Wellbore Wall Research Articles

Highly Compressible Porous Media Flow near a Wellbore: Effect of Gas Acceleration

A fundamental study on porous medium flow of a highly compressible gas near a wellbore is carried out. The effect of gas acceleration is assessed quantitatively. It is shown that gas acceleration induced by the converging flow introduces a quadratic drag on the flow; acceleration due to volumetric-expansion causes the pressure curve to steepen near the wellbore and the flow to become choked at high flow-rates. When the flow is choked, the pressure gradient at the wellbore wall becomes unbounded. It is also shown that for any given mass flow-rate, the well pressure predicted from the model considering acceleration effect is significantly below that calculated from the Darcy-Forchheimer model. Implications of these results to petroleum engineering are discussed.

Initiation pressure, location and orientation of hydraulic fracture

The Hubbert and Willis (1957) [1] fracture criterion has been widely adopted to predict longitudinal fracture initiation in vertical or horizontal wellbores. Current transverse fracture criteria predict fracture by comparing the axial stress in the wellbore wall with the tensile strength of rock. It is shown in this paper that the axial stress is not a good predictor of transverse fracture initiation, because it remains constant during hydraulic pressurization. The magnitude of the most tensile principal stress in the wellbore wall should always be compared with the tensile strength of the rock to predict hydraulic fracture initiation based on elastic theory. Special cases have been found in which the most tensile principal stress reaches the tensile strength of the rock simultaneously at all point on the circumference of the wellbore. It is proposed that transverse fractures are initiated in those cases.

Analysis of Postbuckling Drillstring Vibrations in Rotary Drilling of Extended-Reach Wells

One of the most serious concerns of extended-reach drilling is the dynamic behavior of the drillstring and the cleaning of well. Good cleaning requires an increased angular velocity. This paper presents a 3D nonlinear dynamic model of drillstring in a wellbore of 3D profile. The model suggests possible contact/lift-off of drill pipes with/from the wellbore wall. The interaction of lateral, torsional, and axial vibrations is taken into account. The relation between the normal component of contact force and the deformation of the wellbore wall is taken as quadratic-elastic. The friction force is described based on a hysteretic dynamic model. The friction force model also takes into account, the transition from a sliding to whirling. The equations of drillstring dynamics are solved numerically using the method of lines. The DYNTUB software is developed to analyze the drillstring time-varying processes under different loads. The program is used to study the effects of angular velocity, compression load, torque, friction factor, well profile, and availability of connectors on the drillstring dynamic behavior. From the study follows the key conclusions: (1) The friction factor has a considerable effect on the drillstring rotational behavior in the wellbore; (2) no whirling of drillstring at real value of rolling friction factor in a horizontal well in the discussed examples could be seen at all; (3) when whirling takes place, the contact force shows a dramatic times increase; and (4) snaking can be seen in any wells at moderate compressive load and angular velocity.

Equilibrium of a pressurized plastic fluid in a wellbore crack

This paper investigates equilibrium of a pressurized plastic fluid invading a tensile wellbore crack in a linear elastic, permeable rock. The crack is initially filled by pore fluid at ambient pressure, that is immiscibly displaced by the plastic fluid invading from the wellbore. The plastic fluid comes to rest to form a “plug” within the elastically deformed crack when the limit equilibrium between the shear stresses generated at the fracture walls and the pressure drop between the wellbore wall and the crack tip is reached. The model assumes that the leak-off of the plastic fluid into the rock is negligible, while the displaced pore fluid in the crack tip region is freely exchanged with the surrounding permeable rock to maintain the ambient pressure level. When the crack length ℓ is small or large compared to the wellbore radius R, the problem reduces to that of a pressurized edge or Griffith’s crack, respectively, subjected to a uniform far-field confining stress. In these two end-member cases, the normalized solution for the net pressure distribution, the plug length, and the stress intensity factor at the crack tip is obtained as a function of two numbers – the normalized net fluid pressure at the crack inlet and at the crack tip (partial plugs only) – that embody the solution’s dependence on the wellbore and the far field loading, the fluid yield strength, and the rock modulus. In the general case of an intermediate crack length (ℓ ∼ R), the normalized solution is a function of two additional parameters, the length-to-radius ratio and a normalized measure of the far field stress anisotropy, respectively, which accurate approximation is devised from an end-member solution using a rescaling argument. The equilibrium plug solutions are used to evaluate the breakdown pressure, the critical wellbore pressure at which the crack propagation condition is first met, and to analyze the stability of the ensuing crack propagation.

Finite element analysis of drillstring lateral vibration

Lateral vibration is recognized as the leading cause of drillstring and bottom hole assembly (BHA) failures, shocks and severe damages to borehole wall. This study presents a finite element model using ANSYS software to investigate the drillstring lateral vibrations in slightly deviated wells. The analysis proceeds in two stages. At first, a nonlinear static analysis is performed to determine the effective length of the string where it is free to vibrate in the lateral direction. The second stage consists in modal, harmonic and transient dynamic analyses to obtain the lateral vibration modes and natural frequencies, frequency response and time dependent response respectively. The modeling is developed in the presence of mud, friction and nonlinear contact between drillstring and wellbore wall. The effects of drilling mud, drillstring length, well inclination and WOB are considered. The model was compared with experimental and simulated results obtained from several BHA configurations, giving excellent results. Key words: Drillstring, finite element model, lateral vibration, nonlinear contact model.

Short-time pressure response during the start-up of a constant-rate production of a high pressure gas well

The start-up flow of a constant-rate production of a high pressure gas well is studied, with emphasis on the effect of gas acceleration. Gas acceleration is important in the near wellbore region for a high pressure gas in a high permeability formation. It is shown that when gas acceleration is important, the system of governing equations for the porous media flow becomes hyperbolic. In response to an impulsively imposed mass flow-rate, a steep pressure front is created at the wellbore and it propagates into the formation. This steep pressure front is trailed by large amplitude pressure waves. As they travel away from the wellbore, the pressure front becomes less steep and the amplitude of the trailing waves decreases due to viscous damping. It is found that the pressure drawdown experiences a rapid increase followed by an oscillatory behavior in short times before approaching the classical logarithmic rise regime. The pressure gradient at the wellbore wall can grow to a large magnitude in the early times, which can cause a tensile failure of the rock materials near the wellbore.

A Robust Method for Calculating Formation Mobility With a Formation Tester

SummaryDetermining formation mobility (permeability/viscosity) with a formation tester dates back to the introduction of the tool in the mid-1950s. Many methods have been developed over the years to calculate a formation mobility from a pressure test. Here, a rigorous method is presented that has several convenient features. It is based on a model that assumes the presence of both tool-storage and formation compressibility and so is appropriate for a fully unsteady flow induced in the formation, but it does not require the determination of either compressibility to determine the mobility. The full impact of the wellbore geometry is included (i.e., it does not assume the "spherical-flow model"). The mobility is determined by a simple, direct calculation of the measured time-dependent pressure, as opposed to methods based upon data regression or solving an inverse problem. On the other hand, this new method shares several of the restrictions common to existing techniques: It assumes that the formation contains a single phase of slightly compressible fluid. The calculated mobility characterizes the formation in the vicinity of the wellbore wall, in which formation damage is most likely to occur.This publication is dedicated to Gérard Catala, a colleague with tremendous insight.

Finite Element Analysis of Drillstring Lateral Vibration

Lateral vibration is recognized as the leading cause of drillstring and bottom hole assembly (BHA) failures, shocks and severe damages to borehole wall. This study presents a finite element model using ANSYS software to investigate the drillstring lateral vibrations in slightly deviated wells. The analysis proceeds in two stages. At first, a nonlinear static analysis is performed to determine the effective length of the string where it is free to vibrate in the lateral direction. The second stage consists in modal, harmonic and transient dynamic analyses to obtain the lateral vibration modes and natural frequencies, frequency response and time dependent response respectively. The modeling is developed in the presence of mud, friction and nonlinear contact between drillstring and wellbore wall. The effects of drilling mud, drillstring length, well inclination and WOB are considered. The model was compared with experimental and simulated results obtained from several BHA configurations, giving excellent results. Key words: Drillstring, finite element model, lateral vibration, nonlinear contact model.

Particle-Size Distribution Improves Casing-While-Drilling Wellbore-Strengthening Results

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 128913, ’Particle Size Distribution Improves Casing- While-Drilling Wellbore Strengthening Results,’ by R.D. Watts, SPE, M.R. Greener, SPE, S. McKeever, SPE, P.D. Scott, SPE and D. Beardmore, SPE, ConocoPhillips, originally prepared for the 2010 IADC/SPE Drilling Conference and Exhibition, New Orleans, 2-4 February. The paper has not been peer reviewed. The full-length paper describes the application of particle-size-distribution principles for determining materials to be added to the mud system during casing-while-drilling (CWD) operations. CWD has been demonstrated to stop or significantly reduce lost circulation and improve well-bore strength. The mechanism by which this improvement occurs is not well understood. Introduction If wellbore strengthening can be achieved systematically, then wells can be drilled in known loss areas without contingency strings of casing. In addition, in mature fields where producing horizons have altered pressures from either depletion or pressure maintenance, wells can be drilled with fewer casing strings. Sidetracks become economical because hole size can be preserved for an effective completion, and well costs are lowered by not using additional liners to reach the objective. By adding particles to the mud to fill in the particle-size distribution, losses to natural fractures were stopped while directional wells were drilled with casing in the Piceance basin of Colorado. Applying what was learned in a field trial of CWD in the Alaskan Tarn field, the openhole leakoff resistance was improved by 3.0 lbm/gal drilling with 7.0-in. casing in a 67° angled well. With this success, a four-well CWD campaign was executed with two wells drilled each in the Kuparuk and Tarn fields on Alaska’s North Slope. Results were positive for 7.0-. and 7.625-in. casings, but wellbore strengthening did not occur sufficiently in the 5.50-in.-casing trials. Annular clearance appears to be a critical component for success and is not yet fully understood. The results demonstrate that a significant improvement in fracture gradient can be achieved with the right clearance between the hole and the casing and the proper-sized particles added to the mud system. In addition, the amount of material added has been demonstrated to be as low as 2 lbm/bbl. With confidence that strengthening can be achieved to the levels of improvement demonstrated, wells can be evaluated with significant cost savings by eliminating casing strings and preserving hole size for completions or further drilling. Smear Effect The smear effect has been considered to be either a smearing and plastering of cuttings onto the wellbore wall or the increase in hoop stress around the wellbore resulting when a crack is formed and particles are forced into the gap, creating a wedge and thereby raising the effective fracture gradient. At Piceance, imaging logs taken in the overburden confirmed natural fractures with a radially averaged aperture of approximately 1.0 mm, and these could be correlated back to losses while drilling. Because CWD had stopped losses in these intervals, wellbore strengthening was believed to be the more likely mechanism.

A Fully Coupled Chemo-Poroelastic Analysis of Pore Pressure and Stress Distribution around a Wellbore in Water Active Rocks

Water active rocks consist of minerals that hold water in their crystalline structure and in pore spaces. Free water from drilling fluid can be attracted by the formation depending on the potential differences between pore space and drilling fluid. The fluid movement into the formation or out of the formation can lead to a change in effective stress, thus causing wellbore failures. In all previous studies it is found that the solute transport from or to the formation is primarily controlled by diffusion process and the effect of advection on solute transfer is negligible for a range of very low permeable shale formations (>10−5 mD). In this study a range of permeable shale formations (10−5 to 10−3 mD) commonly encountered in drilling oil and gas wells are considered to investigate the solute transfer between drilling fluid and formation due to advection. For this purpose a finite element model of fully coupled chemo-hydro-mechanical processes was developed. Results of this study revealed that the solute transfer between the drilling fluid and the shale formation is controlled primarily by permeability of the shale formations. For the range of shale formations studied here, there exists a threshold permeability below which the solute transfer is dominated by diffusion process and above which by fluid in motion (fluid flow). Results from the numerical experiments have shown that when the permeability of shales is greater than this threshold permeability, the chemical potential gradient between the pore fluid and drilling fluid reaches equilibrium faster than that when the permeability of shales is below this threshold value. Also it has been found that when advection is taken into account, effective radial and tangential stresses decrease around the wellbore, particularly near the wellbore wall where the solute concentration has reached near equilibrium.

Initiation of a secondary hydraulic fracture and its interaction with the primary fracture

Laboratory and field experiments have shown that secondary fracture treatment along a different direction to the primary hydraulic fracture can increase the recovery of gas from tight sands. Success of a restimulation treatment (secondary fracture treatment) is, however, highly dependent on transient stress distribution around the well. In this paper a numerical poroelastic reservoir model is used to provide a more realistic picture of stress field around a stimulated well during post-fracture production. Initiation of a re-oriented hydraulic fracture and its interaction with the primary hydraulic fracture are also studied using a wellbore re-pressurization model that includes a poroelastic formation, a wellbore and a pair of finite conductive hydraulic fractures. Numerical results have shown that during post-fracture production the directions of maximum and minimum horizontal stresses are reversed within a large area around the wellbore and the hydraulic fractures. We have also shown that relatively small areas exist at the wellbore wall where the original directions of horizontal principal stresses remain unchanged. It is shown that the presence of these small areas could act against initiation of a secondary hydraulic fracture along the most desired directions in terms of recovery enhancement. This study also shows that oriented perforations prior to refracture treatment help initiate secondary fractures in a preferred direction before the primary hydraulic fractures start propagation during re-pressurisation of the wellbore.

An Integrated Geomechanical and Passive Sand-Control Approach to Minimizing Sanding Risk From Openhole and Cased-and-Perforated Wells

Summary The source of sand production is the presence of disintegrated sand grains caused by rock failure at the wellbore and/or perforation walls. Decision for appropriate sand-control strategy requires engineering analysis to evaluate timing and severity of sanding over the life of field conditions. Optimizing well parameters such as well trajectory, perforation orientation, and level of drawdown using geomechanical principles can minimize and delay sand production. This paper presents a geomechanical modeling approach that integrates production history with information from drilling data, well logs, and rock-mechanics tests. A gas field in south Asia with 11 wells and several years of production experience is used to demonstrate this approach. Core-calibrated rock-strength-log profiles are estimated throughout the reservoir depth for all existing wells. A rock-failure criterion at the sandface is developed as a function of in-situ stresses, rock strength, well trajectory, perforation orientation, reservoir depletion, and drawdown. Sanding-evaluation results are calibrated and verified with production data and evidence of sanding in existing wells. Sand-free operating envelopes and sand evaluation logs are then generated for all existing wells and planned infill wells for the life of field conditions. Sand-prone zones and timing of sanding are established as a function of depletion and drawdown for each well, using production forecasts for the rest of field life. For new infill wells, optimum well trajectories, selective perforation intervals, and optimum perforation orientations are proposed to minimize and delay sand production. Recompletion and using passive sand-control methods including selective and orientated perforations are recommended for a number of existing wells. This paper is expected to provide well engineers with guidelines to understand the principles and overall workflow involved in sand-production prediction and minimization of sand production risk by optimizing well trajectory, perforation orientation, and selective-perforation strategy.

Temperature-dependent stability of deep wells in the Cooper Basin

The Cooper-Eromanga Basin is characterised by high heat flow that has been related to the presence of high radiogenic heat-producing granites. Several wells have been drilled in the area to exploit the heat from the fractured granitic rocks of the basement. Drilling through the hot formations in the Cooper Basin (max. temperature ca. 250 °C) with relatively cool drilling fluids induces an almost instantaneous cooling of the wellbore wallrock. Cooling of the hole (the usual case) increases the tensile stresses (and decreases the compressive stresses) at the wellbore wall. The magnitude of the thermal stresses is also dependent on the silica content of the formation. Modelling of the in situ stress tensor and mechanical properties of the wellbore rocks has revealed the time-dependent effect that the borehole collapse pressure has on the stability of the wells. Narrow breakouts form at the time of drilling. Afterwards, the temperature difference (ΔT) decays with time, and as the hole warms up compressive stresses increase and breakouts become enhanced. Therefore, if a high ΔT and a short well exposure time are achieved, it would be possible to inhibit breakout development, drill with a lower mud weight (eventually underbalanced), and, thus, minimise the risk of formation damage.

Identification of lift-off mechanism failure for salt drill-in drilling fluid containing polymer filter cake through adsorption/desorption studies

Abstract Drilling fluid's contact with the productive zone of horizontal or complex wells can reduce well productivity by fluid invasion in the borehole wall. Salted drilling drill-in fluid containing polymers has often been applied in horizontal or complex petroleum wells in the poorly consolidated sandstone reservoirs of the Campos basin, Rio de Janeiro, Brazil. This fluid usually consists of natural polymers such as starch and xanthan gum, which are deposited as a filter cake on the wellbore wall during the drilling. Therefore, the identification of a lift-off mechanism failure, which can be detachment or blistering and pinholing, will enable formulation improvements, increasing the chances of success during filter cake removal in open hole operations. Likewise, knowledge of drill-in drilling fluid adsorption/desorption onto sand can help understand the filter cake–rock adhesion mechanism and consequently filter cake lift-off mechanism failures. The present study aimed to identify the lift-off failure mechanism for this type of fluid filter cake studying adsorption/desorption onto SiO 2 using solutions of natural polymers, lubricants, besides the fluid itself. Ellipsometry was employed to measure this process. The adsorption/desorption studies showed that the adsorbed layer of drilling fluid onto the walls of the rock pores is made up of clusters of polymers, linked by hydrogen bonds, which results in a force of lower cohesion compared to the electrostatic interaction between silica and polymers. Consequently, it was found that the most probable filter cake failure mechanism is rupture (blistering and pinholing), which results in the formation of ducts within the filter cake.

Geomechanics Optimizes Field-Development Strategy of Deep Gas Reservoir

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 108891, "Using Geomechanics To Optimize Field-Development Strategy of Deep Gas Reservoir in Saudi Arabia," by Mahbub S. Ahmed, SPE, Saudi Aramco; Thomas Finkbeiner, SPE, GeoMechanics International; and Adnan A. Kannan, SPE, Saudi Aramco, prepared for the 2007 SPE Asia Pacific Oil & Gas Conference and Exhibition, Jakarta, 30 October-1 November. The paper has not been peer reviewed. Saudi Aramco has embarked on drilling long horizontal and maximum-reservoir-contact wells in deep gas reservoirs. The regional stress is important in predicting wellbore stability and production performance. A detailed geomechanics study was made, and its results were incorporated into the decision tree. The objectives were to find the optimum azimuth to place horizontal wells that would minimize the risk of hole breakouts, optimize drilling-mud weights, and ensure sustainable production under depletion mode. Introduction The subject field is a north/south-trending anticline. The target reservoir is the Permian Unayzah formation, which was discovered in 2000. The reservoir has three geological units: Unayzah-A, siltstone, and Unayzah-B. Because of stratigraphic considerations and constraints on wellhead placement on the surface, field development with highly deviated horizontal drilling is required to reach the target reservoirs. Reservoir management decided to extend the horizontal wells as far as possible to maximize reservoir contact and, hence, production from the Unayzah formation. Because of the highly deviated/horizontal nature of the planned development wells, it was decided to gain a better understanding of whether geomechanical processes might be of concern to wellbore stability. If so, could well integrity be maximized by use of correct mud weights and well directions that would ensure stable conditions during drilling and production? Determining Stress Orientation Approximately 2,500 ft of electrical wellbore-image data covering the Unayzah-A, -B, and parts of Unayzah-C reservoirs from the first four vertical wells drilled in this field were analyzed. The image data were calibrated, verified, and dynamically normalized to provide optimal image quality. Overall image-data quality in all four wells was fair to good. This analysis identified and characterized stress-induced wellbore failure, such as stress-induced borehole breakouts and drilling-induced tensile fractures. Wellbore breakouts are enlargements of the wellbore wall with 180° spacing caused by localized shear failure, where the circumferential hoop stress is most compressive and exceeds the ultimate compressive strength (UCS) of the rock. In vertical wells, breakouts always form in the direction of the least principal horizontal stress. In deviated wells, the position of breakouts in a well is a function of the wellbore trajectory and the stresses acting on the wellbore. Therefore, when wellbore failures can be detected, their occurrence and characteristics (i.e., azimuth and width) can be used to determine in-situ stress magnitudes, effective rock strength, and stress orientations. In general, an abundance of stress-induced wellbore breakouts and some drilling-induced tensile fractures were detected. These fractures occurred intermittently throughout all three Unayzah formations. Cumulative length of these breakouts ranged from 86 to 142 ft in each well.

Bottomhole assembly analysis by finite difference differential method

AbstractThis paper presents a three‐dimensional finite difference differential method for bottomhole assembly (BHA) analysis under static loads. The analysis is required to optimize the BHA configurations for drilling directional boreholes in the petroleum industry. The optimization of BHA configurations ensures the controlled cruising of the drill bit to drill the hole along a planned trajectory. The model incorporates the contact response between drillstring and wellbore wall, the upper tangent point problem, stabilizer configurations, bent sub model and other considerations for numerical solutions. The overall formulations are presented in a matrix format within convenient coordinate systems developing a transformation matrix. Key solution algorithms for computer programming are then described in detail. One analytical solution for beams under weight and torque is used to verify the method. Also the analytical solutions of three other simple BHA configurations are used for verification. The verified method is then applied in a series of parametric investigations to characterize the responses of typical BHAs. The BHA responses studied include the side force at bit and lateral deformation of the assembly along its length with varying weights on bit and hole inclination angles for typical building, dropping and holding assemblies. BHAs with bent sub are analyzed with various tool face angles and bent angles. The effect of wellbore curvature on side forces is also demonstrated. Copyright © 2007 John Wiley & Sons, Ltd.

One-Trip Completion System Eliminates Perforations

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 101086, "One-Trip Sand-Control/Liner-Hanger/ Big-Bore Completion System," by C.R. Hoffman, SPE, Baker Oil Tools, prepared for the 2006 SPE Asia Pacific Oil & Gas Conference and Exhibition, Adelaide, Australia, 11–13 September. A new completion system replaces conventional tubing-conveyed perforating (TCP) and gravel packing. This technology also eliminates formation damage caused by perforating and reduces skin values. It is a new-generation, screenless-sand-control completion system. A telescoping conduit containing sand-control media composed of stainless-steel beads was chosen for its durability and erosion and plugging resistance. The system contains no explosives, eliminating many issues. Introduction A joint-investment project team consisting of three major operators, a service company, and an independent tool manufacturer was formed and charged with the task of developing a system that eliminated formation damage and greatly reduced skin values. Conventional perforating is a major cause of formation damage, so the primary goal was to eliminate perforations and still achieve connectivity with virgin reservoirs and maintain full-bore production and/or injection rates. Also, one-trip capability and user-friendliness were of primary concern; if this system were to cost operators more throughout the completion of a given well, it would have no merit in the marketplace. Therefore, the system was designed around conventional liner and cementing techniques. Purpose Fractured and compacted zones, perforation debris, and formation blockages are common types of damage that can occur in a conventional-perforation tunnel. Case histories have proved that skin values are significantly increased over the life of a well as a result of perforation-tunnel depth and fines that accumulate or are never properly cleaned from these tunnels. Studies have shown that for a 7½-in.-deep perforation tunnel, there may be as much as 60 lbm/ft of debris that must be cleaned from the wellbore. By design, this new technology addresses these factors affecting well productivity. The new technology had to satisfy the following criteria: one-trip deployment, primary cementing of casing tubulars, connectivity to a virgin reservoir, and sand control, all while maintaining cost effectiveness. One-trip installations reduce rig costs greatly. This new technology also addresses some of the problems associated with conventional cased-hole gravel packs such as incomplete perforation packing, voids in the annular pack, and poor communication with the reservoir. Drilling the New Well Use of a calcium-carbonate-based drill-in fluid while drilling the production or injection interval is quite common today. A manganese weighting agent may be used in these fluids to increase fluid density. The carbonate-based fluids provide a very thin, very uniform filter cake on the wellbore wall, providing stability to sensitive and unconsolidated formations. Also, the carbonate particles are acid soluble. This is imperative for this new system because when the telescoping conduits extend and contact the wellbore, a small amount of this material may be trapped on the face. With a barite-based mud there would be no way to remove this obstruction because barite is inert.

Removal of polymeric filter cake in petroleum wells: A study of commercial amylase stability

The drilling fluid contact with the productive zone of drilling wells, with horizontal or complex configurations, can reduce its productivity by fluid invasion in the borehole wall. Drilling fluids usually comprise natural polymers as starch and xanthan gum. These polymers are deposited as a filter cake on the wellbore wall. A common approach to remove this filter cake is the application of acids or strong oxidative solutions. However, these are non-specific species and a possible alternative lies in enzymatic preparations that are able to hydrolyze such polymers. The enzymes catalyze specific substrates, are environmentally friendly and the enzymatic degradation rate is slower than that achieved by the oxidative species, permitting to produce uniform degradation of the filter cake. Openhole operations require thermo and pressure stability of these enzymatic products. The results herein reported deals with the technical viability analysis of a commercial α-amylase as a new catalyst for filter cake removal. The effects of process parameters, like temperature (65, 80 and 95 °C), enzyme concentration (1, 5.5 and 10% v/v), calcium concentration (5, 70 and 135 ppm), and pressure (100, 500, 100 and 6000 psi), on amylase stability under openhole operations were investigated. Temperature demonstrated to be the most important parameter for the enzyme stability. The enzyme thermostability behavior in high salt (NaCl) concentration (completion fluid) was not significantly different from the control solution in distillated water. The pressure effect on enzyme stability did not affect the enzyme stability as temperature. Hydrostatic pressure (6000 psi) did not impact the amylolytic activity in brine solution. Combined pressure–temperature assays showed that temperature is the key factor in enzyme stability for application in polymeric filter cake removal in petroleum wells.

An analytical model for predicting the productivity of perforated wells

In this work, we present an analytical model for the prediction of the productivity of perforated wells. The basic building block of the model is an analytical solution for single-phase Darcy flow to a single perforation in a semi-infinite porous medium. We have expanded this solution to describe the flow to a well with regularly spaced arrays of equidistant perforations along the wellbore wall. The end result is a formula for the perforation skin as a function of perforation length and radius, shot density, perforation phasing, permeability anisotropy, perforation damage and formation damage. Partially perforated wells can be handled with the help of the total skin formula of Jones and Watts [Jones, L.G., Watts, J.W., 1971. Estimating Skin Effect in a Partially Completed Damaged Well. J. Pet. Technol. (February), 249–252.]. The results of the model compare fairly well with the results of previous numerical flow simulations. The model can be readily implemented in a standard spreadsheet program and may be used as an alternative to the current semi-analytical method of Karakas and Tariq [Karakas, S.M., Tariq, S.M., 1991. Semianalytical Productivity Models for Perforated Completions. SPE Prod. Eng. (February), 73–82.]. It is shown that this method does not properly account for permeability anisotropy, which results in overly optimistic well productivities, particularly in the presence of perforation and formation damage.

Stress Partitioning and Wellbore Failure in the West Tuna Area, Gippsland Basin

Image logs from the deep intra-Latrobe and Golden Beach Subgroups of the West Tuna area in the Gippsland Basin reveal that wellbore failure is restricted to fast, cemented sandstone units and does not occur in interbedded shales. Triaxial testing and analysis of empirically derived, wireline-log based strength equations reveals uniaxial compressive strengths of 60 MPa in sandstones and 30 MPa in shales in the West Tuna area. Conventional analysis of wellbore failure assumes constant stresses in the shales and adjacent sandstones and that breakout is focused in the weaker units. We propose that the flat lying, strong, cemented sandstone units in the West Tuna area act as a stress-bearing framework within the present-day stress regime that is characterised by very high horizontal stresses (SHmax > Shmin = Sv). Stress focusing in strong sandstone units can result in high stress concentrations at the wellbore wall and account for the restriction of wellbore failure to the strong sandstone units.Finite element methods were used to investigate the stress distribution in horizontal, interbedded ‘strong’ sands and ‘weak’ shales subject to a high present-day stress state such as exists in the West Tuna area (SHmax > Sv ~ Shmirl). Modelling using the present-day stress tensor and estimated elastic properties for the sandstones and shales indicates that the present-day stress is ‘partitioned’ between ‘strong’ inter-bedded sandstones and ‘weaker’ shales, with high stress being focussed into the strong sandstones. The stress focusing causes borehole breakout in the sands despite their higher strength. Conversely, stresses are too low to generate wellbore failure in the weaker shales.