production in Horizontal Wells," by P.V. Suryanarayana, SPE, and Z. Wu, SPE, Blade Energy Partners; J. Ramalho, SPE, Shell Intl. E&P; and R. Himes, SPE, Stim Lab, prepared for the 2005 SPE Annual Technical Conference and Exhibition, Dallas, 9–12 October. A radially adaptive fine-grid micro-simulator was used to model invasive damage during overbalanced drilling. Near-wellbore pressure and saturation distributions obtained from this model were used as initial conditions for a sector-scale model to study the effects of damage on long-term production performance. Introduction Overbalanced drilling and workover operations often result in invasion of the near-wellbore region by filtrate and solids from the drilling and workover fluids. This invasion causes a reduction in productivity because of degradation of effective permeability. During drilling, mudcake buildup can reduce invasion depth. Mudcake buildup and effectiveness depend on mud formulation, formation characteristics, and overbalance. In horizontal wells, mudcake effectiveness is compromised because of repeated pipe movement against the mudcake, which results in mudcake removal and reformation. Dynamic Damage Modeling A key feature of the model is a fine-grid dynamic microsimulator used to model invasion and obtain a near-wellbore profile of water saturation and reservoir pressure. Saturation-dependent effects such as relative permeability are modeled by use of relative permeability curves based on core tests. The microsimulator has an investigation range of approximately 50 ft from the wellbore. Inputs include the usual reservoir and drilling parameters such as mud properties, overbalance, and drilling time vs. depth. Simulations were performed with and without mudcake to represent the extremes of the invasion boundary. Results from a specially designed core test include undamaged effective permeability, resistance to flow from the wellbore into the reservoir because of the mudcake, absolute permeability damage, and mudcake liftoff pressure. Main output of the invasion model is a near-wellbore saturation and reservoir-pressure profile within the invasion zone that is used with the far-field reservoir properties outside the invasion zone as initial conditions in a sector-scale dynamic simulator with near-wellbore fine grids. Sector dimensions are chosen sufficiently large that no-flow or constant-pressure conditions apply at its boundary. Production is initiated under assumed conditions of rate and pressure constraints, and decline curves are obtained over a desired period of interest (usually 2 to 3 years) for each case of interest. The resulting decline curves for different options can be used to evaluate the effects of invasion on production performance. Fine-Grid Simulator In this work, the near-wellbore fluid-saturation distribution is solved from the two-phase immiscible flow equations as applied to a single-well model. A 2D axisymmetric cylindrical coordinate system is used. Permeability and porosity are assumed to be azimuthally symmetrical along the axis of the horizontal well, and streamlines also are uniformly and symmetrically distributed along the axis. Because the finite-difference method is used to solve the flow equation, extremely fine gridblocks are required to maintain uniform accuracy. A geometric progression scheme is used to generate radially adaptive gridblocks. Finer grid-blocks provide a seamless mechanism to capture the effects of permeability degradation near the wellbore. Typical gridblock size for reservoir-scale models is much larger than the radius of drilling-induced near-wellbore damage. Because a very short time frame (drilling) is being simulated, extremely small timesteps are used to minimize discretization errors.

Viscosity of the Workover Fluid FAPX

The physical properties of workover fluids are important in the success of workover operations, in particular, emulsion stability and viscosity. In this work these properties have been investigated using a direct emulsion of oil in water. Three emulsifiers were analyzed and their effects on emulsion stability have been measured both in terms of surface tension decrease and their hydrophilic-lypophilic behavior. An extensive investigation on viscosity was carried out under laboratory conditions and the results reported as isokoms in ternary diagrams. The experimental results were analyzed in terms of an Arrhenius-type equation. It is concluded that small changes in composition lead to large changes in the viscous properties of the workover fluid.

Drag reduction characteristics in straight and coiled tubing — An experimental study

An excessive friction pressure loss due to the small tubing diameter and curvature (which is believed to cause secondary flow) of Coiled Tubing (CT) often limits the maximum obtainable fluid flow rate in most CT operations. Good drag reduction property becomes a desirable quality for drilling, completion and workover fluids for CT applications. Yet, the drag reduction phenomenon in coiled tubing has not been well understood. This paper presents an experimental study of drag reduction performance of commonly used drag reducing agent, high molecular weight, anionic, AMPS copolymer (Nalco ASP-820) in straight and coiled tubing. The flow loop used consisted of three 1/2-in. OD coiled tubing reels with curvature ratios of 0.01, 0.019, and 0.031. A 1/2-in. OD, 10-ft straight section was also included to compare the drag reduction behavior between straight and coiled tubing. Various concentrations of drag reducing fluid were tested. The optimum concentration was then determined from the results of drag reduction exhibited by the fluid. The differential pressure versus flow rate data were reduced in terms of Fanning friction factor and solvent Reynolds number for estimating drag reduction characteristics. The results show that the drag reduction in coiled tubing are significantly lower than in straight tubing. As curvature ratio increases, the drag reduction decreases. A new drag reduction envelope (which is parallel to the Virk's envelope for drag reduction in straight pipes) is proposed to evaluate the essential characteristics of drag reduction in coiled tubing. The test data plotted on this new envelope clearly show the delayed onset of drag reduction and the effects of curvature and polymer concentration on drag reduction. Presently, the correlations for accurately predicting drag reduction characteristics of a commonly used drag reducing fluid in coiled tubing are non-existent. In this study, new drag reduction correlations are developed that can be used for the engineering design of coiled tubing hydraulics. The correlations are also evaluated using the experimental data from full-scale coiled tubing flow experiments and results showed the good agreement with the predictions from the developed correlations.

The Application of Boundary Element Method to Pressure Behaviour Analysis in a Composite Reservoir With Lateral Drilling

Abstract With the increase of lateral wells, it becomes more and more important to evaluate pressure performance and formation damage in a composite reservoir with lateral drilling. Considering the properties of lateral drilling in a composite reservoir, this paper presents a mathematical model for 3D unsteady flow which is solved using the boundary element method and regional division technique for pressure performance of a lateral drilling well produced at a constant rate or a constant bottomhole pressure. By the reasonable incorporation of pseudo skin factor, dimensionless damaged radius, dimensionless wellbore storage coefficient, and permeability of damaged region, we can get the type curves which can be used to evaluate formation damage caused by lateral drilling. The application to test data for a lateral drilling well in the Liaohe Oilfield in East China shows that the model is reliable and the analysis is valid. Introduction During drilling and production, the formation in the vicinity of the wellbore is damaged to some extent due to the invasion of drilling mud and workover fluids. The evaluation of damage in a lateral drilling well is extremely important for the design of the subsequent well completions. However, an applicable method for the evaluation of damage has not been reported in the literature. Considering factors such as permeability, skin factor, and the radius of the damaged region, a 3D unsteady percolation mathematical model based on the physical model has been derived. Finite differential and finite element techniques are not effective in dealing with the intricate boundary conditions associated with this type of problem. Numerical boundary element method in combination with regional division technique is introduced to solve the flow equations and obtain the numerical solution to the new mathematical model. The boundary element method has three features in handling the mathematical model. First, it lowers the space dimension from 3D to 2D on the boundary curved-surface, which requires less input and computation. Second, it improves precision because the grid partition only involves the boundary and the discreting error comes only from the boundary. The corresponding variables in the region can be directly solved by the differential of the analytical equation. Third, it is convenient for treating the variable at any position in the region. The regional division technique has olved the problem with variable properties as the fluid and formation between the damaged and original formation. The Boundary Element Method, given the above advantages incorporated with the regional numerical simulation, shows promise for applications in simulations. By the reasonable combination of pseudo skin factor, dimensionless damaged radius, dimensionless wellbore storage coefficient, and permeability of damaged region, we can get the type curves which can be used for evaluation of damaged formations caused by lateral drilling. The application to ell test data shows the validity of the model.

Investigation of in-situ low-temperature oxidation as a viable sand consolidation technique

This paper presents the results of the laboratory development phase of a major project to develop a novel sand control technique that could overcome the technical and economic limitations associated with existing methods of sand control. The novel technique is based on in-situ sand consolidation by low-temperature oxidation of a hydrocarbon material that saturates the sand around the wellbore. Laboratory development consisted of two stages. In the first stage, the various process-controlling parameters were optimized to yield consolidated sand with the highest possible compressive strength, minimum loss of permeability, and high stability against typical formation and workover fluids. Under the optimum consolidation conditions, it was possible to produce consolidated sand, from originally loose sand, that is completely stable against flow of crude oil, water and mud acid; has a compressive strength between 1800 and 2300 psi; and with permeability retention between 86.4% and 95.5%. In the second stage, the feasibility of field application of the process was demonstrated on a full-scale physical model resembling an 8-ft section of a 7-in. cased well. The model was packed with loose sand and saturated with crude oil and residual brine. The resulting consolidated sand around the casing was tested by flowing back at a rate of 44 bpd/ft (the maximum available pump capacity) without any sand production. Plans are underway for the first field implementation of the process.

Effects of CaCl 2 and CaBr 2 on the fecundity of Planorbarius corneus L.

Saturated water solutions of calcium chloride (481.3 g CaCl 2/L) and calcium bromide (1065.9 g CaBr 2/L) and their mixtures, commercially prepared as “high density brines”, are regularly used during special operations in exploration and production of natural gas and crude oil. After operations, all workover fluids are left in the environment as waste. In the present study, the effects of several sublethal concentrations of these solutions (CaCl 2 1202 ppm, 2403 ppm and 4796 ppm, CaBr 2 1065 ppm, 2663 ppm and 5325 ppm, 1:1 volume mixture 773.9 ppm, 1931 ppm, 3855 ppm and 5779 ppm) on the fecundity of the freshwater snail Planorbarius corneus L. were laboratory tested. During the six week exposure a considerably reduced fecundity was found. The tested CaCl 2· solution concentrations reduced fecundity by 53.9–84.4 %, CaBr 2 by 72.3–90.8 % and the mixture by 72.5–94.0 % compared with the control groups.

Damage Caused By Clay-based And Clay-free Inhibitive Fluids In Sandstone Formations

Abstract This paper describes the results of a research project on the extent of damage caused by clay-based and clay-free inhibitive fluids in two consolidated sandstones of permeability ranges 0.008-0.013 µm2 (D) and 2.2-2.6 µm3 (D) under simulated borehole conditions using a closed loop circulating facility. The fluids, containing K +, Mg + +, or Ca + + ions as well as clays, solid bridging materials and different polymers, can be used either as drilling fluids or as workover, fracture and gravel pack fluids. The damage was studied on the basis of two factors, viz. damage ratio (DR) (percentage of original permeability lost after encountering the fluids) and sectional damage ratio (SDR) (determined by cutting the damaged core into several segments and then determining the damage ratio of each segment relative to the original permeability of the core). The sectional damage ratio is used to determine the radius and extent of damage in the formation. The dynamic filtration characteristics and the rheological properties of the used fluids were also evaluated. The effect of increasing the temperature and differential pressure on formation damage and filtration characteristics of the sed fluids were also investigated. The effect of the presence of formation pore bridging materials (viz. chalk) in decreasing the extent of damage is also demonstrated here. Introduction During the short phase of "mud spurt." a mud loss occurs in "overbalanced" drilling as a result of the positive differential pressure Δp. The mud spurt continues as long as free faces of the fommtion are available. After the building of the inner and/or outer "filter cake" only the filtrate can dissipate into the formation. In the mud spurt phase, the introduction of the solids into the formation, the changed conditions of fluid saturation in formation pores. solubilization of some of the materials from the rock matrix into [he filtrate and transportation of finer solids into the formation to a wide distance contribute to the reduction of formation permeability and hence well productivity; thus, the formation is deemed damaged. In addition to drilling, filtrate invasion and solid transport can occur during other well operations, such as well cleaning, fracturing and gravel Packing, which result in formation damage. This paper reports on the results of investigations into the extent of damage caused by some clay-based and clay-free inhibitive fluids containing cations and formation pore bridging materials in two consolidated sandstones. The effect of temperature and differential pressure as damage influencing factors were also investigated. The damage was evaluated using mostly 1–5% KCI-solution saturated cores and in some cases, oil saturated cores. Theoretical Background The reduction in the productivity of a well through contamination by drilling and treating fluids has been defined as formation damage. The productivity of a damaged formation is given by Muskat(6) as: Equation (Available In Full Paper) This equation shows that the productivity of a particular well in a formation depends upon two factor, viz. kd (permeability of the damaged formation) and rd (radius of the damaged zone).

Reductions In the Productivity of Oil And Low Permeability Gas Reservoirs Due to Aqueous Phase Trapping

Abstract Many hydrocarbon bearing reservoirs exhibit the potential for significant productivity reductions due to adverse relative permeability effects associated with the retention of invaded aqueous fluids. These fluids could include-water-based drilling mud filtrates, completion fluids, fracture fluids, workover fluids, kill fluids or stimulation fluids (including-spent acid). This paper identifies potential mechanisms behind phase trapping and identifies particular reservoir types which tend to be susceptible to this type of formation damage, most notably low initial water saturation gas reservoirs and strongly oil-wet oil reservoirs. Laboratory techniques to investigate the severity of aqueous trapping and various remedial techniques are described, and two field case studies illustrating the potential for permeability impairment due to invasive aqueous trapping are presented. One case study describes a series of wells completed in the Paddy formation and the second in the Cadomin formation in the Deep Basin area of central Alberta (both gas producing zones). Laboratory case studies documenting the phenomenon of aqueous, phase trapping in strongly oil-wet porous media are also presented. Introduction Oil and gas bearing formations are potentially susceptible to many different types of formation damage(1–6). In this paper we are exclusively concerned with damage associated with aqueous phase trapping (or water trapping or blocking as it is often referred to). To understand the concept of aqueous phase trapping, it is essential to differentiate between the concept of initial (often referred to as connate) aqueous phase saturation (Swi) and irreducible aqueous phase saturation (Swirr).Initial aqueous phase saturation is the initial average fractional portion of the pore space which is occupied by water. The value of the initial aqueous phase saturation is controlled by numerous factors, including reservoir geology, depositional history, temperature, wettability, height above free water contact and pore size distribution. The key point to differentiate in this area is that the initial aqueous phase saturation is not necessarily, and often is not equal to the irreducible aqueous phase saturation and can be either higher or lower than the irreducible saturation. It is in the second case, where the Swi is less than Swirr where productivity reductions due to phase trapping can occur.Irreducible aqueous saturation represents that saturation which is forced to exist in the reservoir by capillary mechanics. Once again, the value of the Swirr is determined by parameters such as the reservoir morphology, pore size distribution, pore throat size distribution, wettability, surface roughness, etc. We often obtain estimates of Swirr through the use of air-brine or air-mercury capillary pressure tests, Although these values often provide good approximations to Swirr they may be poor indications of actual Swi. FIGURE 1: Mechanism or aqueous phase trapping. (Available in full paper) Mechanism of Aqueous Phase Trapping Figure 1 provides an illustrative example of a set of relative permeability curves. The diagram is applicable to either an oil or a gas reservoir. Examination of Figure 1 indicates that, if the zone of interest is at some aqueous saturation greater than the irreducible value of 45%, aqueous trapping will not be a severe problem because the reservoir is already initially highly saturated with water and may even be producing free mobile brine.

An Overview of Formation Damage (includes associated paper 20014 )

Introduction Formation damage has been, and continues to be, a concept that is accepted or rejected on the basis of personal opinions, experiences, and perceived understanding of the process of producing oil and gas. It should be a concern for all oilfield people, whether derrick hands or managers, because it affects the economics of the companies that employ us. A good overview on the subject of formation damage is presented in Ref. 1 Formation damage is a very real problem that must be addressed equally by all departments within a company. It does no good for the drilling department to spend time and money doing the best job possible drilling a water-sensitive zone if the production people dump fresh water down the hole as a kill fluid. Good communication between all departments is imperative to deal with a damage-sensitive zone satisfactorily. In this paper, I relate the concepts and ideas formulated from my work and from communication with other oilfield people. I think that with improved techniques and practices, we will eventually improve the present norm of a 20 to 30% recovery factor achieved at the cost of probably 80 to 90% of the reservoir energy. I hope that recovery factors improve significantly. allowing us to produce 25 to 35% or more on average of the original reserves, depending on economics and on how smart we become. This improvement will require a better understanding of the total chemical and physical picture of the reservoir and its fluids by all industry personnel, not just a few researchers. Another important fact is that no matter what appears to be important, for each phase of the operation, production optimization must not be at the price of safety. The best solution is generally one of some degree of compromise. Because the Middle East nations can produce and transport oil to markets for less than $5/bbl [$32/m3], Western nations must change their thinking and start cooperating, much like the Japanese consortiums, to develop better technologies. If we are to compete effectively with other nations and other energy sources and to remain a viable industry, we must change some of the accepted ideas and be more open with information that is not vital to a company's economic security. I think that the SPE Forum Series events are superior to the traditional technological meetings for information exchange. The healthy exchange of knowledge that takes place in the more informal environment of a forum allows our industry to grow far more rapidly simply because the information is current. This concept must be fostered. I recently requested a literature search for articles that dealt with formation damage. I asked for a brief abstract of each article. The printout I received was an 8 1/2x11-in. [22x 28-cm] book more than 2 in.[5 cm] thick. A tremendous number of good articles have been written on this subject, and any library can organize a similar search. It is impossible to mention each article that pertains to the subject at hand-my apologies. Discussion Formation damage can be caused by either a simple or a complex process involving any one of the phases of producing oil or gas. The dynamics of the drilling process alone is so great that it has to alter adversely the rock's ability to flow fluids. It can be a real test of patience to sort through what has happened to establish a likely cause and to formulate corrective measures. As often as not, the information is sketchy or unavailable. A good example is the case where a potassium-sulfate-based mud system obviously went wrong. With the information that was gathered and knowledge of the area where the well was drilled, the most probable cause of the failure was determined to be that the water hauler looked for the closest water source, which unfortunately was an alkali pond or slough. The very high content of dissolved calcium salts caused a chemical reaction in the mud that prevented the system from functioning as designed. The water sources for drilling and workover fluids are seldom documented, much less analyzed, for desirability, often because the standard forms have no space for this information. JPT P. 780^