INTERPRETATION OF PRESSURE TRANSIENT TESTS OF HORIZONTAL WELLS WITH

The oil and gas industry has long recognized the importance of understanding the behaviors and trends of pressure and fluid flow dynamics for damaged and stimulated horizontal wells. It has also been recognized that the existing theories to predict these behaviors and trends have not been effective due to the geologic factors, as well as drilling, completion, and production processes. Previous researches and studies over the last two decades have shown different types of factors such as the presence of multi-damaged zones, multi-segmented fractures, branching, asymmetry, and deviation from either the vertical direction or the horizontal direction of the wellbores as a result of in-situ stress distribution.The main purpose of this study is to find new applications for the well test analysis rather than the classic applications that are focusing basically on the characterization of formation and determination of the permeability and skin factor. The new applications for the well test analysis are evaluating performance of the zonal isolations and hydraulic fractures and determining the locations of the isolations and fractures that do not perform as designed. Another objective is to investigate pressure behavior and flow regimes of a horizontal well containing either zonal isolations or hydraulic fractures.The objectives in this study are achieved by using different analytical models. These models have been derived to simulate the pressure responses and flow regimes in the vicinity of the wellbore and the outer boundaries of the formations. Based on the new derived models, different analytical solutions and type-curve matching sets have been developed to characterize formations.The first part of this study focuses on the impact of the zonal isolations on pressure behaviors and flow regimes of horizontal wells. Horizontal wells with multiple zonal isolations have become a common completion technique in the oil and gas industry. Sand and asphalt production problems, damaged zones and water cresting or gas coning are the main reasons for using isolators to sustain or improve oil and gas recovery. However, the use of such isolators introduces negative effects on the pressure behavior of horizontal wells.This research introduces new analytical models for studying the effect of this completion technique on pressure behavior of wells with multiple isolated zones. These models have been derived based on the assumption that reservoirs can be divided into multi-subsequent segments of producing and non-producing intervals. Based on the pressure and pressure derivative, the models can be used to estimate the impact of isolators on the pressure behavior. The effects of the number and length of isolators have been investigated for wells having different lengths.A set of type-curves of dimensionless pressure and pressure derivative versus dimensionless time have been generated for two cases. The first case is for wells in an infinite reservoir having short dimensionless wellbore length and multiple-isolated zones, while the second case concentration on very long wells in an infinite reservoir. These plots can be used to verify the number and length of zonal isolations originally installed, as well as to determine the number and locations of malfunctioning isolators. These plots can also be used to locate segments where sand is produced and intervals of water cresting or gas coning are present.The main finding is that the pressure of these wells behaves similarly for all cases. The dominant effect of the isolators can be noticed only during the early time flow regimes, i.e. during the early radial or early linear. The behavior of the late time flow regimes, i.e. pseudo radial is not affected by the presence of isolators.The second part of this study focuses on the pressure behavior and flow regimes that are developed for horizontal wells intersected by multiple-inclined hydraulic fractures. The fractures either fully or partially penetrate the formations. Horizontal wells with multiple hydraulic fractures have become a common occurrence in the oil and gas industry, especially in tight formations. Recent studies have shown that fractures are asymmetric, inclined with respect to the vertical direction and the axis of the wellbore, and partially penetrate the formation in many cases.This study introduces new analytical models for interpreting the pressure behavior of horizontal wells with multiple hydraulic fractures. The hydraulic fractures in this model could be longitudinal or transverse, vertical or inclined, symmetrical or asymmetrical. The fractures propagate in isotropic or anisotropic formations. In addition, they have different dimensions and different spacing. These models can be solved to calculate various reservoir parameters, including directional permeability, fracture length, skin factors, angle of inclination and penetration ratio.Type-curve matching technique has been applied using the plots of the pressure and pressure derivative curves. A set of type curves have been generated for the inclined transverse and longitudinal hydraulic fractures associated with horizontal wells having different inclination angles from the vertical and different penetration ratios.Tiab's Direct Synthesis (TDS) technique has been applied also using the plots of the pressure and pressure derivative curves. Several unique features of the pressure and pressure derivative plots of both longitudinal and transverse fractures models were identified including the points of intersection of straight lines for different flow regimes. These points can be used to verify the results or to calculate unknown parameters. Equations associated with these features were derived and their usefulness was demonstrated in this study

Optimum matrix acidizing: How much does it impact the productivity

Formation damage is one of the big challenges for oil and gas oilfields development. Several types of formation damage most likely exist during the entire life of producing wells. Formation damage can occur during the drilling or coring operations, well completion, work-over and production. The most important problems that affect formation during drilling operations are mud filtrate and fines invasion. There are different damage mechanisms affect reservoirs for instance pore blocking by solids, clay swelling and dispersion and liquid block which all reduce effective permeability to hydrocarbons. The reduction in production and an excessive build up pressure in injection wells indicate the formation. Many techniques are developed to remove the formation damage and to improve the productivity of wells. Matrix acidizing is one of these method which depend on injecting acids into the formation below fracturing pressure to eliminate the damage around the well. In this study, comprehensive design procedures for the acid treatment have been introduced. The procedures include the determination of the damage type and the mineralogy of the formation. Accordingly, the selection of the appropriate acid for the treatment and the optimum volume of injected acid are explained in the study. Additionally, the research presents several models for the pre-flush volume and the main acid volume based on the radius of the damaged zone and the height of the formation. New technique has been proposed for determining the final permeability improvement ratio based on current and proposed productivity index. It has been found the pre-flush volume increase as the carbonate percentage in the formation increases while the main acid volume conversely proportional with the clay content in the formation

Hydraulically Fractured Formations: Parameters Controlling Performance and Maximum Number of Fractures

Horizontal wells essentially increase the area of contact between wellbores and reservoir fluids to some extent. Hydraulic fractures increase this area significantly and develop the vertical permeability. Because of these two techniques, well deliverability or productivity index can be increased to the limit required by the worldwide needs. Several models have been derived for the productivity index of fractured formations and the maximum number of fractures for both finite and infinite reservoirs. The models were developed based on the idea that the total pressure drop in the wellbore can be estimated as the sum of different pressure drops caused by different flow regimes. This pressure drop is necessary for the fluid to flow from the reservoir toward the wellbore. It is well known that the developed flow regimes in the area around the horizontal wells or the hydraulic fractures are not the same as the flow regimes at far distance from wellbores, which is close to the outer boundaries. Therefore, four flow regimes were expected to develop in infinite acting reservoir: pseudo radial flow at the outer boundaries, elliptical flow in the area between wellbores and the regions close to the outer boundaries, formation linear flow in the area between fractures toward wellbores and fractures, and finally fractures linear flow, while pseudo-steady state flow was the expected flow regime for the case of limited reservoirs. Each one of these flow regimes contributes to the total pressure drop necessary for producing certain flow rate in addition to the pressure drop caused by the damage zones resulted from horizontal well drilling and completion, hydraulic fracturing process, and fluid flow chocking effect. In this study, the effects of the anisotropy, fracture dimensions, radius of drainage area, number of fractures and fracture conductivity on productivity index had been investigated. A novel approach for the maximum number of fractures necessary for a specific productivity index was introduced in this paper. The model had been examined for two field cases taken from literatures. The calculated flow rates by this model showed good agreement with the measured flow rates

Rate and pressure behavior considering the fractal characteristics of structurally disordered fractured reservoirs

The main objective of this paper is to understand the impact of the fractal characteristics of fractured reservoirs on their pressure behavior, flow rate decline, and productivity index. The paper proposes a new methodology for developing several analytical models for describing the wellbore pressure distribution and the flow rate decline trend. The proposed models consider including the fractal characteristics such as the mass fractal dimension, conductivity index of anomalous diffusion flow mechanism, fractal-network parameters, fractional-derivative order, and matrix/fracture-interaction index as well as dual-porosity media characteristics such as the storativity and interporosity flow coefficient in the analytical models of the pressure, rate, and productivity index. The study has found that: (1) Some of the fractal characteristics have a significant impact on reservoir performance, while others may not have a significant impact. (2) Fractal reservoirs exhibit better performance than the standard geometry reservoirs of single and dual-porosity media

Revisiting Current Techniques for Analyzing Reservoir Performance: A New Approach for Horizontal-Well Pseudosteady-State Productivity Index

The objective of this paper is to revisit currently used techniques for analyzing reservoir performance and characterizing the horizontal-well productivity index (PI) in finite-acting oil and gas reservoirs. This paper introduces a new practical and integrated approach for determining the starting time of pseudosteady-state flow and constant-behavior PI. The new approach focuses on the fact that the derivative of PI vanishes to zero when pseudosteady-state flow is developed. At this point, the derivative of transient-state pressure drop and that of pseudosteady-state pressure drop become mathematically identical. This point indicates the starting time of pseudosteady-state flow as well as the constant value of pseudosteady-state PI. The reservoirs of interest in this study are homogeneous and heterogamous, single and dual porous media, undergoing Darcy and non-Darcy flow in the drainage area, and finite-acting, depleted by horizontal wells. The flow in these reservoirs is either single-phase oil flow or single-phase gas flow

Integrated deterministic approaches for productivity index of reservoirs depleted by horizontal wells and undergone multiphase flow conditions

This paper introduces new integrated approaches for estimating pseudo-steady state productivity index (PI) and shape factor of oil and gas reservoirs drained by horizontal wells and dominated by multiphase flow conditions. These approaches couple PVT data, relative permeability curves, and pressure distribution models during pseudo-steady state flow (PSS). The objective is eliminating the uncertainties of applying single phase flow models and substantially comprising the realistic parameters that govern multiphase flow conditions. The importance of this study is represented by introducing the impact of multiphase flow (Gas, Oil, Water) to the productivity index and inflow performance relationship of reservoirs depleted by horizontal wellbores

Analysing and characterising horizontal well performance in rectangular closed gas reservoirs considering non-Darcy flow conditions

This paper investigates the impact of non-Darcy flow, represented by rate-dependent skin factor (DQ(SC)), on pressure profiles, flow regimes, and productivity indices of horizontal wells extending in conventional and unconventional gas reservoirs. It introduces a new simplified technique for characterising reservoir performance under different non-Darcy flow impacts. The outcomes of this study are summarised as: 1) understanding the conditions at which non-Darcy flow could have considerable effects on reservoir performance; 2) estimating the deviation in productivity index caused by non-Darcy flow. The most interesting points in this study are: 1) the ability to estimate rate-dependent skin factor from well test analysis by observing early time radial flow regime; 2) all flow regimes, unlike pressure behaviors and productivity index, are not affected by non-Darcy flow; 3) productivity index declines sharply for high rate-dependent skin factor at early production time while pseudo-steady state productivity index is not affected by non-Darcy flow. [Received: April 12, 2018; Accepted: May 9, 2018

Analytical models & type-curve matching techniques for reservoir characterization using wellbore storage dominated flow regime

The applicability of early time data in reservoir characterization is not always considered worthy. Early time data is usually controlled by wellbore storage effect. This effect may last for pseudo-radial flow or even boundary dominated flow. Eliminating this effect is an option for restoring real data. Using the data with this effect is another option that could be used successfully for reservoir characterization.This paper introduces new techniques for restoring disrupted data by wellbore storage at early time production. The proposed techniques are applicable for reservoirs depleted by horizontal wells and hydraulic fractures. Several analytical models describe early time data, controlled by wellbore storage effect, have been generated for both horizontal wells and horizontal wells intersecting multiple hydraulic fractures. The relationships of the peak points (humps) with the pressure, pressure derivative and production time have been mathematically formulated in this study for different wellbore storage coefficients. For horizontal wells, a complete set of type curves has been included for different wellbore lengths, skin factors and wellbore storage coefficients. Another complete set of type curves has been established for fractured formations based on the number of hydraulic fractures, spacing between fractures, and wellbore storage coefficient.The study has shown that early radial flow for short to moderate horizontal wells is the most affected by wellbore storage while for long horizontal wells; early linear flow is the most affected flow regime by wellbore storage effect. The study has also emphasized the applicability of early time data for characterizing the formations even though they could be controlled by wellbore storage effect. As a matter of fact, this paper has found out that wellbore storage dominated flow could have remarkable relationships with the other flow regimes might be developed during the entire production times. These relationships can be used to properly describe the formations and quantify some of their characteristics. Keywords: Reservoir engineering, Reservoir modeling and simulation, Pressure transient analysis, Reservoir characterization, Wellbore storage effect, Skin factor, Reservoir flow regimes, Pressure behavior

Productivity-Index Behavior for Hydraulically Fractured Reservoirs Depleted by Constant Production Rate Considering Transient-State and Semisteady-State Conditions

This paper introduces a new approach for studying productivity-index (PI) behavior of fractured oil and gas reservoirs during transientand pseudosteady-state conditions. This approach focuses on the fact that PI derivative could vanish at a certain production time, indicating the beginning of pseudosteady state, wherein the PI demonstrates constant value. The reservoirs in this study are considered depleted by horizontal wells intersecting multiple hydraulic fractures where Darcy flow and non-Darcy flow may control flow patterns in the porous media. The PI is calculated assuming constant production rate and considering pressure profile for early- and intermediate-production time when transient condition dominates fluid flow and late-production time when pseudosteady state is reached

Pseudo-steady state inflow performance relationship of reservoirs undergoing multiphase flow and different wellbore conditions

This paper introduces an integrated approach for the inflow performance relationship of reservoirs that undergo multiphase flow conditions and drained by vertical wells with different wellbore conditions. The main objective is eliminating uncertainties that govern predicting reservoir performance by assuming single phase flow in the porous media. The proposed approach includes developing several models for multiphase flow conditions using PVT data and relative permeability curves. These models are assembled with the inflow performance relationship to substantially approaching the realistic reservoir pressure/flow rate trend with time