Near-wellbore Pressure Research Articles

Physical simulation study on production characteristics and mechanism of connate water in gas reservoirs

The late-stage development of gas reservoirs often encounters the paradox of significant remaining formation pressure coupled with low wellhead pressure, which indicates small drainage volume, low gas production rate, and low recovery efficiency, reducing gas supply and economic benefit. Owing to the lack of experimental research, the reasons behind this contradiction between gas production and producing pressure differential are unclear. The key factors affecting the development outcomes are reservoir permeability and initial water saturation, while the evaluation parameters include gas and water production rates, reservoir pressure, and recovery efficiency. Based on the characteristic properties of typical gas fields, physical simulation experiments of constant-rate gas production are conducted on spliced long cores with average permeabilities of 2.300, 0.486, and 0.046 millidarcy (mD). Furthermore, leveraging the multi-point embedded pressure measurement technique, the pressure drawdown propagations and the macroscopic and microscopic characteristics of connate water production at the initial water saturations of 0%, 20%, 40%, and 55% are investigated. By connate water, we mean water that occurs naturally within the pores of rock. Pre- and post-experiment core weighing and nuclear magnetic resonance testing are performed. In addition to the mercury injection tests, the results indicate that during gas reservoir depletion, connate water primarily stems from macropores and mesopores, with micropores and nanopores capturing water through capillary imbibition. Moreover, lower permeability and higher initial water saturation lead to greater pressure gradients, increased connate water production, and reduced recovery efficiency. Reservoirs with permeabilities below 0.1 mD are significantly affected by connate water, exhibiting steep pressure profiles. Owing to connate water, the near-wellbore pressure quickly decreases, while distant reservoir pressure barely decreases, implying a limited drainage area. To enhance the recovery efficiency, measures like infill drilling and reservoir stimulation are recommended for low-permeability gas reservoirs.

Induced CaCO3 mineral formation based on enzymatical calcification for bioremediation under different pressure conditions

Enzymatically induced carbonate precipitation (EICP) is widely studied as a promising technique for soil stabilization and consolidation. Most of the studies of biomineralization are carried out at a normal pressure. However, several practical application fields are in high-pressure environmental conditions, which affect treatment effects. In this study, a new high-pressure research apparatus has been constructed and used to provide a maximum confining pressure of 20 bar for sand solidification. In addition, the N-(n-butyl) thiophosphoric triamide (NBPT) addition was proposed to improve the solidification homogeneity at higher pressures. The formed sand columns demonstrated the feasibility of the constructed apparatus for high-pressure sand solidification. The permeabilities of EICP or EICP-NBPT treated specimens both decreased during the treatment regardless of different confining pressures. The increase of confining pressure decreased pore sizes, eventually leading to smaller CaCO3 contents in specimens. With the confining pressure increasing from 0 to 12 bar, the increasing rate of strength for the sample with EICP treatment was 75%, while decreased to 35% and 12% at 16 bar and 20 bar, respectively. The NBPT addition resulted in smaller differences of sonic time values and CaCO3 contents at different parts, achieving higher strengths. The sample with EICP-NBPT treatment had the largest strength at 16 bar. In this study, the difference of strength was attributed to the combined effects of solidification homogeneity and confining pressure. The results demonstrated that the EICP or EICP-NBPT treatments in this study had several promising applications potentials: improving wellbore integrity, reducing near-wellbore pressure loss, and enhancing CO2 sequestration, which benefit the petroleum industry.

Multiphysics coupling study of near-wellbore and reservoir models in ultra-deep natural gas reservoirs

Understanding the changes of the near-wellbore pore pressure associated with the reservoir depletion is greatly significant for the development of ultra-deep natural gas reservoirs. However, there is still a great challenge for the fluid flow and geomechanics in the reservoir depletion. In this study, a fully coupled model was developed to simulate the near-wellbore and reservoir physics caused by pore pressure in ultra-deep natural gas reservoirs. The stress-dependent porosity and permeability models as well as geomechanics deformation induced by pore pressure were considered in this model, and the COMSOL Multiphysics was used to implement and solve the problem. The numerical model was validated by the reservoir depletion from Dabei gas field in China, and the effects of reservoir properties and production parameters on gas production, near-wellbore pore pressure and permeability evolution were discussed. The results show that the gas production rate increases nonlinearly with the increase in porosity, permeability and Young’s modulus. The lower reservoir porosity will result in the greater near-wellbore pore pressure and the larger rock deformation. The permeability changes have little effect on geomechanics deformation while it affects greatly the gas production rate in the reservoir depletion. With the increase in the gas production rate, the near-wellbore pore pressure and permeability decrease rapidly and tend to balance with time. The reservoir rocks with higher deformation capacity will cause the greater near-wellbore pore pressure.

Evaluation of mass transfer coefficient for gas condensates in porous systems: Experimental and modeling

The gas condensate reservoirs are significant resources of energy for various municipal and industrial purposes. An unfavourable phenomenon attributed to this kind of reservoirs is liquid drop-out due to excessive near-wellbore pressure drop during production. Gas injection is normally employed to recover the liquid loss in the underground formation. The amount of condensate recovery is determined by assuming a thermodynamic local equilibrium, which seems irrational due to the limited contact area, high velocity, and low residence time for fluids around the wellbore. In this work, a series of experiments are conducted based on the Taguchi design of experiment (DOE) to study the steady-state mass transfer during gas injection. Three injection gases (CO2, N2, and CH4), three liquids to represent the liquid condensate (C5, C6, and C7), and three mean grain sizes within the range of 150–300 μm are the vital design variables of the experiments where a broad range of gas velocity (0.00472–0.0283 cm/s) is employed. Results of Taguchi DOE approach are then analyzed to find the optimum design levels and influence/contribution of each factor. The experimental data are utilized to develop new models for estimation of the mass transfer coefficient in terms of Schmidt number (Sc), Peclet number (Pe), normalized velocity, and mean grain size. The comparison between the modeling results and real data confirms the reliability and precision of the proposed correlations. Based on the research outputs, the injection rate (60% contribution factor) and grain size (nearly 10% contribution factor) have the highest and lowest effects on the mass transfer coefficient in porous systems, respectively. It is also found that the difference between the equilibrium concentration and the actual concentration of volatile component in the gas phase increases as the gas velocity increases. Based on the DOE, the optimal design levels for the injection rate, gas type, liquid type, and mean grain size are 12 cm3/min, C1, C5, and 300 μm, respectively. The new models provide accurate/reliable mass transfer coefficient (R2 = 0.9906) for non-equilibrium mass transfer cases to simulate re-vaporization of condensate into the gas phase, while implementing gas injection into the gas condensate reservoirs.

The Effect of Resin-Coated Proppant and Proppant Production on Convergent-Flow Skin in Horizontal Wells With Transverse Fractures

Summary In the last decade, many gas reservoirs with permeabilities from 0.1 to 10 md have been developed with horizontal wells with transverse fractures. The potential negative effect of convergent flow in the fractures seems to have been forgotten. The widespread use of resin-coated proppant (RCP) in offshore wells appears to make this problem worse. Using both case studies and reservoir simulations, we examine why RCP could make the problem of convergent flow worse compared with uncoated proppant. Several North Sea horizontal and deviated multifracture gas wells that used RCP and had a significant mechanical skin are presented. Pressure-buildup data confirm the presence of a near-wellbore pressure drop in the fractures. Reservoir simulation with a fine grid reproduces the observed pressure drop because of convergent flow, using realistic proppant-pack permeabilities with gel damage. The effect of proppant production on the convergent-flow skin is shown using production data before and after discrete proppant-production events, demonstrating how proppant production has a beneficial effect on removing convergent-flow skin. We also compare the performance of a new horizontal multifracture well to the original discovery well in the same location, in which a vertical well was fracture stimulated with uncoated proppant and had comparable productivity. If there is a large convergent-flow skin in a fracture with uncoated proppant, this usually leads to some proppant production, which could create “infinite conductivity” channels at the perforations. This removes the convergent-flow pressure drop. If RCP is used to prevent proppant flowback, such channels cannot form easily, and convergent flow acts as a downhole “choke” on production. This “choke” can produce a significant positive skin. In the worst case, a horizontal multifracture well with three or four transverse fractures can produce the same as a fully perforated vertical well with a single fracture. On the basis of a number of real-world incidents of proppant production during post-fracture cleanup, we show strong evidence that a small amount of proppant production can result in an increase in well productivity index (PI) and a decrease in apparent fracture skin. Convergent flow is the most likely mechanism to explain this. In this paper we highlight the potential reduction in well productivity from using RCP for fracturing in gas wells (0.1 to 10 md) with limited inflow area (transverse or oblique fractures), where convergent-flow pressure loss is significant. We show the potential positive effect of small amounts of proppant production in such cases, forming infinite-conductivity channels and removing the convergent-flow skin.

Results of hydraulic fracturing design improvements and changes in execution strategies for unconventional tight gas targets in the Cooper Basin, Australia

Tight gas stimulations in the Cooper Basin have been challenged by strike–slip to reverse stress regimes, adversely affecting the hydraulic fracturing treatment. These stress conditions increase borehole breakout and affect log and cement quality, create more tortuous pathways and near-wellbore pressure loss, and reduce fracture containment. These factors result in stimulation of lower permeability, low modulus intervals (e.g. carbonaceous shales and interbedded coals) versus targeted tight gas sands. In the Windorah Trough of the Cooper Basin, several steps have been employed in an ongoing experiment to improve hydraulic fracturing results. First, the wellbore was deviated in the maximum horizontal stress direction and perforations shot 0 to 180° phased to better align the resulting hydraulic fractures. Next, existing drilling and logging-while-drilling data were used to train a machine learning model to improve reservoir characterisation in sections with missing or poor log data. Finally, diagnostic fracture injection tests in non-pay and pay sections were targeted to specifically inform the machine learning model and better constrain permeability and stress profiles. It is envisaged that the improved well and perforation alignment and better targeting of intervals for the fracturing treatment will result in lowered tortuosity, better fracture containment, and higher concentrations of localised proppant, thereby improving conductivity and targeting of desired intervals. The authors report the process and results of their experimentation, and the results relative to the offsetting vertical well where a typical five-stage treatment was employed.

Performance-Based Comparison for Hydraulically Fractured Tight and Shale-Gas Reservoirs With and Without Non-Darcy-Flow Effect

Summary Reservoir performance of hydraulically fractured tight and shale-gas formations is affected by an extensive range of parameters. Non-Darcy flow is one of these parameters, characterized by a significant effect on near-wellbore pressure drop for horizontal wells and near-fracture tips for hydraulic fractures (HFs). Non-Darcy flow develops in porous media when the velocity of reservoir fluid becomes extremely high because of continuous narrowing in the cross-sectional area of flow and the convergence of flow streamlines. As a result, the inertial forces could be considered the major contributor to the total pressure drop required by fluids to move from the outer drainage area toward the wellbore. Pressure drop, caused by non-Darcy flow, is described by the Forchheimer (1901) equation, wherein the deviation from Darcy's law is proportional to the inertial factor (β), which in turn is a function of porous-media characteristics such as permeability and porosity. This paper investigates the effect of non-Darcy flow, represented by the non-Darcy-flow coefficient (D) and/or the rate-dependent skin factor (DQsc), on pressure profiles, flow regimes, and productivity indices (PIs) of multiple HFs that propagate in tight and shale-gas reservoirs. This paper also introduces a new simplified technique for estimating both DQsc and D by knowing bottomhole flowing pressure and cumulative production at any time. For this purpose, a multilinear-flow-regime model was generated and modified for the existence of non-Darcy flow. A comparison for reservoir performance with and without non-Darcy flow was conducted for different reservoir configurations, including the reservoir-drainage area (2xe and 2ye), fracture conductivities, fracture dimensions, and fracture-propagation ratios. A set of plots has been developed for estimating the rate-dependent skin factor depending on production time with respect to cumulative PI. The outcomes of this study can be summarized as understanding the conditions at which non-Darcy flow could have considerable effects on reservoir performance; estimating the deviation in PI caused by the existence of non-Darcy flow from the cases where Darcy flow is the dominant; and introducing a new technique to estimate DQsc and D. The most interesting points in this study are the ability to estimate these two parameters without the need for experimental studies or use of an empirical model; that all flow regimes expected to develop in the entire life of reservoirs are not affected by non-Darcy flow, unlike pressure behaviors and PI; and that the PI is constant for high values of DQsc at early-time production and sharply declines at later production time.

Choke-Management Strategies for Hydraulically Fractured Wells and Frac-Pack Completions in Vertical Wells

Summary In this study, a quantitative method is presented for the selection of a choke-management strategy that minimizes the risk of the predominant failure mechanisms in hydraulically fractured wells and frac-pack completions. In unconventional resources, an improper choke-management strategy may trigger proppant crushing or the flowback of proppant, resulting in fracture closure and loss of production. In frac packs and high-rate water packs, an abrupt increase in the rate (or drawdown) may induce completion damage, resulting in impaired production and sand production and requiring excessive and costly workovers. Choke-management strategies should aim to minimize near-wellbore pressure gradients along the fracture, thus making proppant flowback and loss of fracture conductivity or connectivity with the wellbore less likely to occur. Choke-management strategies are compared for a wide range of formation and fracture properties, including fluid properties, matrix permeability, fracture conductivity, and fracture length. Results indicate that in unconventional formations (k < 0.01 md) there is a unique choke-management strategy that consistently appears to be the best. The methodology is coupled with previous studies that have focused on determining the critical pressure gradient for which proppant flowback is observed. In frac packs and high-rate water packs, completion failure may occur because of excessive fluid velocities along the frac pack or exaggerated pore-pressure gradients at the completion sandface. Results indicate that the selection of the optimal choke-management strategy is similar to that of openhole completions, with beanup operations achieving a relatively higher reduction in pressure gradients for the case of low values of dimensionless fracture conductivity. The greatest reduction in pressure gradients can be achieved by considering beanup operations during completion design. The results of this study provide, for the first time, a clear methodology for selecting choke-management strategies in hydraulically fractured wells and frac-pack completions for a wide range of reservoir and fluid properties. A general framework for beanup operations is defined and then used to compare beanup strategies for hydraulically fractured and frac-pack completions. It is hoped that this paper will contribute a theoretical foundation to the current diverse operator practices.

The near-wellbore pressure calculation model incorporating thermochemical effect

The potential difference of hydraulic pressure, solute concentration and temperature between the drilling fluid and the formation fluid can induce the flow of solvent and cause changes in the pore pressure during drilling a tight formation, which may result in wellbore instability. According to the continuity equation of fluid, the pore pressure calculation model considering the effect of thermochemical coupling is established and the solution of the pore pressure in the Laplace domain is given. Using this model, the effects of the temperature, solute concentration and viscosity of drilling fluid on the pore pressure around the wellbore are simulated. The results show that, when the wellbore pressure is higher than the formation pressure and the solute concentration of the drilling fluid is larger than that of the formation fluid, the near-wellbore pore pressure will decrease first and then increase during drilling a tight formation, and increasing the drilling fluid temperature will decrease the pore pressure. Increasing the solute concentration of the drilling fluid can inhibit the increase of the pore pressure.

Using a 3D hydraulic fracture simulator to assess the impact of perforation design on high near-wellbore pressure loss in the Cooper Basin

Fracture stimulation in the Cooper Basin has long been challenged by high near-wellbore pressure loss (NWBPL) present in hydraulic fracture treatments. Though many strategies have been applied to either mitigate or prevent this, the industry is still in need of a broadly applicable, economic and practical solution. An approach that has significant potential, and targets NWBPL from its foundation, is perforation design. Perforation design has been shown in the past to have a significant effect on the initiation of a fracture and the success of its continued propagation. A commercial 3D hydraulic fracture simulator has been applied to data from Cooper Basin wells. These vertical wells contain tight sand intervals and are characterised by high differential stress. A sensitivity analysis has been performed using industry-standard GOHFER software, focusing on parameters including perforation diameter, shot density, interval length, number of intervals, and shot spacing. Though many previous authors have suggested that perforation design has limited impact on pressure loss, the analysis performed in this study indicates that there are methods inherent in perforation design that can impact on high NWBPL. In particular, this study has noted a potential for many cost-saving strategies that could be applied to future completions. This is an innovative study that examines the underlying links between perforation design and the resulting near-wellbore pressure loss. It focuses on problematic areas of the Cooper Basin in the hope that by examining these links useful recommendations can be made to the industry.

Common Mistakes Associated With Diagnostic Fracture Injection Tests

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 169539, ’Diagnostic Fracture Injection Tests: Common Mistakes, Misfires, and Misdiagnoses,’ by R.D. Barree, SPE, J.L. Miskimins, SPE, and J.V. Gilbert, SPE, Barree & Associates, prepared for the 2014 SPE Western North American and Rocky Mountain Joint Regional Meeting, Denver, 16-18 April. The paper has not been peer reviewed. During the last 20 years, diagnostic fracture injection tests (DFITs) have evolved into commonly used techniques that can provide valuable information about reservoirs and hydraulic-fracture-treatment parameters. Thousands of tests are run every year in both conventional and unconventional reservoirs. However, many factors associated with data collection and analysis can result in poor or incorrect results. This paper attempts to describe some of the common problems and to help prevent some common errors often observed in DFIT execution and analysis. Introduction DFITs are small pump-in treatments performed to gather data to help design follow-up hydraulic-fracturing treatments and characterize a reservoir. A generic DFIT is shown in Fig. 1. The wellbore is first filled at a low to moderate rate until a positive surface pressure response is observed. With low- to- moderate wellbore compressibility, the pressure should rise quickly until initial breakdown occurs. Breakdown will be indicated either by a sharp drop in pressure as a new fracture initiates (as at Number 1 in Fig. 1) or by a plateau in pressure as existing fractures are opened and extended. Once a breakdown event is observed, the injection rate should be increased to the maximum rate allowed by available horsepower or to 75% of the planned treatment rate of the main fracture treatment, whichever is achievable. A constant rate is then held for 3–5 minutes (Number 2 in Fig. 1), after which a rapid step-down can be conducted. The step-down test is separate from the actual DFIT but is commonly run at the end of the pump-in to determine perforation and near-wellbore frictional pressure losses. The rate is then immediately reduced to zero to obtain the instantaneous shut-in pressure (ISIP), shown as Number 4, and the falloff pressure is monitored for as long as possible or as long as necessary to acquire the desired data. Even when high friction is not expected, the step-down is recommended to make identification of ISIP easier.

Well productivity in an Iranian gas-condensate reservoir: A case study

This work is another step forward in our understanding of the dynamics of condensate buildup around wellbores in gas condensate fields. For this purpose one of the unique and huge Iranian gas condensate reservoirs is selected. The effects of condensate bank on the gas and condensate productivity and also the reservoir performance have been investigated throughout a simulation study. The productivity of the wells in the moderately rich gas condensate reservoir was observed to have initial rapid decrease and then reach a relatively constant value and after that a second decrease as the reservoir was depleted. Compositional simulation clarified the reasons for this uncommon productivity change. During early production, a ring of condensate rapidly formed around wellbore when the near-wellbore pressure decreased below the dew point pressure of the reservoir fluid. Moreover, relative permeability effects caused the saturation of condensate in this region to be considerably higher than the maximum condensate predicted by the PVT laboratory work. Gas productivity also decreased as the effective permeability to gas was severely reduced due to this high condensate saturation in the ring. After condensate formation throughout the reservoir due to pressure reduction below dew point, the gas flowing into the ring became leaner causing the condensate saturation in the ring to decrease. This increased the effective permeability of the gas. On the other hand, the reservoir pressure drop leads to less productivity which caused the gas productivity to reach a constant value. Changes in gas and condensate compositions in the reservoir also impacted gas productivity. As the result of this study it could be mentioned that the gas production rate may stabilize, decrease or possibly increase, after the period of initial decline. This is controlled primarily by the condensate saturation near the wellbore which would decrease in the near wellbore region because of the leaner gas entering this region and also partial vaporization. In addition to the gas production rate, the composition change should also be considered in the sale contracts.

Phosphonic/Hydrofluoric Acid: Tortuosity Remediation for Fracturing Treatments

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 152624, ’Phosphonic/Hydrofluoric Acid - A Promising New Weapon in the Tortuosity-Remediation Arsenal for Fracturing Treatments,’ by Ricardo Melo, James Curtis, SPE, Julio Gomez, SPE, Alexandre Melo, Fernando Garcia, and Helio Pedrosa, SPE, Baker Hughes, prepared for the 2012 SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, 6-8 February. The paper has not been peer reviewed. Tortuosity is one of the biggest challenges for shale and tight gas hydraulic-fracturing treatments, leading to high near-wellbore frictional pressure loss, premature screenouts, reduced treating rates, and poor production results. A new solution demonstrated substantial success in overcoming particularly stubborn tortuosity problems. The method builds on the use of a nondamaging, single-stage phosphonic-/hydrofluoric-acid system (SAS) for matrix-stimulation treatments. Introduction Hydraulic fractures are initiated and kept open by pressure. The pressure is transmitted by the pumped fluid, so as the pumping rate increases, so does the pressure. Following this process, stress is induced in the rock around the well-bore. If the pumping rate continues to increase, so does the stress. Eventually, a stress limit will be reached at which point the rock can no longer sustain the applied stress and it fractures. Over a long perforated interval or in deviated wells, fractures can initiate anywhere, provided that the fluid pressure gradient exceeds the fracture gradient, either to initiate fractures or to reopen natural fractures. Generally, the rock will fail at its weakest point and the fracture will initiate there. However, if the pressure continues to rise, additional fractures may be formed because of changes in near-wellbore stress, as shown in Fig. 1. Later, the fracture will reach its natural direction, according to the formation’s stress orientation. Every perforation is a potential source of fracture initiation. Many of these fractures will be very small, but some may be large enough to take a significant portion of the treatment fluid. Despite the artificial-stress environment generated around the well-bore, hydraulic-fracture treatments tend to produce a small number of larger fractures. Because of increased stresses around the fracture faces, individual fractures tend not to join together. The stress regime around the fracture faces can cause fractures to repel each other. However, with the complex stresses around the wellbore and perforations, fractures can join together at some point, connecting through narrow paths, sometimes with bends toward a main large fracture. Therefore, the treating fluid must flow from a region containing many small narrow fractures to a region containing a few large fractures. In following this path, the fluid must move through a series of convoluted, bending, and narrow fractures (i.e., a tortuous path). This tortuosity can produce a significant pressure loss, resulting in a smaller-than-expected fracture or in early screenout. Such screenouts might also be caused directly by tortuosity because these channels through the rock often are not wide enough for the proppant to pass through, causing the proppant to bridge and prevent further flow of proppant.

Deepwater Workover Experience With Extreme Hydrostatic Overbalance

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 134378, ’Deepwater Workover Experience With Extreme Hydrostatic Overbalance, 2002-2009’ by G. Myers, SPE, D. Cahill, SPE, P. Clay, SPE, B. Esquinance, B. Smith, SPE, and R. Zeringue, SPE, Shell E&P Co.; C. Davis, SPE, Shell International E&P; and T. Kenney, Crown Consulting, originally prepared for the 2010 SPE Annual Technical Conference and Exhibition, Florence, Italy, 19-22 September. The full-length paper presents planning and execution details for fluid-loss control during workovers with “extreme-hydrostatic-overbalance” (EHO) conditions (i.e., between 1,500 and 4,000 psi). Actual results for several wells from three deepwater fields in the Gulf of Mexico (GOM) are included. The information is applicable to operators that face similar requirements to maintain well control throughout the workover, mitigate any damage to the installed sand control or reservoir, and complete removal of the fluid-loss barrier to re-establish production. Introduction For many years, the industry has dealt with large hydrostatic overbalances in a variety of ways during workovers. Onshore, operators of tight gas fields initially may pump fluid to kill the well for rig up, then add fluid intermittently during the job as required to work safely. Offshore, operators of shallow-water, higher-permeability fields may initially kill the well with seawater for rig up, then continuously feed or “let the well drink” seawater to maintain hydrostatic overbalance during the job. The full-length paper focuses on direct-vertical-access (surface tree) wells in deepwater GOM fields. These wells are characterized by high-permeability, thick sand intervals; downhole sand control; and very high fluid-loss rates after perforating or stimulation. Profitability is tied to maintaining high production rates without significant solids production. It is the combination of extreme hydrostatic overbalance, high permeability, downhole sand control, and high production potential that makes these wells so challenging. Subsea wells in deepwater GOM fields must be handled differently because of the potential for riser collapse, use of riser fill valves, and the daily cost of floating rigs. EHO is a term used to describe conditions significantly outside the normal. It is common to execute workovers in the GOM with 200- to 300-psi hydrostatic overbalance—that is, the difference between the hydrostatic-column pressure at the perforations and the near-wellbore reservoir pressure. Depending on the reservoir-drive mechanism, workovers in later life may be executed with 300- to 800-psi hydrostatic over-balance (moderate) or 800- to 1,500-psi overbalance (high). The term EHO is used to describe wells with 1,500-psi or greater overbalance and is not a precise definition. Depending on the job, 1,200-psi hydrostatic overbalance may require similar planning. To date, jobs have been planned with overbalance approaching 4,000-psi, typically using seawater as the workover fluid.

Wellbore-Stability Performance of Water-Based-Mud Additives

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 116139, "Wellbore Stability Performance of Water Base Mud Additives," by R.T. Ewy, SPE, and E.K. Morton, SPE, Chevron Energy Technology Company, originally prepared for the 2008 SPE Annual Technical Conference and Exhibition, Denver, 21–24 September. The paper has not been peer reviewed. A critical property for many water-based muds (WBMs) is the ability to prevent a near-wellbore pore-pressure increase in shales. By slowing or preventing this pressure increase, an overbalance pressure is maintained that promotes wellbore stability. Using a device that simulates downhole rock stress and overbalance fluid-pressure conditions and preserved shale samples, four different muds containing different additives were tested. Direct measurements of shale pore pressure vs. time were obtained, representing the pore pressure inside the near-wellbore region. Introduction One of the main shale-instability mechanisms that occurs with water-based drilling fluids is the wellbore pressure penetrating into the shale pore space. This increases the near-wellbore pore pressure and reduces the overbalance. This reduction of overbalance, which acts like a support pressure for the hole, can result in shale failure and wellbore instability. This pressure penetration cannot be prevented with standard filtration additives because shale pores are extremely small, approximately 0.01 µm, and shale permeability is extremely low, typically approximately 0.01 microdarcy or less. Experimental Each sample was cut from preserved downhole shale core and had never been contacted by water or brine. By avoiding "premature" contact with aqueous fluids, a meaningful swelling response on the shale as caused by the drilling fluid can be measured. Each mud test was performed on a new, preserved shale sample. The shale used for this study contains approximately 70% clay, approximately one-third to one-half of which is kaolinite, with the remainder being mostly mixed-layer illite/smectite. All samples were equilibrated to 96% activity in a vacuum desiccator before testing. This downhole shale core was cut with an oil-based mud and was kept fully preserved. The samples were cut and end-ground using decane, and they were not contacted by any aqueous fluid. Fig. 1 in the full-length paper illustrates the inner part of the shale/fluid-interaction test apparatus. The samples were right-circular cylinders with a 0.75-in. diameter and 0.5-in. length. The sample was surrounded by an impermeable jacket, which also extends to the top and bottom end caps. This allows a confining pressure to be applied to the sample using hydraulic oil (the entire illustrated section in Fig. 1 sits inside a pressure vessel). The confining pressure represents the in-situ stress acting on the shale near the wellbore.

Wellbore-Strengthening Technique for Drilling Operations

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 105809, "Further Development, Field Testing, and Application of the Wellbore- Strengthening Technique for Drilling Operations," by Giin-Fa Fuh, SPE, and Dave Beardmore, SPE, ConocoPhillips Co., and Nobuo Morita, SPE, Waseda U., prepared for the 2007 SPE/IADC Drilling Conference, Amsterdam, 20-22 February. A significant increase in formation fracture resistance can be achieved as a result of a fracture sealing or plugging mechanism induced by a particle "screenout" effect resulting from the drilling fluid being loaded with an adequate amount of narrowly sized granular materials. Such an increase in formation fracture resistance is particularly valuable in helping to drill through depleted zones without losing fluid, strengthening the weaker formations that usually require additional casing strings for protection, avoiding lost circulation during cementing operations, and drilling high-angle well sections with high mud weights that normally would not be possible because of low formation fracture gradients. Introduction Lost circulation is perhaps the most costly mud-related drilling problem. Not only is rig time lost, but large volumes of expensive drilling fluids are lost to the formation. Lost circulation also can lead to severe well-control incidents. In response, several technologies referred to as "wellbore strengthening" (WS) are being developed to prevent or correct lost circulation. WS means that the breakdown pressure of the wellbore is greater after the treatment than before. These methods include use of special granular material, heating the wellbore, and use of rigid-plug-forming pills. The full-length paper focuses on a WS method that uses mud with special bridging and fluid-loss formulations. In the mid-1980s, a joint-industry project (JIP) was conducted to determine why oil-based mud apparently caused a lower fracture gradient than water-based mud (WBM). Data from this JIP were analyzed, and it was determined that they did not fit ordinary fracturing models of the time. These researchers noted that certain lost-circulation materials (LCMs) actually seemed to increase the pressure required for fracture propagation to more than what was seen with untreated drilling mud. They conducted laboratory tests outside the JIP to verify their observations. The result was the development of a loss-prevention material (LPM) that was found to inhibit the extension of a fracture tip. LPM was tested in the field several times and was quite successful. It was able to increase the wellbore break-down pressure in several cases, and subsequent application of the technology has allowed a casing string to be skipped in several cases. The technique affects only the near-wellbore break-down pressure, not the far-field fracture gradient.

Using geological information to optimize fracture stimulation practices in the Cooper Basin, Australia

Fracture stimulation treatments of tight formations in the Cooper Basin can be associated with hydraulic fracture complexity that results in abnormally high treating pressures, low proppant placement and poor economic success. Pre-completion (image log and rock testing data) and post-completion data (fracture stimulation pressure decline plots) were reviewed in 13 treatment zones from the Cooper Basin. Rock strength, image log and stimulation data were available for seven of those zones. From this analysis, a distinct relationship between rock properties (shear and tensile rock strength), geological weaknesses (natural fractures and other fabrics) and fracture stimulation complexity (net pressure, near-wellbore pressure loss and pressure-dependent leak-off) was observed. It is proposed that high in situ stress ( S hmin ≧0.8 psi ft −1 ; 18.1 MPa km −1 ), a large contrast in tensile strength between intact rock ( T >1015 psi (7 MPa)) and pre-existing weaknesses in the reservoir ( T ∼0) promote the propagation of fracturing fluid along multiple fracture pathways, and thus abnormally high treating pressures, low proppant placement and poor economic success during fracture stimulation treatments in the Cooper Basin. The methodology used to predict in situ stress and hydraulic fracture complexity herein presents a potential generic approach that can be used in similar basins where hydraulic fracture complexity is a problem or where conventional stimulation practices are unsuccessful.

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.

Theoretical Model and Numerical Investigation of Near-Wellbore Effects in Hydraulic Fracturing

Summary The high near-wellbore pressure drop, which has frequently been reported in fracture treatments, is indicative of ineffective communication between the wellbore and the fracture. Although numerous observations of such effects have been published, few attempts have been made to understand them. This article describes three possible mechanisms of near-wellbore effects [perforation phasing misalignment-induced rock pinching, perforation pressure drop, and fracture reorientation (deviation tortuosity)] and their implementation in a numerical fracture simulator. Typical signatures of all three effects in fracture treatment records are shown, and a method is proposed by which to distinguish them. Perforation phasing misalignment has been identified as a cause of near-wellbore restriction. Because the fracture does not always initiate at the perforation, the fluid must communicate with the fracture through a narrow channel (microannulus) around the casing. Here we describe this pinching effect and show that it is related to the contact stress between the cement and the formation. Perforation pressure drop and deviation tortuosity, which have previously been proposed by other authors, have also been modeled. They have been incorporated into the simulator, together with the phasing misalignment effect, to allow investigation of the differences in response between the different mechanisms. Results of simulating the effects of erosion of near-well effects on treating pressure are also shown. Comprehensive field cases studies exhibiting near-wellbore mechanics are presented. The relevant near-wellbore mechanism is first identified and the downhole pressure is then simulated, demonstrating the validity of the model.

A Well Model Based on the Pseudosteady-State Pressure Distribution in the Finite-Element Simulation of Depletion Reservoirs

ABSTRACT In calculating the long-time performance of closed reservoirs using a finite-element method, an accurate and efficient simulation highly depends on a proper grid selection. The treatment of wells can particularly have a strong influence on computed results. For the efficient simulation of field-scale problems with multiple wells of differing production rates, a well model was introduced to reduce the concentration of elements near wells. The model was based on a near-wellbore pressure distribution during pseudosteady state, leading to a logarithmic type of approximation. Well performance calculated in the well model is correlated to the conditions in the appropriate location from the actual well. This approximation overcomes an inaccuracy for fluid flow calculation in the vicinity of wells and can be implemented easily in existing grids. A numerical model based on the approach was developed for a simulation study. Numerical examples are presented to show the accuracy and computational efficiency resulting from the use of the proposed well model. With the approximation, it was possible to reduce the number of elements and grid nodes up to 80%. The level of error due to the approximation was in an acceptable range for all cases considered. The key element to the accurate calculation is the ratio of the effective radius of the near-well region compared to the distance to the nearest boundary.