Caliper Logs Research Articles

Shale volume and porosity delineation of coast swamp depobelt in Niger delta region, Nigeria, using well log

Well log data from two wells were evaluated for shale volume, total and effective porosity. Well log data were obtained from gamma ray, neutron-density log, resistivity, sonic and caliper log respectively. This study aimed at evaluating the effect of shale volume, total and effective porosity form two well log data. The results of the analysis depict the presence of sand, sand-shale and shale formations. Hydrocarbon accumulation were found to be high in sand, fair in sand-shale and low in shale, since existence of shale reduces total and effective porosity and water saturation of the reservoir. The thickness of the reservoir ranged from 66 – 248.5ft. The average values of volume of shale, total and effective porosity values ranged from 0.004 – 0.299dec, 0.178 – 0.207dec and 0.154 – 0.194dec. Similarly, the water saturation and permeability ranged from 0.277 – 0.447dec and 36.637 - 7808.519md respectively. These values of total and effective porosity are high in sand, fair in sand-shale and low in shale formations. The results for this study demonstrate: accuracy, applicability of these approaches and enhance the proper evaluation of petrophysical parameters from well log data.

Inference of in situ stress from thermoporoelastic borehole breakouts based on artificial neural network

SummaryThe determination of in situ stresses is very important in petroleum engineering. Hydraulic fracturing is a widely accepted technique for the determination of in situ stresses nowadays. Unfortunately, the hydraulic fracturing test is time‐consuming and expensive. Taking advantage of the shape of borehole breakouts measured from widely available caliper and image logs to determine in situ stress in petroleum engineering is highly attractive. By finite element modeling of borehole breakouts considering thermoporoelasticity, the authors simulate the process of borehole breakouts in terms of initiation, development, and stabilization under Mogi‐Coulomb criterion and end up with the shape of borehole breakouts. Artificial neural network provides such a tool to establish the relationship between in situ stress and shape of borehole breakouts, which can be used to determine in situ stress based on different shape of borehole breakouts by inverse analysis. In this paper, two steps are taken to determine in situ stress by inverse analysis. First, sets of finite element modeling provide sets of data on in situ stress and borehole breakout measures considering the influence of drilling fluid temperature and pore pressure, which will be used to train an artificial neural network that can eventually represent the relationship between the in situ stress and borehole breakout measures. Second, for a given measure of borehole breakouts in a certain drilling fluid temperature, the trained artificial neural network will be used to predict the corresponding in situ stress. Results of numerical experiments show that the inverse analysis based on finite element modeling of borehole breakouts and artificial neural network is a promising method to determine in situ stress.

Vertical seismic profiling using distributed acoustic sensing with scatter‐enhanced fibre‐optic cable at the Cu–Au New Afton porphyry deposit, British Columbia, Canada

ABSTRACTWireline logs and vertical seismic profile data were acquired in two boreholes intersecting the main mineralized zone at the Cu–Au New Afton porphyry deposit, Canada, with the objectives of imaging lithological contacts, fault zones that may have acted as conduits that channelled the mineralization, and alteration zones. Log data provide physical rock properties for the main lithologies and alteration zones. Calliper logs reveal many faults and caved‐in zones generally indicating rocks with low integrity at the borehole wall. The preponderance of these zones, as indicated by the logs, suggests that their response may dominate the seismic‐reflection wavefield. Outside fault zones, compressional and shear‐wave velocities exhibit significant variability due to porosity, the heterogeneity of volcanic fragmental rocks and alteration. Distributed acoustic sensing was used to acquire vertical seismic profiling data in the two boreholes surveyed with wireline logs. Straight and helically wound fibre‐optic cables housed standard fibres and a fibre engineered to increase the intensity of backscattering at the distributed acoustic sensing interrogator. Standard and engineered optical fibres placed in the two boreholes were daisy‐chained together to form two 5‐km‐long continuous fibres that were interrogated at once with two interrogators. A new generation of interrogator connected to the engineered fibres provided field data with lower noise level and higher signal‐to‐noise ratio. These data with higher signal‐to‐noise ratio from straight fibre‐optic cable were processed and used for depth imaging. Depth images benefitted from new migration weights that account for the directional sensitivity of the straight fibre‐optic cable and limit the extent of migration artefacts. Migration results show several reflectors with shallow dips to the northwest, some explained by faults intersecting the surveyed boreholes. The main sub‐vertical lithological and alteration contacts at New Afton generated downgoing reflections that were not considered in the migration.

Characterization of non-matrix type and flow potential using lost circulation information

Lost circulation zones (LCZs) provide valuable information about the properties of non-matrix features – i.e., fractures and karst – intersected by wells during conventional drilling, including information about the type, size, connectivity and flow potential. The magnitude of the loss rate and lost volume should reflect the nature of the non-matrix feature responsible for losses. For example, the total volume lost in each of these zones provides a minimum volume of connected pore space, whereas the instantaneous rate of loss suggests whether the LCZ is due to drilling into a cave (high rate of loss) versus a fracture (low rate of loss). We define and quantify each LCZ from information recorded in the drilling reports including top and base of the LCZ, maximum loss rate, and cumulative volume lost to the zone. Once each LCZ has been identified from the drilling reports, we evaluate wellbore images and caliper logs across each anomalous zone to determine the cause of the loss event – e.g., caves or fractures. Results suggest that caves are typically characterized by high lost rates (>50 m3/h or 315 bbl/h), while fractures and touching vugs are characterized by lower rates (<50 m3/h or 315 bbl/h). Low rates and volumes in excess of 160 m3 (1006 bbl) appear to be related to fractures, while volumes below this threshold can be attributed to either fractures or touching vugs. This natural breakout between karst and fractures in particular, allows us to work in data challenged environments and use drilling data as a screening tool to evaluate whether the main non-matrix flow elements are fracture or karst dominated. A key product of this work is a volume versus rate (VvR) plot that typifies loss characteristics for specific non-matrix features, so that in the absence of image logs, it can be used to infer the causes of each LCZ event.

Type and distribution of Mid-Permian Maokou Formation karst reservoirs in southern Sichuan Basin, SW China

Abstract Based on the analysis of the responses of conventional logs such as natural gamma (GR), density (DEN), acoustic interval transit time (AC), compensated neutron (CNL), dual lateral resistivity (Rlld, Rlls), and caliper log (CAL), combined with drilling data, cores, thin section and productivity of 65 wells, the reservoirs in the Mid-Permian Maokou Formation of southern Sichuan Basin were divided into four types, fractured-vuggy, pore-vuggy, fractured and fractured-cavity. The main reservoirs in high productivity wells are fractured-vuggy and pore-vuggy. The reservoirs of Maokou Formation are generally thin, and can be divided into the upper reservoir segment (layer a of the second member to the third member of Maokou Formation, P2m2a-P2m3) and the lower segment (layer b of the second member of Maokou Formation, P2m2b). The two reservoir segments are mainly controlled by two grain beaches during the sedimentation of P2m2a-P2m3 and P2m2b, the vertical zonation of karst, and the fractures. The upper reservoir segment is generally better than the lower one in development degree and single well productivity, and is much thicker than the lower one. It is thicker in the Yibin-Zigong-Weiyuan-Dazu area, the southwestern area of Chongqing and the southeastern area of Luzhou, while the lower segment is thicker in the Neijiang-Zigong-Luzhou area and the Dazu-Luzhou area. The areas with big reservoir thickness at tectonic slope or syncline parts are the favorable exploration areas.

Potential hydrocarbon zone identification: a case study

Formation depiction is the progression that describes both physical and chemical properties of rocks and fluids through the exploitation of available log or core data. Geologic formations are generally heterogeneous in nature. Different types of well logs like caliper, SP, resistivity, gamma, sonic, neutron, and density logs are used to characterize formations. Formation temperature (Tf), porosity (Φ), permeability (k), formation water resistivity (Rwf), formation water saturation (Sw), etc. are the main characteristics of a reservoir. In this study, a gas field located in Brahmanbaria district, Bangladesh, with latitude 24° 00′ 58.6″ N and longitude 91° 07′ 14.4″ E is examined. The geothermal temperature gradient was 0.00735 °C/m with a temperature of 43.33 °C at depth of 3535 m. Four sand zones (identified as B, D, F, and H), four shale zones (identified as A, C, E, and G), and four sand mixed with shale zones (specified as I, J, K, and L) were mapped between depth 2800 and 3557 m. The average porosities (combining sonic, neutron, and density porosities) of zones B, D, F, and H were 25.5%, 26.2%, 23.95%, and 20.65%, respectively, with permeabilities of 84.26 mD, 49.64 mD, 35.01 mD, and 296.38 mD. Considering all the parameters (porosity, permeability, resistivity, and formation water saturation), it is shown that zone H (3036–3186 m) is a more effective gas production zone.

Geomechanical analysis on casing deformation in Longmaxi shale formation

Abstract Casing deformation is the most significant problem while developing Longmaxi shale gas formation in Sichuan Basin, southwest China. In one of the operating acreages with 72 horizontal wells, 38 wells encountered casing deformation problems after several stages of hydraulic fracturing treatments. Tremendous lateral lengths were affected, among which some of them were treated with diversion technology during fracturing and some others were simply abandoned. Previous research explores this problem from perspectives of cementing, casing strength and etc. However, after combining all the data, we found that it is likely due to formation slip. In this research, we summarized all the casing deformation positions happened in the area of interest. We then project these positions into the ant-tracking plot. It is found that most of the deformed positions correspond to the fault positions in the ant-tracking plot. Further, we run caliper logs for some of the wells. From the images of the deformed positions, it can be inferred that the casing deformation is due to the formation shear. Based on what we found, we set up a model for fault slip potential. This model is based on Mohr-Coulomb (MC) failure criteria. We use this model to analyze the natural fractures observed from an FMI log. It is found that the increase of pore pressure from hydraulic fracturing jobs can cause natural fractures to slip. However, it cannot cause beddings to slip, which some of the previous research has suggested. The data and analysis in this research confirm that casing deformation in Longmaxi shale formation is caused by fault slip. Other reasons, like voids in cement bond, lithological layers, are not detrimental to this problem. In the end, we presented a method for continuing treatment when casing deformation happens. This method has been utilized in field, and significant downtime is reduced.

Determination of coal layers using geophysical well-logging methods for correlation of the Gelik-Zonguldak and Kazpınar-Amasra (Bartın) coalfields, Turkey

The most commonly used well-logging methods for determining coal layers are radioactive (gamma ray, neutron and gamma–gamma) and electrical (resistivity, spontaneous potential and inductive polarization). Other methods that can be used are sonic, thermal, density, caliper and dipmeter logs. In the determination of the coal beds, the evaluation of the well-logs and the interactions between the boreholes are very important. The boundaries of the geological strata are determined by the logs, which are also spatially correlated. The decrease in gamma-ray values, low neutron density, high resistivity, characterize coal layers. Due to the presence of large coal reserves in this area, 81 boreholes have been drilled at the determined points in the long term. Radioactive and electrical well-logs have been applied to these boreholes in order to determine lithology and coal beds. In this study, three boreholes from Gelik-Zonguldak region and four boreholes from Kazpinar-Amasra (Bartin) region were selected and evaluated. Geophysical data were used for the determination of coal beds and correlation. Regional assessments were made with the lithological, structural and tectonic data.

The present-day state of tectonic stress in the offshore Kutch-Saurashtra Basin, India

Abstract Exploration activity in the Kutch-Saurashtra area has drawn major attention and because of the recent hydrocarbon discoveries offshore Kutch-Saurashtra basin is now moved from category III to II. Accurate understanding of the full present-day stress tensor and pore pressure is critical for field development. In this study, pore pressure, stress magnitudes and horizontal stress direction have been estimated from high resolution geophysical logs and various direct downhole measurements recorded in the studied offshore exploratory wells. Extensive availability of subsurface pressure measurements confirms hydrostatic pore pressure in the tertiary sediments. Magnitudes of vertical, minimum and maximum horizontal stresses indicate a strike slip tectonic stress regime. Wellbore breakouts of A-C qualities have been identified in density image logs and four arm caliper logs, indicating a NNE trend (N10°E to N20°E) of SHMax (maximum horizontal stress). The same has been confirmed from Shear wave anisotropy analysis as well. The interpreted stress direction is in good agreement with the World Stress map data available from the adjacent area. This study is significant in understanding the subsurface behavior during drilling, reservoir modeling, future well stimulation and production optimization.

A robust approach for determining borehole shape from six-arm caliper logs

We have developed a robust and reliable method for determining borehole shape from six-arm caliper logs. Four- and six-arm calipers are the common caliper tools used in open-hole logging. They provide information about wellbore geometry that is important in petrophysical and geomechanical analyses. The analysis procedure for four-arm caliper logs is well-established, but the analysis for six-arm caliper logs can be troublesome in complex hole environments containing breakouts or keyseats when the tool is off center. The challenge with the six-arm caliper is how to remove the effect of tool decentralization, which cannot be handled properly by using conventional correction methods, which are developed based on the assumption of circular or elliptical boreholes. To resolve this issue, we have developed a new approach for tool decentralization correction. The new method is based on an assumption that the true borehole center should be the center of a circle that fits the caliper pad positions in the least-squares sense subjected to the restriction that the circle is confined within the six pads. We first compare the new method with the conventional chord method and ellipse-fitting method through numerical modeling. We numerically investigate the general performance of these three methods by using a Monte Carlo approach to generate a large number of simulations that mimic caliper logging run in boreholes with a variety of different wellbore geometry. We then study the applicability of the new method in field data analysis by applying it to a field logging data set acquired in a well that contains the breakout and the keyseat. The modeling and field-data results indicate that the new method can yield more reliable estimates of the virgin borehole center than the other two methods and thus can give clearer delineation of the borehole shape.

In-situ stress inversion in Liard Basin, Canada, from caliper logs

This paper proposes an integrated method of analytical calculation, artificial intelligence, and probabilistic analysis to cost-effectively determine geomechanical properties and in-situ stresses from borehole deformation via caliper logs. It's also demonstrated in this paper that the actual borehole size can not be simply taken as the bit size by default, and adjusted borehole size has to be used to find the reasonable borehole deformation. In the proposed method, an artificial neural network (ANN) is applied to map the relationship among in-situ stress, adjusted borehole size, geomechanical properties, and borehole displacements. The genetic algorithm (GA) searches for the set of unknown stresses and geomechanical properties that match the objective borehole deformation function. Probabilistic analysis is conducted after ANN-GA modeling to estimate the most possible ranges of the parameters. The hybrid method has been demonstrated by a field case study to estimate the adjusted borehole size, Young's modulus, and the two horizontal in-situ stresses using borehole deformation information reported from four-arm caliper logs of a vertical borehole in Liard Basin in Canada.

Evaluation of Reservoir Properties Using Wireline Logs of Well Sarai-Sidhu-1, Punjab Platform, Central Indus Basin, Pakistan

The well Sarai Sidhu-01 is located on Punjab Platform, Central Indus Basin, Pakistan. Punjab Platform is the eastern part of Central Indus Basin, and tectonically it is the stable portion of Indus Basin, which was least affected during Tertiary Himalayan orogeny. This study attempts to decipher reservoir potential for hydrocarbon exploration. It aims to delineate a subsurface hydrocarbon bearing zone and to estimate the reservoir properties. A complete suite of wireline logs containing Caliper log (CALI), gamma ray log (GR), spontaneous potential log (SP), neutron log (ON), density log (OD), and resistivity logs (MSFL, LLS, and LLD) with all drilling parameters and well tops were utilized. The methodology adopted to accomplish this task includes the calculation of volume of shale (Vsh) by using gamma ray log and effective porosity (OE) by using density and neutron logs. Resistivity of water (Rw) was calculated by SPmethod, and the saturation of water (Sw) and the saturation of hydrocarbons (Sh) is calculated with the help of Archie’s equation. According to log signatures, Lumshiwal formation of early Cretaceous age encountered in well in the depth range of 5433 ft. to 5797 ft. was marked as a possible reservoir, and this zone was evaluated for its reservoir potential in detail using a set of equations. The average values calculated for different parameters are as follows: Vsh= 30%, OE= 17%, Sw= 46%, and Sh= 54%. The analysis shows that Sh is low, so it is inferred that Lumshiwal formation has a low potential and is economically not feasible for hydrocarbons production.

How do the geological and geophysical signatures of permeable fractures in granitic basement evolve after long periods of natural circulation? Insights from the Rittershoffen geothermal wells (France)

Two deep wells were drilled at Rittershoffen (Alsace, France) to produce high-temperature fluids to supply heat to a biorefinery. The GRT-2 production well was drilled to a depth of 3196 m MD and was deviated to target a permeable local fault in the granitic basement buried beneath a thick sedimentary cover. The objective of this study is to better understand the permeability of fractured reservoirs within crystalline rocks, focusing on the production well GRT-2. Based on a petrographic and mineralogical analysis of cutting samples, several granitic facies associated with hydrothermal alteration were identified on the basis of the amounts of illite, chlorite, anhydrite, secondary geodic quartz, and oxides. These observations were correlated with various geological and geophysical datasets (gamma ray, porosity, density, electrical resistivity, caliper, borehole image logs, temperature, rate of penetration, and mud losses) to localize and identify permeable fracture zones. In sections where acoustic image logs were not available, such as in the deepest part of the well, the geometries of the fracture zones were interpreted from an oriented caliper log. The caliper log interpretation detected one-third of the fractures detected by acoustic image logs. However, two major fracture sets striking N–S and dipping eastward or westward were observed. Furthermore, a synthetic resistivity log that fits the measured resistivity log relatively well was built using the Archie and Waxman and Smits models. This approach is a proxy for estimating the porosity and the mineralogical changes based on the cation exchange capacity, which is controlled by the chlorite/illite ratio, derived from electrical logs in granitic formations. The correlation of all these results allowed the identification of a resistivity signature of a permeable fracture zone that spatially fits with the temperature signature. The major contribution of this study is the identification of a hierarchy of permeable fractures based on petrophysical signatures. The geophysical signature of fracture zones with low residual permeability exhibits a broad depth extent, whereas the geophysical signature of a highly permeable fracture zone is more localized. Past hydrothermal circulation has enlarged the altered and porous zones around open fractures, and in some cases, intense illitization has plugged these fracture zones and reduced their permeabilities.

An approach for wellbore failure analysis using rock cavings and image processing

There have been interests to link different cuttings/cavings to various wellbore failure types during drilling. This concept is essential when caliper and image logs are not available. Identification of wellbore failure during drilling gives more chance of immediate actions before wireline logging program. In this paper, an approach was presented based on the image processing of ditch cuttings. This approach uses the sphericity and roundness of cuttings as input data to classify caving types and subsequently determine the dominant failure type. Likewise, common definitions of cavings were discussed initially before a new criterion is suggested. This quantitative criterion was examined by observations from caliper and acoustic image logs as well. The proposed approach and criterion were implemented on ditch cuttings taken from a well in Western Australia. Results indicate that the primary failure is shear failure (breakout) due to high levels of angular cavings. However, another failure due to the fluid invasion into pre-existing fractures was also recorded by blocky cavings.

Wellbore stability analysis during drilling through marine gas hydrate-bearing sediments in Shenhu area: A case study

Because of the metastable character of natural gas hydrate-bearing sediments (GHBS), they can be easily affected by drilling operations, thereby inducing the wellbore instability risk. This issue is studied in this paper by means of numerical simulations based on the first exploration well performed in the Shenhu area of the South China Sea in 2007. The corresponding simulated results were compared against the field caliper logging curve. Besides this analysis, the effects of both drilling mud properties (i.e., temperature, density, and salinity) and initial reservoir conditions (i.e., permeability, and saturation) on the wellbore stability were further investigated under the condition of drilling mud invasion into the GHBS. It is anticipated that the coupled multiphysics phenomena triggered under operation conditions can lead to wellbore instability and may also trigger the formation of fractures. The simulation results show that the predicted yield region around the borehole of well SH2 conforms to the borehole enlargement observed in the field. The sensitivity analyses indicate that a local increase in the pore pressure is likely to be generated in the wellbore vicinity, triggered by the large amount of free gas to be released during hydrate dissociation, which is in turn induced by heating (i.e., coming from the drilling-friction effects) and the high salinity of the drilling muds typically used. This study shows that by engineering the salinity of the drilling mud, the amount of free gas to be produced from marine GHBS can be controlled, preventing in this way further wellbore instability issues. This research also shows that an increase in the drilling-mud density not only impact on the development of pore pressures near the borehole, but it also affects the extent of drilling-mud invasion. This effect will extend the hydrate dissociation to a wider area and will also reduce the resistance of the formation, leading to further deformation and potential failure. The analyses also show that the increase in the initial hydrate saturation is associated with a stronger sediment and a more stable wellbore. The model also predicts that GHBS with higher absolute permeability will dissipate faster the excess of pore pressure in the surrounding sediment, contributing to wellbore stability; however, the extent of the hydrate dissociation zone will expand and thereby will increase the yield region.

Deformation mechanism of horizontal shale gas well production casing and its engineering solution: A case study on the Huangjinba Block of the Zhaotong National Shale Gas Demonstration Zone

In the Huangjinba Block of the Zhaotong National Shale Gas Demonstration Zone in the periphery of the Sichuan Basin, two horizontal shale gas wells suffer severe casing deformation. In this paper, the geological and engineering characteristics of the strata around the deformed casing interval were analyzed based on the 24-arm caliper measurement of casing deformation, open-hole caliper, electrical resistivity, drilling time and gas logging, cementing CBL∖VDL and CBL imaging. Then, 24-arm caliper measurement data were analyzed and 3D imaged by 3D imaging analysis software, to figure out the morphologic characteristics of deformed casing. It is shown that severe casing deformation tends to occur where structural fractures are developed. Besides, casing deformation is mainly in the form of “S”-shape bending vertically. The severely deformed casing is also characterized by obviously transverse shear deformation caused by the high-angle sliding compression of rocks. Therefore, some suggestions were proposed correspondingly. First, the countermeasures in this block shall focus on shear casing deformation caused by the sliding of rocks along the fracture face. Wellbore trajectory shall be designed based on the structural contours map of pay zones to bypass the “ridge” and “valley bottom” area in the local high and steep structural zones. Second, the distribution information of fractured zones shall be predicted based on the ant-tracking attribute volume distribution map of pay zones, so that the wellbore trajectory can run along the strike of fractured zone. And third, it is recommended to use plug-drilling free big bore bridge plug or full-bore infinite stage completion technique, so that the conventional bridge plug milling operation after fracturing can be omitted and each fractured layer can be put into production after fracturing.

The identification of coal texture in different rank coal reservoirs by using geophysical logging data in northwest Guizhou, China: Investigation by principal component analysis

Coal texture properties are one of important factors for determining the gas sorption capacity and transport properties. The recognition of coal texture with drilled cores or mining seam observation is direct and effective methods, but both methods are expensive and impossible for unexplored coal seams. The cut-off values logging data were applied in a few coal basins while the method ignores the effect of different coal ranks and is complicated with blurry boundary. In this study, 174 coal cores data obtained from 18 CBM wells were correlated with their geophysical logging responses in northwestern Guizhou Province. Four well-logging curves of the caliper logging (CAL), densities (DEN), natural gamma (GR) and deep lateral resistivity (LLD) were chosen to analyze coal textures. With progressive damage of coal, both values of CAL and LLD gradually increase while the DEN and GR tend to decrease. The identification index was reconstructed by using the principal component analysis (PCA) to identify coal texture of different coal ranks to improve the qualities of coal texture identification and reduce multiple solutions. The logging evaluation method for coal texture identification were applied in multiple coal seams in western Guizhou Province to validate the prediction method of logging data. The results show that PCA is feasible tool to analyze coal texture with improving accuracy and the well logging identification coal texture is good consistency with core identification in different rank coal.

Three-dimensional hydro-mechanical model of borehole in fractured rock mass using discrete element method

Borehole stability, in heavily fractured rock mass has been a significant issue in deep earth resources exploration and extraction. In this study, a three-dimensional model using 3DEC is developed to simulate a borehole drilled in fractured rock mass. A model with overbalanced drilling conditions is simulated in this study. In doing so, different depths of a borehole, MB-1 borehole, in Northern Perth basin was simulated. The developed model was validated against log measurements of Caliper log and strength of rock is found as a governing factor in controlling the stability. Then, hydro mechanical modelling was carried out and it was observed that high mud flow rates and high pore pressure increased the instability around borehole. Furthermore, a parametric study was performed to investigate the influence of viscosity and fluid flow on the stability. Shear displacement linearly increase with an increase in flow rate while fluid pressure decreases due to increase in fractures aperture with an increase in flow rate. Similarly, increase in viscosity caused increase in fracture shearing and therefore instability around borehole.

ANALYSIS OF DEEP STRESS FIELD USING WELL LOG AND WELLBORE BREAKOUT DATA: A CASE STUDY IN CRETACEOUS OIL RESERVOIR, SOUTHWEST IRAN

To identify the wellbore instability of Bangestan oil reservoir in the southwestern Iran, the direction and magnitude of stresses were determined using two different methods in this study. Results of injection test and analysis of wellbore breakouts were used to verify the accuracy of the stress profiles. In this study the Bartoon method, which using the breakout angle and strength of rock, was used. In addition, the ability of artificial neural network to estimate the elastic parameters of rock and stress field was used. The output of the neural network represents a high accuracy in the estimation of the desired parameters. In addition, the Mohr-Coulomb failure criterion was used to verify stress profiles. Estimated stresses show relative compliance with the results of injection test and Barton method. The required minimum mud pressure for preventing shear failures was calculated by using the Mohr-Coulomb failure criterion and the estimated stress profiles. The results showed a good compliance with failures which have been identified in the caliper and image logs. However, a number of noncompliance is observed in some depth. This is due to the concentration of fractures, collisions between the drill string and the wellbore wall, as well as swab and surge pressures. The stress mode is normal and strike-slip in some depth based on the estimated stress profiles. According to direction of breakouts which is clearly visible in the caliper and image logs, the minimum and maximum horizontal stresses directions were NW-SE and NE-SW, respectively. Thses directions were consistent with the direction of regional stresses in the Zagros belt.

Determination of In-Situ Stress and Geomechanical Properties from Borehole Deformation

This paper proposes a cost-effective technique to determine geomechanical properties and in-situ stress from borehole deformation data. In this approach, an artificial neural network (ANN) is applied to map the relationship among in-situ stress, borehole size, geomechanical properties, and borehole displacements. The genetic algorithm (GA) searches for the set of unknown stresses and geomechanical properties that matches the objective borehole deformation function. Probabilistic recapitulation (PR) analysis is conducted after each ANN-GA modeling cycle and will be repeated with a reduced number of unknowns for the next ANN-GA modeling cycle until unequivocal results are achieved. The PR-GA-ANN method has been demonstrated by a field case study to estimate borehole size, Young’s modulus, Poisson’s ratio, and the two horizontal stresses using borehole deformation information reported from four-arm caliper log of a vertical borehole. The methodology effectively solves the issue of the multiple solutions (various rock mechanical properties and in-situ stresses combinations) for a certain borehole deformation. The case study also indicated that the calculated horizontal stresses are in reasonable agreement with the filed hydraulic fracture treatment observations and the reported regional stress study of the area.