Bottom-hole Pressure Conditions Research Articles

Analyzing the performance of single-cutter cutting rock under bottom-hole pressure conditions

Addressing the ambiguity surrounding the process of crack initiation and propagation in rock subjected to confining pressure and hydrostatic pressure, this study integrates laboratory experiments with numerical simulations. First, an analysis is conducted on the cutting force, rock fragmentation energy consumption, rock chip size, and distribution of cutting stress in rocks simultaneously exposed to confining pressure and hydrostatic pressure. Subsequently, an internal crack propagation analysis model for rock is established using the finite discrete element method, and the accuracy of this model is verified through experimentation. The process and characteristics of internal crack propagation during the cutting process are analyzed. Lastly, the variation characteristics of cutting forces under different cutting parameter conditions are compared. The findings indicate that, under identical cutting conditions, confining pressure reduces the degree of granite rock fragmentation, increases the presence of powdery rock debris, and mitigates force fluctuation characteristics, leading to an approximate 17% increase in energy consumption of rock breaking. The presence of confining pressure promotes the generation of micro-cracks within the rock, but restricts the expansion of primary cracks. Notably, shear cracks ahead of the cutting cutter and tensile cracks beneath the cutting path are conspicuously diminished, thereby augmenting the difficulty of rock failure. The elevation of confining pressure and cutting depth emerges as the principal factors contributing to elevated cutting forces, with cutting forces exhibiting exponential growth with increasing confining pressure. At a hydrostatic pressure of 9 MPa, cutting forces escalate by 50 %. Moreover, substantial cutting depth induces discontinuity in the rock failure mechanism. Stress during cutting predominantly concentrates in the vicinity of the PDC cutter front and beneath the cutting trajectory, extending along the advancement direction of the PDC cutter and below the cutting path. These results offer valuable insights for optimizing drilling parameters under confining pressure conditions.

Monitoring and Characterization of Gas Migration in Oil-Based Mud Using Fiber-Optic DAS and DTS

Summary Understanding gas dynamics in mud is essential for planning well control operations, improving the reliability of riser gas handling procedures, and optimizing drilling techniques, such as the pressurized mud cap drilling (PMCD) method. However, gas rise behavior in mud is not fully understood due to the inability to create an experimental setup that approximates gas migration at full-scale annular conditions. As a result, there is a discrepancy between the gas migration velocities observed in the field as compared to analytical estimates. This study bridges this gap by using distributed fiber-optic sensors (DFOS) for in-situ monitoring and analysis of gas dynamics in mud at the well scale. DFOS offers a paradigm shift for monitoring applications by providing real-time measurements along the entire length of the installed fiber at high spatial and temporal resolution. Thus, it can enable in-situ monitoring of the dynamic events in the entire wellbore, which may not be fully captured using discrete gauges. This study is the first well-scale investigation of gas migration dynamics in oil-based mud with solids, using optical fiber-based distributed acoustic sensing (DAS) and distributed temperature sensing (DTS). Four multiphase flow experiments conducted in a 5,163-ft-deep wellbore with oil-based mud and nitrogen at different gas injection rates and bottomhole pressure conditions are analyzed. The presence of solids in the mud increased the background noise in the acquired DFOS measurements, thereby necessitating the development and deployment of novel time- and frequency-domain signal processing techniques to clearly visualize the gas signature and minimize the background noise. Gas rise velocities estimated independently using DAS and DTS showed good agreement with the gas velocity estimated using downhole pressure gauges.

An investigation of fatigue response of well cement under cyclic loading and impact on zonal isolation performance

Cyclic bottomhole pressure fluctuation is very prevalent in modern well construction and enhanced petroleum recovery applications and poses a great challenge to annular seal integrity and successful zonal isolation, even in cases where the cement seal exhibits excellent initial quality. Thus, annular sealants must be designed to mitigate or minimize the deleterious effects of cyclic pressure fluctuations on the annular seal. Optimal cement designs for this purpose require a proper understanding of damage modes and mechanisms associated with a cyclic pressure regime, as well as the impact of the cement mechanical integrity evolution on the leakage of the cemented annulus. Using four cement formulations with distinct mechanical and microstructural properties, we investigated the mechanical integrity evolution and leakage characteristics of cemented pipe specimens subjected to confinement pressure fluctuations. Via microscopic inspection of the cement/pipe interface after pressure cycling and permeability measurements during pressure cycling, we attempted to correlate cement properties with leakage and suggest a recommendation for optimal cement design and successful zonal isolation in wellbores subjected to cyclic pressure. Test data indicate that under high enough pressure variation, interfacial cracking at the cement pipe interface is unavoidable and the cement seal's ability to maintain zonal isolation will be dependent on the microstructural morphology and microscale mechanical resilience of the cement formulation. Stiffer conventional cements also appear to have a higher chance of leakage through non-interfacial fractures than their more flexible counterparts. Latex cements show great promise for effective zonal isolation under cyclic bottomhole pressure conditions and should be studied in more detail.

Low Equivalent Circulating Density Organoclay-Free Invert Emulsion Drilling Fluids

AbstractHigh pressure and high temperature (HPHT) wells especially those with narrow pore/fracture pressure gradient margins present challenges in drilling. Maintaining optimum and low rheology for such wells becomes a challenge where a slight change in the bottom-hole pressure conditions can lead to nonproductive time. However, maintaining low viscosity profile for a drilling fluid can pose a dual challenge in terms of maintaining effective hole-cleaning and barite-sag resistance. This paper describes the formulation of 95pcf medium-density organoclay-free invert emulsion drilling fluids (OCIEF) with a low viscosity profile. The fluids gave lower plastic viscosity (PV), which ensured that the fluid presents low equivalent circulating density (ECD) contribution while drilling/circulating. These fluids were formulated with acid-soluble manganese tetroxide as weighting agent and a specially designed bridging-agent package. The fluids were hot rolled at 300 °F and their filtration and rheological properties were measured. The paper describes the static-aging, contamination, and high pressure/high temperature rheology measurements of the fluids at 300 °F. Particle plugging experiments were performed on the fluids to determine the invasion characteristics and the nondamaging nature of the fluids. These organoclay-free invert emulsion fluids (OCIEFs) were then field-trialed in different wells with good results. Field deployment of the 95pcf organoclay-free invert emulsion fluid helped to maintain the required hole stability in the high temperature and high pressure (HTHP) well. The well was displaced to 95pcf production screen test (PST) fluid and completed with a 4 ½ in. sand screen. The paper demonstrates the superior performance of the developed fluid in achieving the desired lab and field performance.

Gas rate decline analysis for boundary-dominated flow with fractal reservoir properties under constant / variable bottom-hole pressure conditions

Current gas rate decline analysis methods in boundary-dominated flow (BDF) are mainly based on Arps' empirical decline models, or the liquid-based analytical models associating with pseudo-variables. Recently, Stumpf and Ayala (2016), and Wang and Ayala (2020) demonstrated that the decline exponents (b) used in Arps’ hyperbolic model can be rigorously estimated in advance for both constant and variable conditions regardless of reservoir properties and before collecting any production data. In this paper, we further investigate the gas rate flow behavior for heterogeneous reservoir, which is characterized by fractal properties. The decline exponents (b) are thus re-derived based on the gas flow rate equation in BDF, and it is shown that the expression of decline exponents can be written in the same format with homogeneous reservoir by defining new productivity indexes. This allows for the application of the step-by-step explicit original-gas-in-place (OGIP) determination methods proposed by Stumpf and Ayala (2016), and Wang and Ayala (2020) in fractal radial flow. However, due to the heavily pressure depletion before BDF for linear flow, the average value of decline exponent (donated as bi) is not available any more. Therefore, our explicit OGIP determination method CANNOT be directly applied, which would lead to the underestimation of the true value if it is blindly used. Finally, several simulated cases are discussed to validate the capabilities of the methodology. The finding of this study can help for better understanding of the gas rate decline behavior in heterogeneous reservoirs.

Rate transient analysis of infinite-acting linear flow by use of piecewise constant diffusivity coefficients

Rate transient analysis (RTA) techniques are developed based on the analytical solutions to the hydraulic diffusivity equation. The diffusivity equation is subject to nonlinearity caused by the dependency of the rock and fluid properties to pressure. In this study, first, we develop a semi-analytical model to solve a nonlinear diffusivity equation for transient linear flow under the constant bottom-hole pressure condition. We use piecewise constant diffusivity coefficients to linearize the diffusivity equation. The domain under consideration is divided into an arbitrary number of subdomains. Each subdomain is assigned with a constant hydraulic diffusivity coefficient. As a result, the nonlinear diffusivity equation is reduced into a set of piecewise linear equations. Further, we propose a new RTA approach using the developed semi-analytical model. We then validate both the semi-analytical model and the RTA approach against direct numerical simulation. The comparison reveals the high accuracy of the developed model in the estimation of reservoir properties, pressure profiles, and flow rates, including the cases with highly pressure-dependent properties. Finally, we apply the proposed RTA approach to the flowback and long-term production data obtained from two horizontal wells to determine the reservoir properties, such as the cross-sectional area to flow and initial permeability. The field applications demonstrate that the proposed RTA approach provides a rigorous avenue for production data analysis of pressure-sensitive formations during transient linear flow.

An Integrated Approach To Optimize Bottomhole-Pressure-Drawdown Management for a Hydraulically Fractured Well Using a Transient Inflow Performance Relationship

SummaryThe purpose of this paper is to determine the optimal strategy of bottomhole-pressure (BHP) drawdown management in a hydraulically fractured well with pressure-sensitive conductivity to remain conductive while maintaining a high enough drawdown to maximize the estimated ultimate recovery (EUR). In this work, a novel permeability-decay coefficient accounting for dynamic conductivity effect (DCE) is proposed to represent the pressure sensitivity in a fracture on the basis of experimental results. Using an existing method, the constant/variable BHP conditions and the hydraulic fractures with DCE are considered in the model. Model verification is performed by comparing with the solutions from the numerical method. Then, the mechanism of fracture closure and its effect on production performance are investigated using the semianalytical solution, and the interplay between pressure drawdown and productivity loss is captured by generating a set of type curves for the transient inflow performance relationship (TIPR).Next, an easy-to-use approach is developed to find the optimal path of BHP decline vs. time, and the practical optimal drawdown is calibrated by capturing the time-lapse behavior, with consideration of the effect of production history on TIPR. It is found that if the relation of decay coefficient and pressure is a linear function, there will be a reversal behavior on TIPR as BHP drawdown increases. That is to say, an operating point exists on the TIPR curves, beyond which the production rate decreases; otherwise, the production rate increases. The operating point is defined as the optimal BHP drawdown at a given time, and the optimal profile of BHP drawdown is achieved by integrating operating points on TIPR curves corresponding to different times. Subsequently, a synthetic case generated by a coupled-geomechanical/reservoir simulator is defined to demonstrate that an optimal BHP-drawdown schedule developed by the semianalytical approach has the ability to enhance ultimate recovery by reducing the effective stress on the stress-sensitive fracture while maintaining the well productivity.

Analytical dual-porosity gas model for reserve evaluation of naturally fractured gas reservoirs using a density-based approach

The development of naturally fractured gas reservoirs often requires the deployment of rigorous techniques for production data analysis incorporating dual-porosity gas behavior. It has been a prominent problem to linearize and analytically solve the governing equations for dual-porosity gas systems. This study applies a pseudo-pressure-based interporosity flow equation to derive a density-based rate-transient analysis method to accurately predict the gas production rate and estimate the amount of original gas in place (Gi) for the systems. The methodology also predicts the gas production rate by transforming the response of its liquid counterpart via a decoupling of the pressure-dependent effects using dimensionless depletion-driven parameters.For the first time, the density-based flowing material balance method is derived for the dual-porosity gas reservoir. More than that, an innovative fracture productivity equation that was missing for the dual-porosity system is derived as well. This study provided detailed derivations for the model and relationship used in past density-based dual-porosity rate-transient analysis. The dual-porosity productivity equation and the relationship between average matrix pseudopressure and average fracture pseudopressure are rigorously derived. The rescaling relationship between the dual-porosity liquid solution and the dual-porosity gas solution is also demonstrated in detail. An appropriate interporosity flow equation for gas is used. Based on that, the results show that the density-based approach is able to successfully capture the dual-porosity behavior of gas for constant bottomhole pressure condition.

A semi-analytical approach for analysis of the transient linear flow regime in tight reservoirs under three-phase flow conditions

The majority of current techniques for production data analysis of hydraulically-fractured horizontal wells only consider single- or two-phase flow conditions. Three-phase flow is expected to occur in many practical scenarios of low-permeability reservoir production when water (frac fluid and/or formation) production is occurring along with hydrocarbon phases. In this paper, a new semi-analytical method is developed to allow production data analysis of wells producing from low-permeability (tight) reservoirs exhibiting three-phase during the transient linear flow period.The proposed technique is based on the modified black oil formulation and is developed by employing the Boltzmann transformation. The modified black oil formulation comprises three highly nonlinear Partial Differential Equations (PDE's) that describe the flow of water, oil and gas in the reservoir. The use of the Boltzmann transformation allows conversion of this set of governing fluid flow PDE's to a set of Ordinary Differential Equations (ODE's) that can be easily solved using numerical techniques such as the Runge-Kutta method. In this paper, oil relative permeability under three-phase flow conditions is modelled using Stone's well-known first model.A theoretical basis for the occurrence of straight lines on a plot of 1/q vs √t for any producing phase is provided herein. The slope of the line is a function of the flowing fluid properties, and the reservoir and fracture characteristics. One important advantage of using the Boltzmann transformation is that the linear flow parameter, xf√k, can be directly estimated as a part of the solution process without the need for defining any complex pseudo-variable transformations. The results demonstrate that the relative error in xf√k estimation is generally less than 10% for different fluid models and relative permeability curves. Moreover, the simultaneous solutions of the ODE's provide the pressure and phase saturations as unique functions of the Boltzmann variable; these can be used to find relationships between pressure and phase saturations that in turn can be utilized for other rate transient analysis applications. The derived pressure-saturation relationships are in excellent agreement with numerical simulation for different three-phase relative permeability models.The significance of this paper is that a new theoretical and practical framework is introduced for the first time to analyze three-phase production data for transient linear flow under constant flowing bottomhole pressure conditions. These conditions are of practical importance for many tight production scenarios where water, in addition to hydrocarbon phases, are mobile in the reservoir. The results are validated using numerical simulation.

Rate Decline Analysis of Vertically Fractured Wells in Shale Gas Reservoirs

Based on the porous flow theory, an extension of the pseudo-functions approach for the solution of non-linear partial differential equations considering adsorption-desorption effects was used to investigate the transient flow behavior of fractured wells in shale gas reservoirs. The pseudo-time factor was employed to effectively linearize the partial differential equations of the unsteady flow response. The production performance of vertically fractured wells in shale gas reservoirs under either constant flow rate or constant bottom-hole pressure conditions was analyzed using the composite flow model. The calculation results indicate that the non-linearities that develop in the gas diffusivity equation have significant effects on the unsteady response, leading to a larger pressure depletion and rate decline in the late-time period. In addition, gas desorption from the shale acts as a recharge source, which relieves the gas production rate of decline. Greater values for the Langmuir volumes or Langmuir pressures provide additional pressure support, leading to a lower rate decline while the flowing well bottom-hole pressure is maintained. The reservoir size mainly affects the duration of the pressure depletion and rate decline. In the case of ignoring the non-linearity and adsorption-desorption effect in the differential equation, a greater rate decline under constant bottom-hole pressure production can be obtained during the boundary-dominated depletion. This work provides a better understanding of gas desorption in shale gas reservoirs and new insight into investigating the production performances of fractured gas well.

Use of rescaled exponential models for boundary-dominated liquid-rich gas flow analysis under variable bottomhole pressure conditions

The analysis of production data from natural gas reservoirs can serve as one of the most powerful tools to estimate remaining reserves and provide a forecast of its future performance. While fundamentals of decline for dry gas reservoirs are well described in literature, those for liquid-rich gas reservoirs are yet to be well-understood. Any predictive model used to analyze these reservoirs must account for the inherent changes in reservoir fluid composition during their producing life due to condensate dropout within the reservoir, once reservoir pressure falls below dew point pressure. This study presents a mathematical model capable of predicting non-linear flow behavior in multiphase gas-condensate reservoirs using rescaled exponential models applicable to boundary-dominated flow regimes under variable bottomhole pressure conditions. We develop a set of analytical solutions for surface oil and total hydrocarbon flowrates, for wells producing under variable bottomhole pressure. We model hydrocarbon production from gas-condensate reservoirs by employing a material balance over produced condensate and total hydrocarbons. In this material balance approach, we use equivalent fluid molar densities in multiphase systems, resulting in analytical equations for the different flowing phases. The developed set of analytical solutions aims at providing an accurate estimate of reservoir behavior and available reserves, which can be used to inform critical economic decisions for further development of the reservoir. The proposed rescaled models minimize assumptions and stay true to the physics of multiphase flow. We demonstrate that the developed analytical model closely predicts the numerical simulation results for the hydrocarbon flowrates as well as the estimated reserves where a wide range of gas-condensate reservoirs, from lean to liquid-rich, is considered.

Transient Coupled Wellbore/Reservoir Model Using a Dynamic IPR Function

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 181691, “A Transient Coupled Wellbore/Reservoir Model Using a Dynamic IPR Function,” by A. Posenato Garcia, The University of Texas at Austin; P. Cavalcanti de Sousa, Texas A&M University; and P.J. Waltrich, SPE, Louisiana State University, prepared for the 2017 SPE Reservoir Simulation Conference, Montgomery, Texas, USA, 20–22 February. The paper has not been peer reviewed. Conventional inflow-performance-relationship (IPR) models are used in coupled wellbore/reservoir transient simulations, even if bottomhole-pressure conditions are assumed to be constant on the derivation of such IPR models. The dynamic IPR model proposed in this paper not only captures the relevant reservoir dynamics from the well perspective but also is computationally more efficient than discretized models using hundreds of gridblocks to simulate the near-wellbore region. Introduction Traditionally, well deliverability is obtained by combining IPR and vertical-flow-performance (VFP) curves. This method was first discussed in 1954 and provides snapshots of the average- bottomhole-flowing-pressure (Pwf) and average-oil-flow-rate (qo) relationships at given times in the life of the well. It fails, however, in accurately portraying the transient behavior of these variables. Transient relationships are important in the design and analysis of pressure-transient tests, design of production tubing and artificial-lift systems, reservoir management, and estimating flow rates from multiple producing zones. Capturing the real behavior of these variables requires coupling the reservoir model and wellbore model. General-use coupled models rely on running reservoir simulations (accounting for near-wellbore effects) and using the output of that run as the input to the wellbore model, which, in turn, will retrofit the reservoir simulator for a new run. This can be costly and time consuming and it is not always successful or accurate. On the other hand, coupled models developed for special cases, while still relying upon simulations, are faster and provide reliable results but have no general application. This paper introduces a new technique of coupling wellbore and reservoir models where the simulation of the reservoir response to changes in the bottomhole flowing pressure is obtained not by numerical methods but rather by solving the diffusivity equation using the Fourier transform. This mathematical tool generates time-dependent equations—the dynamic IPR—which are able to provide the reservoir response to any pressure variation, regardless of how fast or slow this change might be. Methods Conventional IPR models are algebraic equations correlating the bottomhole flowing pressure and the flow rate through the production-zone completion. Because most of these models rely on correlations and experimental-data fit, it is common practice in the industry to perform well tests periodically to correct the IPR models according to the most-updated information on the fluids and reservoir parameters. The focus of this work is on homogeneous, isotropic, circular-shaped, undersaturated oil reservoirs with a finite-diameter vertical well in the center. Thus, the authors considered IPRs that correspond to these same conditions. These IPRs are defined for three different flowing times: transient, pseudosteady state, and steady state. Please see the complete paper for the relevant equations.

Dynamic safety risk analysis of offshore drilling

The exploration and production of oil and gas involve the drilling of wells using either one or a combination of three drilling techniques based on drilling fluid density: conventional overbalanced drilling, managed pressure drilling and underbalanced drilling. The conventional overbalanced drilling involves drilling of wells with mud which exerts higher hydrostatic bottom-hole pressure than the formation pore pressure. Unlike the conventional overbalanced drilling, underbalanced drilling involves designing the hydrostatic pressure of the drilling fluid to be lower than the pore pressure of the formation being drilled. During circulation, the equivalent circulating density is used to determine the bottom-hole pressure conditions. Due to lower hydrostatic pressure, underbalanced drilling portends higher safety risk than its alternatives of conventional overbalanced drilling and managed pressure drilling. The safety risk includes frequent kicks from the well and subsequent blowout with potential threat to human, equipments and the environment.Safety assessment and efficient control of well is critical to ensure a safe drilling operation. Traditionally, safety assessment is done using static failure probabilities of drilling components which failed to represent a specific case. However, in this present study, a dynamic safety assessment approach for is presented. This approach is based on Bow-tie analysis and real time barriers failure probability assessment of offshore drilling operations involving subsurface Blowout Preventer. The Bow-tie model is used to represent the potential accident scenarios, their causes and the associated consequences. Real time predictive models for the failure probabilities of key barriers are developed and used in conducting dynamic risk assessment of the drilling operations. Using real time observed data, potential accident probabilities and associated risks are updated and used for safety assessment. This methodology can be integrated into a real time risk monitoring device for field application during drilling operations.

Gas well production analysis with non-Darcy flow and real-gas PVT behavior

A rigorous semi-analytical model is developed to study the production rate behavior of wells in gas reservoirs with Forchheimer's non-Darcy flow under constant or varying bottomhole pressure conditions. Rigorous modeling of gas property variation in reservoirs is integrated in this model. Three dimensionless parameters, normalized gas viscosity and compressibility product, Forchheimer number, and normalized viscosity, are introduced to quantify their effects on non-Darcy flow in the reservoir. The variation of viscosity and compressibility product in the gas reservoir depletion process leads to a smaller production decline rate than that of exponential decline. The parameter b in Arps' decline equation under Darcy flow is defined as the base value, b ⁎, that helps identify the production decline caused by reservoir non-Darcy flow. Under the condition of constant pressure drop the more severe the non-Darcy flow, the larger the Forchheimer number. Generally, non-Darcy results in a smaller production rate, a larger decline rate in the boundary-dominated period, and a longer transition period between these two periods. The viscosity variation enhances non-Darcy flow, which lowers the initial production rate but has very little effect on the production decline rate. A larger production decline rate during the boundary-dominated period may help petroleum engineers identify the non-Darcy flow effect from the production data. Analyses show that the traditional quadratic equation is a good approximation only if non-Darcy flow is not severe and that for non-Darcy flow in the reservoir, the traditional Fetkovich's type curves may underestimate reservoir permeability, overestimate well skin factor, and misinterpret reservoir drainage area. A method of using the proposed model to identify the non-Darcy flow from production data is presented. Two examples from the literature are analyzed, and good type curve matches and more reliable results are obtained.

The Phase Behaviour of Acid Disposal Gases and the Potential Adverse Impact on Injection or Disposal Operations

Abstract As increased volumes of acid gases (containing carbon dioxide and hydrogen sulphide) are processed, the technique of downhole re-injection of the concentrated acid gas for disposal of these unwanted fluids continues to become more popular. In many cases, bottomhole injection temperature and pressure conditions are such that the injected acid gas phase is a supercritical fluid that is miscible with the existing reservoir fluids and, thus, the potential for adverse relative permeability effects (due to thecreation of in situ immiscible liquid and vapour phases) is avoided. In other cases, however, combinations of lower reservoir temperatures and/or initially depleted disposal zone pressures, or blending of the acid gas with the in situ lean gas, can result in the formation of both liquid and vapour acid gas phases in the formation in the near-wellbore region. This can often cause very significant relative permeability effects, which may result in large reductions in injectivity of the acid gas on either a permanent or transient basis. This paper provides actual examples of such systems, as well as reviewing the design protocol that must be used to evaluate if potential phase behaviour problems can occur downhole during an acid gas disposal operation. This hasproven to be a key parameter in the successful evaluation of anacid gas disposal operation. Introduction In many acid gas injection operations, the bottomhole pressure condition is high enough that, over the entire life of the injection operation and at all possible blended compositions between the acid injection gas and the reservoir fluids, a monophasic condition is present. In some cases, when the initial reservoir pressure is low, initial injection commences in the "gas" phase region, and as pressure gradually increases, the phase condition of the fluids around the injection wells enters the two-phase region where a "liquid" acid gas phase is in thermodynamic equilibrium with an acid gas "vapour" phase. This may also occur when the acid gas blends with reservoir gas which may elevate the dew point pressure line upwards above the current injection pressure level, once again resulting in a condition of two-phase flow. The creation of these two immiscible phases (which have an interface and measurable interfacial tension between them) can, particularly in lower permeability formations, create significant adverse relative permeability effects which may result in large transient or permanent reductions in injectivity, possibly compromising the economics of the acid gas injection operation. Understanding the phase behaviour in such situations and how it interacts with the capillary pressure and relative permeability phenomena present within the matrix of the proposed injection zone is essential. Limited data is available in the literature on the properties of high temperature and pressure acid gas mixtures and their specific phase behaviour(1–8). This is also the case with data regarding the specific interaction of single and multiphase acid gas interactions with reservoir rock(9–11) and the effects of multiphase acid gas induced relative permeability effects(12). The motivation of this work was to obtain a dataset to expand the knowledge base in this area.

On the determination of the skin factor and the turbulence term coefficient through a single constant gas pressure test

The best correlation for evaluating the turbulence term coefficient, D( μ), for transient flow in gas wells under constant flow rate conditions is currently that of Lee et al. [Lee, R.L., Logan, R.W., Tek, M.R., 1987. Effect of turbulence on transient flow of real gas through porous media. SPE Form. Eval. (March), 108–120]. Several authors have used this correlation to calculate the production decline for wells that produce under constant bottomhole pressure conditions, but it is not clear if this is correct. When exploiting any gas reservoir, the flow rate and the average reservoir pressure decrease with time. This process makes D( μ) increase, whereas D( μ) q sc decreases with time; in contrast, when a well is produced under constant flow rate conditions, D( μ) q sc increases with time. Due to this fact, it can be of considerable practical interest to analyze the behavior of the high velocity pseudoskin factor, D( μ) q sc, for gas wells that produce under constant bottomhole pressure conditions. This paper presents the results of a study aimed at obtaining a correlation of both the mechanical skin factor, s, and the turbulence term coefficient, D( μ), for constant bottomhole pressure conditions through the analysis of a single test. Results obtained through a radial real gas flow simulator, carefully validated for pseudosteady state conditions were used as a database for the development of the new correlations. The skin effect considered varies from 0 to 10. Two different gases are considered. Other variables studied are the constant pressure, the reservoir size r e/ r w and formation permeability. The correlation is presented by means of straight-line fits of s t/[ s(1− r w/ r d)] in the vertical axis and D( μ i) q sc in the horizontal axis. The correlation coefficient was 0.9976. The error obtained when one evaluates the skin factor, s, using the correlation presented in this work is less than 10%. The error is substantially less when production rates are low. These rates strictly correspond to the case of low permeability reservoirs, where the constant pressure boundary condition considered is this study closely apply.

An investigation of constant-pressure gas well testing influenced by high-velocity flow

This paper presents the results of a study of transient pressure analysis of gas flow under either constant bottom-hole pressure conditions or the constant wellhead pressure conditions. The effects of formation damage, wellbore storage and high-velocity flow are included in the model. The analysis of simulated well tests showed that the interpretation methods used for liquid flow are generally accurate when the m( p) is used. For these conditions, a graph of 1/ q D vs. log t D presents gradually lower values of 1.1513 as the value of p wf decreases: for pressure buildup conditions, a graph of m D(1, Δ t a D )/ q D(Δ t a D = 0) vs. ( t a D + Δ t a D )/Δ t a D shows values of this slope within 1% of the 1.1513 value. However, when high-velocity flow influences constant pressure production tests, the slope can yield errors up to 13%. This upper limit occurs when the formation has a relatively ‘high’ permeability (around 1 mD) and the rate performance test is affected by high-velocity flow. It was found that pressure buildup tests are superior to rate performance tests because high-velocity flow does not affect the slope of the straight line portion of the buildup curve. Derivative analysis of simulated buildup tests showed that the skin factor is considerably miscalculated when the high-velocity flow effect is significant. This problem could lead to errors in the calculation of the skin factor, s, up to 300%.

Improved Formation Evaluation From Pressure and Conventional Cores Taken With Stable Foam-Bennett Ranch Unit (Wasson Field)

Improved Formation Evaluation From Pressure and Conventional Cores Taken With Stable Foam-Bennett Ranch Unit (Wasson Field)

Rock Failure During Tooth Impact and Dynamic Filtration

Abstract In previous publications, results of single-blow bit tooth impacts on saturated rocks at various stress states were reported. This paper extends these earlier works to include study of bit impact tests on salt water-saturated Berea and Bandera sandstone samples under conditions of elevated confining and pore pressure. During the tests dynamic filtration and deposition of a mud cake were occurring due to the presence of drilling mud in the borehole and a borehole-to-formation pressure differential. Results indicate that saturation of these sandstones with salt water tends to make them weaker than when saturated with nonreactive fluids. Plastic failure often occurs even when extremely high fluid-loss muds are present in the borehole. The failure mode tends toward plasticity with decreasing fluid loss. Brittle failure of sandstones in mud-filled holes is apparently relatively rare. Depending on the stress level, and the associated failure mode, withdrawal of the bit tooth induces a tensile force that seems rather important relative to the quantity of rock removed by vertical tooth impact. Introduction A vast majority of the oil wells drilled today involve the use of colloidal muds having a measurable mud filtrate loss. It is known from field experience that reduction of the water loss of a mud generally results in a reduction of the penetration rate. This paper describes an investigation of crater formation at simulated bottom-hole pressure conditions for drilling fluids having different water losses. The literature on single bit tooth impact (cratering) at atmospheric conditions is extensive, but only a limited amount of work has been performed at the stress conditions similar to that found in oil wells. Spherical penetrator cratering tests on rocks at hydrostatic pressure were performed by Payne and Chippendale. Chisel impact studies on limestone with independently varying overburden and borehole pressure and atmospheric pore pressure were reported by Garner, et al. Gnirk and Cheatham performed "static" penetrator tests on dry rocks at equal overburden and borehole pressures. Podio and Gray studied the effect of pore fluid viscosity at atmospheric pore and borehole pressures and varying overburden pressures. Their results illustrated the importance of fluid saturation of the rock. Yang and Gray reported single tooth impact tests on saturated rocks at elevated borehole, pore and confining pressures, but with equal pore and borehole pressures. For the work reported in Refs. 4 and 5, filtration across the hole bottom purposely was avoided. Maurer has investigated the effect of independently varying pore and borehole pressures at elevated overburden pressures by using a zero water-loss mud in the borehole. His tests were carried out under conditions that allowed independent control of overburden, pore and borehole pressures, but without control of filtration at the hole bottom. EXPERIMENTAL APPARATUS AND PROCEDURE APPARATUS The single blow chisel impact apparatus used by Gamer, as modified for this study, is shown in Fig. 1. A cross section of the pressure vessel is shown in Fig. 2. Several pieces of auxiliary equipment were added to the original apparatus in order that the borehole and pore pressure could be applied in a manner analogous to the actual bottom-hole situation. The pore-pressure system included a filtrate volume-measuring transducer and had sufficient surge capacity to allow filtrate to be injected into the sample without significant changes in pore pressure at points remote to the borehole. The borehole-pressure system contained a cross connection to the pore-pressure system so that both systems could be pressured simultaneously. The borehole-pore pressure differential was applied rapidly by the use of a quick and full-opening valve. SPEJ P. 163ˆ

Bit - Tooth Penetration Under Simulated Borehole Conditions

Bit - Tooth Penetration Under Simulated Borehole Conditions