Formation damage caused by drilling-fluid invasion, production, or injection can lead to positive skin factors and affect fluid flow by reducing permeability. When mud filtrate invades the formation surrounding a borehole, it will generally remain in the formation even after the well is cased and perforated. This mud filtrate in the formation reduces the effective permeability to hydrocarbons near the wellbore. It may also cause clays in the formation to swell, reducing the absolute permeability of the formation. In addition, solid particles from the mud may enter the formation and reduce permeability at the formation face.

Abstract Inflow control devices (ICD) have been used to balance flux around completions and also delay break-through of unwanted water into completions. Inflow-control devices (ICDs) were provided to curtail water production from heterogenous reservoirs with strong aquifer systems and/or supported with water injection. The model for the ICD consists of pressure-drop equations from the reservoir, through the screen, the flow conduit, the ICD nozzle, and into the production tubing, along with pressure drop through the lower-completion system. This additional pressure drop does not contribute to additional fluid inflow into the wellbore and this is seen to be an impairment to the productivity of horizontal wells. Pressure losses from horizontal wellbores which do not contribute to increased production is seen as skin and consequently, a new equation was derived to estimate skin due to ICD in horizontal completions. In this paper, a horizontal well equipped with inflow control device which was drilled in one of the off-shore fields of the Niger Delta region was used as a case study in evaluating the performance of an ICD completion. The new equation was used to estimate the skin due to ICD of this completion and the result obtained is compared with the skin obtained using pressure transient analysis and the results obtained from both approach are similar. This paper shares how the new equation was used to estimate skin due to ICD and the result comparison with that of a pressure transient analysis.

Abstract When a reservoir is bounded, well productivity is affected in the long time according to the nature of the boundary. The length of time for oil production is strongly affected by well location with respect to the boundary, whether the boundaries are single, paired and vertical or paired and inclined. It therefore becomes important that well location is guided to achieve prolong oil production. The guide may be achieved from solution to a specific flow equation describing pressure distribution. The solution prescribes rates and well location for available reservoir system properties. In this paper, dimensionless pressure derivatives of a vertical oil well are studied to search for optium well location that can guarantee satisfactory oil production without premature influence of the external boundaries. The external boundaries are sealing and are considered to be inclined. The solution to this dimensionless diffusivity equation is utilized. The derivatives are computed from the total dimensionless pressure expression summing all the image wells by superposition principle. The Python and Excel softwares were deployed to compute all the dimensionless pressures for the different well designs. Larger magnitudes of dimensionless pressure derivatives would indicate higher oil production for any well design and inclination of the sealing faults. The optimum well location from the sealing faults is inversely proportional to the inclined angles. This implies that nearer wells to faults produce optimally at a given time of production. Furthermore, the relationship between well distance and productivity has no maximum or minimum points. Therefore there is no particular optimum location distance from the faults for optimum productivity. Optimum well location for sealing boundaries depends on many factors, such as production profile, well design, faults angle, fluid type and lease size. Furthermore, it was also observed that the wellbore radius has no significant effect on the dimensionless pressure derivative, optimum well location and the optimum time of production.

A new analytical procedure is introduced for the interpretation of pressure-transient data in oil producers with pronounced water production. The new mathematical model is applicable to flow conditions where segregated flow dominates the displacement process in the reservoir. Here, formation flow capacity and individual magnitudes of oil- and water-phase mobility are also determined, allowing accurate reservoir characterization under such complex flow conditions.

Segregated flow is very common in natural porous rocks and is characterized by a sharp interface between oil and water. Hence, our new mathematical model mimics the dynamics of this flow mechanism by taking into consideration the individual contributions of oil and water from each reservoir zone. This novel mathematical model is utilized to extract formation flow capacity and mobility for both phases. An average fluid saturation can also be determined with a reasonable accuracy.

The reservoir system in hand is represented by a two-layer model with no crossflow between the different zones in the reservoir. Because of gravity effects, oil is produced from the top layer while water is produced from the bottom one. Each reservoir layer has its own distinct static and dynamic properties, such as porosity, permeability, thickness, and petrophysical properties. A case study based on synthetic reservoir data is presented to demonstrate the application of the mathematical model in characterizing formation rocks. It is observed that conventional well-testing methods could produce inaccurate results when applied to reservoir systems influenced by segregated flow. Using the new model, a correction factor is derived to estimate absolute permeability values from the conventional well-testing analysis, producing a one-to-one transformation between dispersed and segregated flow.

The conventional way of interpreting pressure-transient data for two-phase flow displacements under segregated conditions is based on an equivalent single-phase flow model that might produce inaccurate results and invalid estimates of flow capacity and phase mobility. Our new approach, therefore, is more representative for the system under consideration and captures the flow mechanism more robustly.

A new analytical procedure is introduced for the interpretation of pressure-transient data in oil producers with pronounced water production. The new mathematical model is applicable to flow conditions where segregated flow dominates the displacement process in the reservoir. Here, formation flow capacity and individual magnitudes of oil- and water-phase mobility are also determined, allowing accurate reservoir characterization under such complex flow conditions.

Segregated flow is very common in natural porous rocks and is characterized by a sharp interface between oil and water. Hence, our new mathematical model mimics the dynamics of this flow mechanism by taking into consideration the individual contributions of oil and water from each reservoir zone. This novel mathematical model is utilized to extract formation flow capacity and mobility for both phases. An average fluid saturation can also be determined with a reasonable accuracy.

The reservoir system in hand is represented by a two-layer model with no crossflow between the different zones in the reservoir. Because of gravity effects, oil is produced from the top layer while water is produced from the bottom one. Each reservoir layer has its own distinct static and dynamic properties, such as porosity, permeability, thickness, and petrophysical properties. A case study based on synthetic reservoir data is presented to demonstrate the application of the mathematical model in characterizing formation rocks. It is observed that conventional well-testing methods could produce inaccurate results when applied to reservoir systems influenced by segregated flow. Using the new model, a correction factor is derived to estimate absolute permeability values from the conventional well-testing analysis, producing a one-to-one transformation between dispersed and segregated flow.

The conventional way of interpreting pressure-transient data for two-phase flow displacements under segregated conditions is based on an equivalent single-phase flow model that might produce inaccurate results and invalid estimates of flow capacity and phase mobility. Our new approach, therefore, is more representative for the system under consideration and captures the flow mechanism more robustly.

Abstract

The viscous character of rock salt can cause problems during drilling and well construction operations, but can be favorable during well abandonment. The natural process of salt creep can reinstate the integrity of rock salt caprocks and create an additional well barrier. The method requires removing of a part of the casing set across a salt caprock formation. Differential stresses at the wellbore wall will initiate the process of creep leading to a reduction of wellbore radius and closure of an uncased wellbore section. Geomechanical numerical simulations were conducted to evaluate the creep-induced wellbore convergence in salt formations. A two-component creep constitutive material model was used, which takes into account the contributions of both the non-linear creep component, dominant under high differential stresses, and the linear creep component, dominant under low differential stresses. The calculation results expectedly show an increase in the creep strain rate with depth due to increasing temperature and differential stress. However, the creep strain rate decreases exponentially as the wellbore radius decreases. The shortest borehole closure time for a depth of 3.5 km, which is applicable to well abandonment in the K12-B CO₂ Injection Project in the Netherlands, amounts to about 500 days.

Abstract

In a typical test of the hydraulic fracturing (HF) method, fluid is injected into a wellbore until the initial cracks around the wellbore begin to develop. After that, the injection is stopped and the fluid pressure starts to decline. This stage is called shut-in. The common graph of the HF test is the wellbore pressure versus time that is used for estimating the in-situ stresses. A significant point in this curve, which is associated with the minimum horizontal in-situ stress, is the shut-in pressure. In this paper, a plane strain numerical model is used for simulating the injection and shut-in stages of hydraulic fracturing. This model considers wellbore effects, compressibility of injection system and fluid viscosity. Based on numerical results, increasing of fluid viscosity decreases the duration of the shut-in stage and length of initial notch is ineffective in the shut-in pressure.

Introduction

Hydraulic fracturing (HF) test has been a rather old method for enhancing the efficiency of oil wells, but the developing this method in recent decades has caused that it has become a technique for designing the huge underground projects such as tunnels, mines, oil and gas wells, etc. (Howard and Fast, 1970, Haimson, 1968, Cornet, 1982, Tsukahara et al., 1996). One of the results obtained from the HF test is the graph of wellbore pressure versus time that is separated to three distinct stages. The first stage that is injection phase, the fluid is pumped into the wellbore and the pressure increases until pre-existing cracks in the rock mass start to propagate. After this stage, the fluid injection stops and then the fluid occupies throughout the crack length (shut-in stage). Finally, the cracks begin to close owing to the residual strength of the rock mass. The fluid withdraws from the wellbore during the phase known as flowback (Fig. 1).

For estimation of in-situ stresses, two vital points have been introduced in the wellbore pressure versus time graph: The breakdown pressure that is the peak pressure and the shut-in pressure is measured during the shut-in stage. According to the H-W (Hubbert and Willis, 1957) and H-F (Haimson and Fairhurst, 1967) criteria, the breakdown pressure is related to the horizontal in-situ stresses. Furthermore, it has been suggested that the shut-in pressure is equal to the minimum in-situ stress (Gronseth and Kry, 1982).

There are many ambiguities and arguments about the shut-in curve and the most of these issues may be attributed to the shut-in stage instability. Although in the shut-in stage the injection ceases but the energy required for propagating cracks exists, then the fluid pressure drops and becomes approximately uniform in the crack. Various factors affect the closure process after the shut-in.

We investigate the initiation and early-stage propagation of an axi-symmetric hydraulic fracture from a wellbore drilled in the direction of the minimum principal stress in an elastic and impermeable formation. Such a configuration is akin to the case of a horizontal well and a hydraulic fracture transverse to the well axis in an open hole completion. In addition to the effect of the wellbore on the elasticity equation, the effect of the injection system compressibility is also taken into account. The formulation accounts for the strong coupling between the elasticity equation, the flow of the injected fluid within the newly created crack and the fracture propagation condition. Dimensional analysis of the problem reveals that three dimensionless parameters control the entire problem: the ratio of the initial defect length over the wellbore radius, the ratio between the wellbore radius and a length-scale associated with the fluid stored by compressibility in the injection system during the well pressurization, and finally the ratio of the timescale of transition from viscosity to toughness dominated propagation to the timescale associated with compressibility effects. A fully coupled numerical solver is presented, and validated against solutions for a radial hydraulic fracture propagating in an infinite medium. The influence of the different parameters on the transition from the near-wellbore to the case of a hydraulic fracture propagating in an infinite medium is fully discussed.

Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in San Antonio, Texas, USA, 8-10 October 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Optimum fluid placement is crucial for a successful acid stimulation treatment, especially in thick, highly heterogeneous carbonate formations with multiple zones and/or extensivee productive intervals. A variety of diversion methods are applied in acidizing treatments to evenly place acid along the well, but the effectiveness of these diversion methods is generally only inferred from the rate and pressure behavior during the treatment, and is not known with any certainty. Recently, distributed temperature sensing technology has enabled us to observe dynamic temperature profiles along the wellbore during and immediately following an acid treatment. This technology allows uss to monitor and evaluate treatments and diversion methods in real-time from captured sequence of temperature profiles at different times during and after acid injection. We presented a mathematical model in previous papers to simulate the temperature behavior in the formation and along the wellbore, during and shortly after an acid treatment (Tan, 2009 andd 2011). An inversion procedure was also included to interpret the acid distribution profile from the measured temperature data in a hypothetical example.

Abstract For oil reservoir with bottom water and/or gas cap, gas and water conings impose serious problems during the oil production. Coning leads to the premature gas and water breakthrough thus results in high water cut and gas oil ratio, which require a higher surface facility capacity to process excessively produced water and larger three-phase separators to separate gas, oil, and water. Consequences of early breakthrough are large footprint due to large facility, more energy to operate field, and low oil recovery. Even though numerous studies had been focused on solving the critical oil rate for gas and water coning problems, to our knowledge none of them considers the effect of capillary pressure on critical oil rate. The ignorance of capillary pressure caused the error of calculated critical rate to rise to 300%, according to the real field case study. The errors caused by neglecting capillary pressure are severe in low permeability reservoirs. For the purpose of good production design, we investigated the effect of capillary pressure on critical rate estimation. Our study showed that the calculated critical rates are close to real field critical rates. The existing methods underestimate the critical rate by not taking capillary pressure into account. Therefore, more accurate critical rates can be obtained using our method. With more accurate result more reliable production plan can be designed to maximize the ultimate recovery.