The development of tight reservoirs using a horizontal well requires caution owing to the reservoir sensitivity to stress. Predicting the horizontal wellbore instability during reservoir depletion is critical for tight reservoirs. The present study investigated the wellbore failure criteria and stress orientation changes with reservoir depletion of a horizontal well in a tight reservoir, considering rock sensitivity to stress with pressure reduction. An integrated reservoir model coupled with geomechanics was used to predict pore pressure. A mechanical earth model (MEM) was constructed to examine the stability of horizontal wells. The unconfined compressive strength (UCS) was correlated with changes in porosity due to stress changes. The MEM shows that the failure criteria around the horizontal wellbore, including breakout, loss, and breakdown pressures, change considerably with reservoir depletion. A more significant response was observed in the stress-sensitive layer, which was characterised by a higher permeability. The safe mud weight window of the studied horizontal well narrowed significantly after production for five years, whereas the stability was completely absent after ten years. The deterioration of stability with depletion is governed mainly by permeability reduction, which may cause severe pressure reduction, whereas the stability improvement due to the increase in UCS caused by porosity reduction seems marginal. Relatively small changes in the direction of the stresses around the wellbore with depletion were observed, with the stress distribution concentrated in the predominant direction as the depletion continued. This study indicates that the sensitivity of petrophysical and geomechanical properties to stress amplifies the instability in tight reservoirs, particularly around wellbores.

Geomechanics plays a significant role in all phases of an oil and gas field’s life cycle, from exploration to production and even beyond field abandonment. It has various applications in the petroleum industry, such as predicting safe mud window and determining the magnitude and direction of in-situ stresses. The objective of this study is to determine the magnitude and orientation of far-field stresses, identify fault types, estimate pore pressure, and evaluate mechanical properties for different formations by constructing a one-dimensional geomechanical model (1D-MEM) for a deep well in the Halfaya oilfield. This study utilizes open-hole log measurements, including density, sonic compression and shear wave velocities, gamma-ray, caliper, and bit size. The results from the model indicate that the Mishrif A, Mishrif B1, Mishrif B2, Mishrif C1, Mishrif C2, Mishrif C3, Mauddud, Nahr Umr B, Ahmadi, and Zubair formations exhibit normal faulting. On the other hand, the Nahr Umr A, Shuaiba, Ratawi, and Yamama formations show strike-slip faulting. The Rumaila formation, based on the magnitudes of the far-field stresses, appears to exhibit reverse faulting. Furthermore, the Yamama formation demonstrates abnormally high pore pressure, while other formations are considered natural pressure formations. In terms of rock properties, shale and sand formations have lower Young's modulus, Poisson's ratio, and UCS, whereas limestone formations have higher values. Moreover, limestone formations exhibit higher friction angles compared to sandstone and shale formations.

For a reservoir with high storage capacity and low ability to produce, the serious problem is the sharp reduction in the recorded well productivity within a short period. One solution to this problem is to create hydraulic fractures that increase formation permeability and keep its production at high rates for a sufficient time. The field under study is the East Baghdad oil field of three formations: Saadi, Tanuma, and Khasib. Knowing the geomechanical behavior of these reservoirs has a critical effect on the success of hydraulic fracturing operations. In this study, rock stress magnitude and direction, rock elasticity, rock strength to fracturing initiation, and all these parameters in addition to petrophysical properties will be used to identify whether the hydraulic fracturing operation could be successful or not. An integrated modeling of the studied reservoir is an essential step including 1-D geomechanical evaluation of many formations in order to choose the perfect layer to create hydraulic fracture. Then, a 3-D distribution of geomechanical properties and petrophysical properties was presented to make a perfect selection of these properties. The geomechanical evaluation of the reservoirs under study is supported by experimental evaluation of core samples including Energy Dispersive X-ray spectroscopy (EDS), Scanning Electron Microscopic (SEM) image, and thin section (TS) image. The results show that a reduction in the calculated geomechanical properties in terms of Poisson ratio young modulus and compressive strength are favorable for candidate layer selection. Among the studies of rock mechanical properties, it is also noticed that unconfined compressive strength is a crucial parameter for best layer selection. The suitable depths for fracturing jobs are given in detail in this study using brief data collected from four wells.

Geomechanical properties have a prominent influence on reservoir stresses, which consequently reduce permeability and porosity with pressure depletion. These properties significantly affect the accuracy of reservoir modeling and recovery calculation, but have not been fully studied; therefore, more work is needed. Full field data and laboratory measurements are included in the study. The work involves deriving an equation by combining experimental data for permeability and porosity reduction during a change in stress with the poroelastic stress equation to investigate the impact of Poisson's ratio and Young's modulus on the reduction of permeability and porosity with pressure depletion. Most simulation studies assume constant geomechanical properties across the entire reservoir or for each individual reservoir layer. In this study, three approaches were considered for the Poisson's ratio and Young's modulus in the reservoir model: 1) constant average values assigned to the entire reservoir, 2) constant average values assigned to each layer, and 3) constant values assigned to each grid block. The validity of the model results was checked by history matching with production and pressure data. For the studied tight reservoir, the Poisson's ratio and Young's modulus significantly affected the permeability and porosity reduction with pressure depletion. The impact of Young's modulus was more pronounced than Poisson's ratio. The simulation results for oil rate, cumulative oil production, and water cut for the reservoir and a selected well showed that applying the three suggested geomechanical approaches resulted in a substantial discrepancy in the model outcome. In general, the coupled model with the mapped geomechanical properties resulted in lower oil and water production. This is attributed to the large values of mapped Young's modulus in parts of the reservoir which resulted in large permeability reduction and subsequently lower oil and water production is expected. In contrast lower Young's modulus per layer was obtained due to averaging process. Poisson's ratio effect on fluid production is much less significant due to its small effect on permeability reduction with depletion. Similarly, the adoption of different geomechanical property values for each layer yielded a relatively lower production outcome than when using a constant value for the entire reservoir. The study indicates the importance of considering the detailed description of the reservoir geomechanical properties to obtain reliable simulation results.

Optimum perforation location selection is an important study to improve well production and hence in the reservoir development process, especially for unconventional high-pressure formations such as the formations under study. Reservoir geomechanics is one of the key factors to find optimal perforation location. This study aims to detect optimum perforation location by investigating the changes in geomechanical properties and wellbore stress for high-pressure formations and studying the difference in different stress type behaviors between normal and abnormal formations. The calculations are achieved by building one-dimensional mechanical earth model using the data of four deep abnormal wells located in Southern Iraqi oil fields. The magnitude of different stress types and geomechanical properties was estimated from well-log data using the Techlog software. The directions of the horizontal stresses are determined in the current wells utilizing image-log formation micro-imager (FMI) and caliper logs. The results in terms of rock mechanical properties showed a reduction in Poisson’s ratio, Young modulus, and bulk modulus near the high-pressure zones as compared to normal pressure zones because of the presence of anhydrite, salt cycles, and shales. Low maximum and minimum horizontal stress values are also observed in high-pressure zones as compared to normal pressure zones indicating the effects of geomechanical properties on horizontal stress estimation. Around the wellbore of the studied wells, formation breakouts are the most expected situation according to the results of the wellbore stress state (effective vertical stress ( σ zz ) > effective tangential stress ( σ θθ ) > effective radial stress ( σ rr )).

This research presents a method for calculating stress ratio topredict fracture pressure gradient. It also, describes a correlation andlist ideas about this correlation.Using the data collected from four wells, which are the deepestin southern Iraqi oil fields (3000 to 6000) m and belonged to four oilfields. These wells are passing through the following formations: Y,Su, G, N, Sa, Al, M, Ad, and B. A correlation method was applied tocalculate fracture pressure gradient immediately in terms of bothoverburden and pore pressure gradient with an accurate results.Based on the results of our previous research , the data were usedto calculate and plot the effective stresses. Many equations relatinghorizontal effective stress and vertical effective stress are obtained foreach well and used to calculate fracture pressure gradient. Similarequations are found for group of formations that calculate fracturepressure gradient and to find the most accurate correlation amongthem.

As a reservoir is depleted due to production, pore pressure decreases leading to increased effective stress which causes a reduction in permeability, porosity, and possible pore collapse or compaction. Permeability is a key factor in tight reservoir development; therefore, understanding the loss of permeability in these reservoirs due to depletion is vital for effective reservoir management. The paper presents a case history on a tight carbonate reservoir in Iraq which demonstrates the behavior of rock permeability and porosity as a function of increasing effective stress simulating a depleting mode over given production time. The experimental results show unique models for the decline of permeability and porosity as function effective stress. This stress sensitivity is even more pronounced in cores with lower initial porosity and permeability. The pores’ size and shape, as well as mineral content provide important reasons for various functions in the stress-dependent behavior of the porous media. Additionally, mercury injection capillary pressure (MICP), thin section (TS) results, scanning electron microscope (SEM) data, and X-Ray diffraction (XRD) are incorporated to relate the microscopic controlling factor to stress sensitivity behavior of this reservoir formation. The results indicate that permeability is more sensitive to effective stress than the porosity. Different responses to the stress of similar initial permeability are discussed according to their mean hydraulic radius (MHR). Distinguished fabric signatures for the studied reservoir is identified from grouping the MHR-permeability relations, which is significant and can provide insight on the heterogeneity of a given reservoir and how it is related to pore size distribution. This grouping mode provided better data allocation than depending on other parameters such as; conventional samples’ initial petrophysical properties, pore size distribution, MHR values, reservoir stratigraphic units division, and clay content for the samples, which all failed in achieving reasonable data grouping for the tight reservoir under study. A relation of the viscous behavior (ductility/brittleness) of this tight reservoir to permeability and stress is examined.

The instant global trend towards developing tight reservoir is great; however, development can be very challenging due to stress and geomechanical properties effect in horizontal well placement and hydraulic fracturing design. Many parameters are known to be important to determine the suitable layer for locating horizontal well such as petrophysical and geomechanical properties. In the present study, permeability sensitivity to stress is also considered in the best layer selection for well placement. The permeability sensitivity to the stress of the layers was investigated using measurements of 27 core sample at different confining stress values. 1-D mechanical earth model (MEM) was built and converted to a 3-D full-field geomechanical model to reach perfect layer choice. The analysis of results has diagnosed the maximum horizontal stress direction of NE-SW as determined using both Fullbore Formation Micro Imager FMI and sonic scanner anisotropy analysis. The effect of porosity and permeability compaction as a result of stress changes while reservoir depletion is including on the reservoir simulation model. The choice of best layer and optimum design criteria for hydraulic fracturing is done in the current study using a compaction simulation model with the results of available measurements of geomechanical properties. The results of the simulation model show that the formation sensitivity to stress is an important factor for detecting a suitable layer for horizontal wells placement. The results of MEM indicate that horizontal stress difference (Δσ) and unconfined compressive strength (UCS) are the most important factors among geomechanical parameters affected the layer selection. From simulation results, it was found that 225 to 275 m fracture half-length gives a higher increment in oil production. The optimum number of fracture stages is noticed to be 8 to 10 stages after which the increment in production will reduce.

Increasing hydrocarbon recovery from tight reservoirs is an essential goal of oil industry in the recent years. Building real dynamic simulation models and selecting and designing suitable development strategies for such reservoirs need basically to construct accurate structural static model construction. The uncertainties in building 3-D reservoir models are a real challenge for such micro to nano pore scale structure. Based on data from 24 wells distributed throughout the Sadi tight formation. An application of building a 3-D static model for a tight limestone oil reservoir in Iraq is presented in this study. The most common uncertainties confronted while building the model were illustrated. Such as accurate estimations of cut-off permeability and porosity values. These values directly affect the calculation of net pay thickness for each layer in the reservoir and consequently affect the target of estimating reservoir initial oil in place (IOIP). Also, the main challenge to the static modeling of such reservoirs is dealing with tight reservoir characteristics which cause major reservoir heterogeneity and complexities that are problematic to the process of modeling reservoir simulation. Twenty seven porosity and permeability measurements from Sadi/Tanuma reservoir were used to validate log interpretation data for model construction. The results of the history matching process of the constructed dynamic model is also presented in this paper, including data related to oil production, reservoir pressure, and well flowing pressure due to available production.

Accurate and simple techniques for measurement of fluid rheological properties are important for field operations in the oil industry. Marsh Funnels are popular quality-control tools used in the field for drilling fluids and they offer a simple, practical alternative to viscosity measurement. In the normal measurements, a single point (drainage time) is used to determine an average viscosity; little additional information is extracted regarding the non-Newtonian behavior of the fluid. Here, a new model is developed and used to determine the rheological properties of drilling muds and other non-Newtonian fluids using data of fluid density and drainage time collected from a Marsh Funnel as a function of viscosity. The funnel results for viscosity compare favorably to the values obtained from a commonly-used Fann 35 viscometer. Different quantities of bentonite, barite and other additives which have been used to prepare many samples. Empirical equations are obtained μapp. = ρ (t – 28) and μapp. = -0.0118t2 + 1.6175t - 32.168, where apparent viscosity (μapp.) in (cp), Marsh funnel time (t) in seconds and the density (ρ) in gm/cm3.

Hydrocarbon production might cause changes in dynamic reservoir properties. Thus the consideration of the mechanical stability of a formation under different conditions of drilling or production is a very important issue, and basic mechanical properties of the formation should be determined.There is considerable evidence, gathered from laboratory measurements in the field of Rock Mechanics, showing a good correlation between intrinsic rock strength and the dynamic elastic constant determined from sonic-velocity and density measurements.The values of the mechanical properties determined from log data, such as the dynamic elastic constants derived from the measurement of the elastic wave velocities in the material, should be more accurate than that determined by direct strength tests with core samples. This can be attributed to the scale effect and sampling disturbances.The aim of this study was to present methods of determining measures of some mechanical properties, from available well log data (conventional sonic, density, and gamma ray) for a well in North Rumaila field.The mechanical properties include formation strength and Poisson’s ratio. For the formation strength, combined elastic modulus (Ec) and shear modulus (G) were determined. The Poisson’s ratio was determined by using three different techniques to permit the accuracy of their values. The elastic modulus, shear modulus, and Poisson’s ratio were then correlated with depth and effective stress.The results show that combined correlations are important source of the prediction of overpressure zones which represent a major problem encountered in drilling and production process.