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An interpretive (structural and stratigraphic) study of the two,-dimensional seismic, data of East Nasiriya area (30 km to the south east of Nasiriya oil field within Thi-Qar province, southeastern Iraq) was carried out using Petrel 2017 program. The study area has an importance due to its location between many oil fields, but still without exploration of oil wells. Twenty five seismic lines were used, date back to different types of seismic surveys conducted in the region at different time periods. Also, the seismic velocity surveys of the nearest wells to oil fields, such as Nasiriya-1 and Subba-8, in addition to their sonic and density logs were used. A synthetic seismogram with a good matching with the seismic section was achieved to ensure the identification of the reflectors and reflectivity type (peak or trough) and follow up each one through the whole area of interest. Top Zubair reflector was picked using the composite line to link the seismic sections with each other after enhancing the ties between seismic lines. Time and depth maps were made using velocity maps created from the velocity model. The seismic, interpretation, in the area showed the existence of certain stratigraphic, features, in the ,studied reflector. Some distribution mounds and sand lenses were observed in the study area, which are continuous in more than two-dimensional seismic line in the area. These activity elements provide a reasonable explanation for the distribution of hydrocarbons in the area of study.

Norway’s Ringhorne Field is a faulted anticline, which produces oil from Triassic (Statfjord) and Paleocene (Hermod) sands. It is located on the Utsira High. Geochemical studies of the produced oil indicate that the oil is generated from mature Upper Jurassic marine shales in the adjacent Viking Graben. However, it is not clear how oil migrated into the Triassic reservoirs and charged the overlying Paleocene reservoirs. Lateral hydrocarbon migration is not detectable on seismic data. However, vertical hydrocarbon migration can be observed as a vertically aligned, low-amplitude, chaotic signature on normally processed seismic data. Gas-chimney detection is a proven neural network technique to detect these vertical hydrocarbon migration pathways. The processing results are then validated using a set of criteria to determine if they represented true hydrocarbon migration rather than seismic artifacts. The chimney processing results using this traditional (shallow) neural network are compared with convolutional neural network (deep learning) results and geomechanical modeling on key lines. Key reservoirs are delineated using a deterministic simultaneous seismic inversion approach. Reliable chimneys are then visualized in the vicinity of the producing reservoirs. The results indicate pathways by which the Triassic fluvial sands received the charge and how these reservoirs have flank leakage to provide the charge to shallower Paleocene reservoirs. This approach is currently being used over hundreds of fields and dry holes in the Norwegian North Sea and worldwide as analogs to assess the hydrocarbon charge and top seal risk predrill.

Affected by the surrounding injection and production wells, the formation near the infill adjustment well is in an abnormal pressure state, and drilling and completion operations are prone to complex situations and accidents such as leakage and overflow. The conventional shut-in method is to close all water injection wells around the adjustment well to ensure the safety of the operation, but at the same time reduce the oil field production. This paper proposes a design method for shut-in of water injection wells around adjustment wells based on injection-production data mining. This method uses water injection index and liquid productivity index as target parameters to analyze the correlation between injection and production wells. Select water injection wells with a high correlation and combine other parameters such as wellhead pressure and pressure recovery speed to design accurate adjustment schemes. Low-correlation wells do not take shut-in measures. This method was applied to 20 infill adjustment wells in the Penglai Oilfield. The correlation between injection and production wells was calculated using the data more than 500 injection wells and production wells. After a single adjustment well is drilled, the surrounding injection wells can increase the water injection volume by more than 5000 m3. This method achieves accurate adjustment for water injection wells that are high correlated with the adjustment well. Under the premise of ensuring the safety of drilling operations, the impact of drilling and completion on oilfield development is minimized, and oilfield production efficiency is improved. It has good application and promotion value.

The regular job of a reservoir engineer is to put a development plan to increase hydrocarbon production as possible and within economic and technical considerations. The development strategy for the giant reservoir is a complex and challenging task through the decision-making analysis process. Due to the limited surface water treatment facility, the reservoir management team focuses on minimizing water cut as low as possible by check the flow of formation and injected water movement through the Mishrif reservoir. In this research, a representative sector was used to make the review of water injection configuration, which is considered an efficient tool to make study in a particular area of the entire field when compared with the full-field model on the basis of time-consuming and computational analysis. The sector model was neighboring by extra grid blocks and three pseudo wells as injector wells to realize the pressure on the sector boundary, which attained an acceptable history matching. The fluid model and physics model were introduced by using Pressure Volume Temperature data of well involved in the study area and two relative permeability curves. Fourteen wells were utilized in this work, four wells are injectors, and the rest are producer. The development scenarios were implemented by setting various targets of oil production and different water injection rates required for pressure maintenance operations. Optimization of water cut has been applied by adjustment of production and injection rates and shut off the high water cut intervals. The results obtained from this study showed that the inverted 9-spot has a good recovery which is illustrated in the case_2C, the production rate was (49,000 STB/D) with minimum water cut (27.5%) as compared with a five-spot pattern.

The lithology of four formations from the Cretaceous period (Mishrif, Rumaila, Ahmadi, and Mauddud) was evaluated using the Acoustic Impedance and Vp/Vs ratio cross plot from Rock Physics Templates. Dipole sonic logs in Am-6-Am-10 well log were used to calculate compression velocity then the estimated shear velocity using Greenberg Castagna equations. RHOB and VP logs were used to calculate Acoustic Impedance. The ratio of Vp/Vs was measured then used with Acoustic Impedance colored by shale volume which is measured from gamma ray log, porosity and water saturation to estimate lithology type of the considered formations using cross plots and rock physics chart in the Techlog software. The lithology of the formations found to be of high porosity limestone alternating with hard limestone layers and the shale volume increases in the Ahmadi formation. The water bearing zone was found in all Formations, this zone is indicted by high Vp/ Vs ratio and low AI. The hydrocarbon bearing zones were indicated by low amount of both Acoustic Impedance and Vp/Vs ratio and this observation was shown in Mishrif and Mauddud formations.

Given the complexities of reservoir exploration and development, it is vital to understand the geomechanical properties of the reservoir and well in the drilling operation. In constructing a mechanical model of the earth, a combination of environmental geomechanical parameters, as well as the magnitude and direction of stresses, is used. In this study, stress analysis and its effect on azimuth well in deviated drilling in an oil field located in southwestern Iran are investigated. Necessary geomechanical parameters are estimated using density and slowness logs of sonic waves (shear and compression). The Mohr–Coulomb failure criterion is followed to determine a safe mud weight window. A mechanical model of the earth is designed using laboratory data and well logging, and it is validated by the results obtained from laboratory rock mechanics using the calibrated core samples. The results show that drilling in the azimuth at about 135° with an angle of about 15° is the most stable path for the well in the carbonate reservoir formation in the studied oil field.

Summary Lufeng oil field was discovered in the 1980s in the Pearl River Mouth Basin (PRMB) of the South China Sea and has entered the stage of secondary oil recovery. One major problem that has restricted the subsequent exploration of the oil field is the unclear regional reservoir and caprock distribution, because practitioners have been using post-stack attributes and acoustic impedance inversion to analyze the distribution of sandstone (reservoir) and mudstone (caprock). In current geophysical research on reservoirs and caprocks, prestack inversion has been widely used because of its advantage over post-stack inversion. However, the accuracy of using single P/S-wave velocity ratio (VP/VS) or density (Vden) inverted by prestack to predict lithology is still insufficient. In this study, we created a new attribute VRDEN, the sum of VP/VS and the weighted Vden, to capture the lithology variation of the reservoir. We integrated 3D seismic data and well log data and applied simultaneous prestack inversion and multiattribute regression analysis to determine reservoir properties, such as sand thickness, effective porosity, and distribution of sandstone and mudstone of the Lufeng oil field. Then, we calculated the new attribute VRDEN from VP/VS and Vden obtained from simultaneous prestack inversion to determine the lithology variation. The multiattribute regression analysis, combining prestack attributes and post-stack attributes, indicates the effective porosity and sand volume in the Enping Formation, which contains the main oil-bearing reservoirs in the Lufeng oil field. Results show that when the sandstone thickness is greater than 12.5 m, the prediction error of VRDEN is the lowest compared with VP/VS and Vden. In En-2 member of the Lower Enping Formation, medium- to high-porosity (14 to 17%) sandstone (19.5 m thickness) is widely distributed in the west and middle of the study area, with an area of nearly 300 km2. The high-porosity sand zones stretch from the east of the Lower Enping Formation to the west of the Upper Enping Formation, which is the result of westward progradation of the braided delta. Our workflow used a novel seismic attribute VRDEN in the simultaneous prestack inversion and multiattribute regression process to provide a more predictive spatial distribution of reservoir-nonreservoir features. The improved reservoir understanding will allow more efficient exploitation of the Lufeng oil field, and the improved workflow will facilitate exploration of other oil fields in the world.

The harvest of hydrocarbon from the depleted reservoir is crucial during field development. Therefore, drilling operations in the depleted reservoir faced several problems like partial and total lost circulation. Continuing production without an active water drive or water injection to support reservoir pressure will decrease the pore and fracture pressure. Moreover, this depletion will affect the distribution of stress and change the mud weight window. This study focused on vertical stress, maximum and minimum horizontal stress redistributions in the depleted reservoirs due to decreases in pore pressure and, consequently, the effect on the mud weight window. 1D and 4D robust geomechanical models are built based on all available data in a mature oil field. The 1D model was used to estimate all mechanical rock properties, stress, and pore pressure. The minimum and maximum horizontal stress were determined using the poroelastic horizontal strain model. Furthermore, the mechanical properties were calibrated using drained triaxial and uniaxial compression tests. The pore pressure was tested using modular dynamic tester log MDT. The Mohr–Coulomb model was applied in the 4D model to calculate the stress distribution in the depleted reservoir. According to study wells, the target area has been classified into four main groups in Mishrif reservoir based on depletion: highly, moderately, slightly, and no depleted region. Also, the results showed that the units had been classified into three main categories based on depletion state (from above to low depleted): L1.1, L1.2, and M1. The mean average reduction in minimum horizontal stress magnitude was 322 psi for L1.1, 183.86 psi for L1.2, and 115.56 psi for M1. Thus, the lower limit of fracture pressure dropped to a high value in L1.1, which is considered a weak point. As a result of changing horizontal stress, the mud weight window became narrow.

Background. This paper presents a study of the applicability and the first results of pilot works of the technology of periodic water injection into production wells with subsequent oil production (Huff and Puff ), which was not previously used in Russia. The oil field of the company “Gazprom Neft” with a terrigenous reservoir of low permeability is considered. Aim. It is planned to use the technology at marginal waterless wells with hydraulic fracturing, which are on the verge of profitability, to increase oil production. Materials and methods. The physical principles of capillary impregnation in a hydrophilic reservoir were presented, which, under given conditions, should lead to an increase in oil production in waterless wells during cyclic water injection and shutdown with subsequent production. Since this technology was not previously used in Russia, a review and analysis of the unsuccessful application in the United States and the successful experience in China in fields with similar properties and wells was carried out. For the design of pilot works, calculations were made on a synthetic hydrodynamic model with double porosity and permeability, according to which a significant increase in oil production in a marginal well was obtained relative to standard operation. Pilot work was carried out on four oil wells of the company’s field, which were previously planned to be transferred to the reservoir pressure maintenance stock. Only two of them managed to meet the required injection and shutdown periods. Results. Pilot work didn’t show significant increase in oil production after the application of the technology. At the same time, there was no decrease in representative wells, which should have occurred due to a decrease in the phase permeability of oil, which indicates the work of the effect of capillary imbibition during water injection. Conclusions. Based on the analysis of the ambiguous results of pilot works, a conclusion is made about the ineffectiveness of the huff and puff technology in the specified modes, the necessity of their optimization and further research.

Gas injection has been evaluated and implemented in the large carbonate oil field located offshore Qatar as water alternating gas or WAG. It has been seen that WAG is economically viable and a robust enhanced oil recovery (EOR) method for homogenous formations. However, using WAG in heterogeneous parts of the field has not been attempted due to issues like early gas breakthrough and unfavourable sweep efficiency. Hence, it was decided to design a foam-assisted WAG system that can provide the required conformance control to mitigate those issues and expand the use of WAG. A complete laboratory programme was carried out to screen the best foaming surfactant formulation that resulted in the selection of environmentally friendly, Alkyl polyglucoside (APG) surfactant. Surfactant testing involved foamability in porous media under oil-wet and water-wet conditions in presence of residual oil to gas flood. The chosen surfactant showed good foam strength in both cases with effective mobility reduction factors (MRF) above 20. The impact of mobile oil was also observed by co-injecting oil during linear core flood experiments, which clearly showed that good foam strength could be achieved in a lower flow fraction of mobile oil with foam. Additionally, boosting of foam strength using amphoteric Lauryl Betaine (LB) surfactant was also performed. The formulation with APG/LB (70%/30%) gives foam boosting of 2.5 times compared to foam strength using APG alone. Additionally, it was shown that altering wettability using a nonionic Tergitol surfactant (TGT-1) as pre-flush and then injecting APG-5 surfactant and methane resulted in foam strength, which is 1.5 times higher than observed in oil-wet conditions.

The objective of this paper is determining the petrophysical properties of the Mauddud Formation (Albian-Early Turonian) in Ratawi Oil Field depending on the well logs data by using interactive petrophysical software IP (V4.5). We evaluated parameters of available logs that control the reservoir properties of the formation, including shale volume, effective porosity, and water saturation. Mauddud Formation is divided into five units, which are distinguished by various reservoir characteristics. These units are A, B, C, D, and E. Through analyzing results of the computer processed interpretation (CPI) of available wells, we observed that the main reservoir units are B and D, being distinguished by elevated values of effective porosity (10%-32%) and oil saturation (95%-30%) with low shale content (6%-30%). Whereas, units A, C, and E were characterized by low or non-reservoir properties, due to high water saturation and low values of effective porosity caused by increased volume shale.

A seismic study was conducted to re-interpret the Qasab and Jawan oil field in northern Iraq, south of the city of Mosul, by reprocessing and interpreting many seismic sections of a number of field surveys that included the field area. Two reflectors are detected, represented by Hartha Formations which were deposited during the Cretaceous age and Euphrates Formation which was deposited during the Tertiary age in order to stabilize the structural image of this field. The study was achieved by reinterpreting seismic sections using the Petrel program, where time, velocity and depth maps were prepared for the two formations. The study showed that the Qasab and Jawan fields generally consist of a structural closure located at the wells of the northern dome. This closure extends to the south east and deviates towards the east in the form of a structural rift. The study concluded the existence of a transverse fault that cuts Qasab and Jawan structures, forming a structural trap that represents the southern part of Qasab structure.

The Compressional-wave (Vp) data are useful for reservoir exploration, drilling operations, stimulation, hydraulic fracturing employment, and development plans for a specific reservoir. Due to the different nature and behavior of the influencing parameters, more complex nonlinearity exists for Vp modeling purposes. In this study, a statistical relationship between compressional wave velocity and petrophysical parameters was developed from wireline log data for Jeribe formation in Fauqi oil field south Est Iraq, which is studied using single and multiple linear regressions. The model concentrated on predicting compressional wave velocity from petrophysical parameters and any pair of shear waves velocity, porosity, density, and fluid saturation in carbonate rocks. A strong linear correlation between P-wave velocity and S-wave velocity and between P-wave velocity and density rock was found. The resulting linear equations can be used to estimate P-wave velocity from the S-wave velocity in the case of both. The results of multiple regression analysis indicated that the density, porosity, water-saturated, and shear wave velocity (VS) are strongly related to Vp.

Summary Volumetric maximum curvature attribute computed from 3D ocean bottom cable (OBC) seismic data, production logging tool (PLT), inorganic chemical tracer data, and fractures observed from core and full-bore formation microimager (FMI) logs were integrated to characterize fractured carbonate reservoirs of an offshore oil field in Abu Dhabi, United Arab Emirates (UAE). The extracted maximum curvature anomalies are predominantly orientated in NNE-SSW and NE-SW, a trend perpendicular to the dominant fault direction in the oil field and similar to the dominant strike directions of fractures measured from core data and FMI logs. Because the fracture strike directions of well data mimic the strike directions of curvature anomalies at corresponding reservoir levels, we interpreted the maximum curvature anomalies to represent dilatational fractured zones or fracture corridors. Integration of dynamic data, such as PLT and chemical tracers, and maximum curvature anomalies demonstrate that the inferred fracture zones can determine water breakthroughs as well as inter- and intrareservoir communications. As a result, this study highlights possible fracture zones and their internal architecture, as well as their potential flow capabilities. These results play a key role in reservoir management and monitoring of water movement through structural pathways.

At present, reservoir whether isotropy or anisotropy is taking more attention, particularly the difference in (porosity, permeability, and capillary pressure) associated with pore space. These differences are due to the original sediments and thus diagenetic changes. It has been found that common models are insufficient to predict reservoir performance and field management program design. Recovery factor (RF) is the main factor affecting the optimization process for any reservoir that is very sensitive to reservoir heterogeneity and hence an accurate vertical and horizontal permeability (Kv and Kh) distribution is required. A case study is represented in this paper aimed at vertical permeability estimation from horizontal permeability and porosity for Mishrif reservoir in west Qurna/1 oil field southern Iraq. This study has been accomplished by testing five models, harmonic averaging, Kozeny-Carman equation, Zahaf and Tiab, Iheanacho et al., and Fazelalav to determine vertical permeability and comparing the results with core data values. It is found that the models were used showed an accuracy variation between the units of Mishrif reservoir based on Mishrif full diameter cores from 20 wells. Four new correlations are obtained for mA, CRII, mB1, and mB2 units for Mishrif Reservoir in West Qurna/1 oil field. The correlation shows that the permeability is depending on porosity in the mA unit due to the homogeneity and the Mb1 unit has a higher anisotropy than the other units.

Oil and gas reservoirs are of the main assets of countries possessing them. Production from these reservoirs is one of the main concerns of engineers, which can be achieved by drilling oil and gas reservoirs. Construction of hydrocarbon wells is one of the most expensive operations in the oil industry. One of the most important parameters affecting drilling cost is the rate of penetration (ROP). This paper predicts the rate of penetration using artificial intelligence and hybrid models on Kaboud oil field well #7 in the directional stage. In this study, different models were constructed through various approaches based on 1878 dataset obtained from drilling operation in the well#7. Then, the accuracy of the constructed models was compared with each other. It was found that the MLP-ABC algorithm predicts the rate of penetration more accurately, by far, as compared with other methods. The MLP-ABC algorithm achieves impressive ROP prediction accuracy (RMSE = 0.007211 m/h; AAPD = 0.1871%; R2 = 1.000 for the testing subset). Consequently, it can be concluded that this method is applicable to predict the drilling rate in that oilfield.

The structural division and stratigraphic estimation of the perceptible geological basin are the most important for oil and gas exploration. This study attempts to obtain subsurface geology in parts of east Nasiriya, southern Iraq using of seismic data and some adjacent well information for structural and stratigraphic interpretation. To achieve this goal, 2D seismic data in SEG-Y format were used with velocity and logging data. The seismic profile is then interpreted as a two-dimensional (time domain and depth domain) contour map, which is represented as a real subsurface geology. Reflectors from the Mishrif and Yamama Formations (Cretaceous period) were detected. According to the structural interpretation of the selected reflectors, TWT maps of the horizon were prepared, and depth maps were drawn, which show some noses structures in the study area. The seismic interpretation in this area confirmed the existence of certain stratigraphic features in the studied strata. Some distribution mounds and flat spots were also observed which similar to the characteristics of the Nasiriya oil field stratigraphic features that are the considered as hydrocarbon indicators.

This research includes structure interpretation of the Yamama Formation (Lower Cretaceous) and the Naokelekan Formation (Jurassic) using 2D seismic reflection data of the Tuba oil field region, Basrah, southern Iraq. The two reflectors (Yamama and Naokelekan) were defined and picked as peak and tough depending on the 2D seismic reflection interpretation process, based on the synthetic seismogram and well log data. In order to obtain structural settings, these horizons were followed over all the regions. Two-way travel-time maps, depth maps, and velocity maps have been produced for top Yamama and top Naokelekan formations. The study concluded that certain longitudinal enclosures reflect anticlines in the east and west of the study area representing Zubair and Rumaila fold confined between them a fold consist of two domes represents Tuba fold with the same trending of Zubair and Rumaila structures. The study confirmed the importance of this field as a reservoir of the accumulation of hydrocarbons.

The Albian Mauddud reservoir of the Khabbaz Oil Field is consisting of 170 m alternating shelf carbonates and pervasive dolomite horizons of coarse to fine crystalline mosaic. Core analysis and log measurements reveal the occurrence of three electrofacies units (A, B, and C) with variable petrophysical properties. Unit A with good reservoir quality shows average porosity of 18.8 % and average permeability of 27.5 md. The other two units (B and C) are less attractive and have an average porosity of 9.6 % and 9.2 % consequently. Pore size ranges between macro to meso types and related mainly to vugs, fractures and intercrystalline porosity, especially in the dolomite units. The reservoir fluids saturation, bulk volume, and mobility are evaluated using resistivity logs measurements and porosity logs (Neutron-Density porosities) in addition to other reservoir laboratory data. Calculations and cross data plotting of the related petrophysical parameters were applied to the three units of the Mauddud reservoir in seven wells of the field. It shows an overall good reservoir fluids mobility. Results indicate that the formation water of Khabbaz Oil Feld is a non-movable type especially for the crestal wells which make most of these wells produce water-free hydrocarbon. Variability within well’s hydrocarbon mobility is noticed and related to units and subunits lithology and porosity variation. Other variations seem to be related mainly to permeability, pores geometry and variability of water saturation in addition to the location of well with respect to oil pool within the field structure.

Archie’s parameters, cementation factor (m), saturation exponent (n) and tortuosity factor (a), are general factor that have effects on water saturation magnitude, due to their sensitivity to pores distribution, lithofacies properties and wettability, particularly in carbonate reservoirs. Water saturation magnitude has a direct effect in estimating initial oil-in-place values, and inaccuracy in its values will lead to huge impact errors in initial oil-in-place values, so it would affect the economics of field management and development plans. In this paper, the main objective was to investigate the impact of using conventional and modified Archie’s parameters in the determination of water saturation from well log interpretation for Tertiary reservoir in Khabaz oil field, a heterogenous carbonite reservoir in the north of Iraq which was affected by different digenesis processes that impacted the reservoir quality. Tertiary reservoir of Khabaz field consists of five geological units (A, B, C, D and E), and the selected well penetrated the top of the reservoir at 2200.5 m RTKB and passed through five geological units and reached total depth at 2348 m RTKB. The geothermal gradient of the field was 1.12 ℉ per 100 ft, and formation water resistivity (Rw) was about 0.029 Ω m. Water saturation was at first estimated from resistivity logs by Archie model with conventional known values of parameters (a, m and n) (1, 2 and 2), respectively, and then Archie’s parameters were modified and determined by graphical technique of Pickett plot for each geological unit to estimate water saturation. Finally, the results show the water saturation value was more sensitive for Archie’s parameter in low-porosity and high-clay-volume zone, but less sensitive in clean high-porosity zone, and water saturation values determined by modified Archie model were less about 18.5% at mean than their value by using conventional Archie’s parameters.

The injection experiment conducted at the Rangely oil field, Colorado, was a pioneering study that showed qualitatively the correlation between reservoir pressure increases and earthquake occurrence. Here, we revisit this field experiment using a mechanistic approach to investigate why and how the earthquakes occurred. Using data collected from decades of field operations, we build a geological model for the Rangely oil field, perform reservoir simulation to history match pore-pressure variations during the experiment, and perform geomechanical simulations to obtain stresses at the main fault, where the earthquakes were sourced. As a viable model, we hypothesize that pressure diffusion occurred through a system of highly permeable fractures, adjacent to the main fault in the field, connecting the injection wells to the area outside of the injection interval where intense seismic activity occurred. We also find that the main fault in the field is characterized by a friction coefficient μ ≈ 0.7—a value that is in good agreement with the classical laboratory estimates conducted by Byerlee for a variety of rock types. Finally, our modeling results suggest that earthquakes outside of the injection interval were released tectonic stresses and thus should be classified as triggered, whereas earthquakes inside the injection interval were driven mostly by anthropogenic pore-pressure changes and thus should be classified as induced.

The paper is devoted to joint application of 3D seismic survey and well logging techniques to study oil and gas presence in Maykop deposits in Naftalan oil field. The field is located in Naftalan-Northern Naftalan area of Ganja oil and gas province, Azerbaijan. The paper brings data about Naftalan field, the ancient brachianticline type of field in Azerbaijan. The paper also considers the history of study of the field by use of geological and geophysical techniques. Despite the studies cover the area since 1873, the oil and gas presence in Maykop has not been studied sufficiently due to sparse network of wells and insufficient amount of core samples. To avoid this gap the results of previous studies have been revised. Joint interpretation of well logging data acquired from 22 wells and data of 3D seismic survey covering the area has been done. On the basis of oil-saturation cube, we have designed the map (the area between the top and the foot of I horizon of Maykop) and 3D model of target interval. It has been defined that uneven distribution of oil saturation and poor oil recovery depends also on sedimentation environment, characterized by rapid subsidence of the basin and increasing amount of clay in the process of sedimentation. Our studies revealed that the average value of oil saturation varies as 0.5–0.6 and increases towards the North-East of the study area. In the final stage of the study we have presented the oil saturation cube and the map drawn on the basis of this cube.

This research is an attempt to solve the ambiguity associated with the stratigraphic setting of the main reservoir (late Cretaceous) of Mishrif Formation in Dujaila oil field. This was achieved by studying a 3D seismic reflection post-stack data for an area of ​​602.62 Km2 in Maysan Governorate, southeast of Iraq. Seismic analysis of the true amplitude reflections, time maps, and 3D depositional models showed a sufficient seismic evidence that the Mishrif Formation produces oil from a stratigraphic trap of isolated reef carbonate buildups that were grown on the shelf edge of the carbonate platform, located in the area around the productive well Dujaila-1. The low-frequency attribute illustrated that it is restricted in the area around the productive well Dujaila-1, which confirmed the existence of reef porous carbonate buildups and hydrocarbon accumulation in this region. The pay zone of the reef mound trap extends for about 7 km from the well Dujaila-1 toward the southwest side and 4 km toward the well Dujaila-2, without reaching it, which is explaining why it was dry. Therefore, this area to the south of the productive well Dujaila-1 represents a good area for low-risk drilling. Consequently, the hydrocarbon system observed in the Dujaila oil field provides a new opportunity to explore and produce oil in Mishrif Formation in other areas on the flank of the productive structures and in flat areas situated on the belt of the carbonate platform edge.

The study field has been an oil-producing area in southern Iran for nearly 50 years. Complex geological structure and varying levels of depletion scenarios require geomechanical analysis of the res...

More than 6 million tons of the oil have been extracted in the Skybа Zone of the Ukrainian Carpathians. In particular, 4.2 million tons of oil (85.7% of total production) were obtained from the Yamna sandstones of Paleocene, which are characterized by satisfactory physical properties. Most of the areas of fields that exploited them are located in the Boryslav oil and gas production area. Among them are such oil fields as Skhidnytsko-Urytske (more than 3.8 million tons of oil extracted), Violeta, Faustina, MEP, Miriam and Ropne. Outside this area, oil was extracted in Strilbychi and Staraya Sol. At most of these fields, oil horizons are at a depth of only 100-800 m. The gas and condensate are extracted at the field of Tanyavа in the wing of the Vytvytska Luska of the Berehova Skyba, which has been torn off by the thrust. In addition, a very large number of natural oil and gas manifestations - direct signs of oil and gas potential - have been recorded in the Skyba Zone. All this indicates the potential prospects of structures within the Skyba Zone, including shallow ones. The distribution area of Yamna sandstones is much larger than the area of these deposits. The distribution area of sandstones of Yamna is much larger than the area of these deposits. It occupies about half of the area of Skyba Zone. Part of it can be considered promising, removing areas where of Yamna sandstones are present on the day surface, although, even in such conditions, they are in some cases industrially oil-bearing (Strelbychi oil field). Sandstones of Yamna are characterized by satisfactory reservoir properties., The calculated porosity and permeability reach the maximum values at known deposits: 0.182 and 130 ∙ 10–3 microns2 respectively, and the estimated thickness of 13.5 m. In the Folded Carpathians and, especially, within the north-eastern fragments (Beregova, Oriv, Skoliv) in different years performed a large amount of field seismic surveys. On the basis of the obtained materials, for the first time in the Carpathian region structural constructions were made on the reflecting horizons in the Paleocene (Yamna Formation) and in the Stryi Formation of the Upper Cretaceous. This article evaluates the prospects of these research objects. The Khodkiv and Osichnyanska structures of Berehova Skyba are recommended for conducting search works.

In this paper, we attempt to predict the depositional environments with associated lithofacies of the main reservoir of the late Cretaceous Mishrif carbonate Formation, depending on the analysis of the created seismic isopach map by integrating seismic and well data. The isopach map was created from a 3D-seismic reflection survey carried out at the Dujaila oil field in southeastern Iraq, which is of an area of 602.26 Km2, and integrated with the data of the two explored wells. Based on the interpretation of the seismic isopach map, the diagram of the 3D-depositional environment model of Mishrif Formation was constructed. It showed three distinguished depositional environments, which were graduated from a back reef lithofacies of a shallow open marine (shelf) environment in the west and NW, to a shoal environment of isolated Rudist reefal buildup in the middle, and a fore reef lithofacies of the deep open marine basin environment in the SE of the field. A 3D-instantaneous frequency model was generated to verify the capability of the seismic isopach map of predicting the depositional environments, which in turn showed that the low frequency was restricted in the region of the high thickness of Rudist reefal buildups (porous reservoir facies) in the vicinity of the productive well Dujaila-1.

Permeability is one of the key parameters in reservoir property studies. The existing well log interpretation models could not predict the permeability accurately due to the complexity and ambiguity of well logging curves, and the prediction results may demonstrate significant contradictions with the production data. Based on the comprehensive analysis of cores, well logs, laboratory tests, and thin section observations, we take the first member of Liushagang Formation (L1) in Weizhou 11-1N Oil Field as the target, and select median grain size, porosity, and resistivity to establish a multiple nonlinear regression interpretation model of permeability. The accuracy and applicability of this model is validated by the laboratory test data and oil production performance. This permeability interpretation model is easy and practical to operate. Furthermore, it bridges the geological characteristics and the production performance.

This study presents is a classification of reservoir properties (porosity and shale volume) into rock types for carbonate Rumaila reservoir in Central Iraq (Ahdeb Field). The Cluster analysis method is used to identify rock types and to recognize well log clusters of similar characteristics. For most subsurface research, the determination of the rock type (lithofacies and petrofacies) is not adequate enough because of a lack of cores and cuttings. An interactive petrophysics software program was used to get the results of a cluster analysis technique, in order to determine the rock typing (log facies) in Rumaila formation units in the Ahdeb oil field. Initially, petrophysical parameters such as porosity, shale volume and quantity of various reservoir minerals were determined using the probabilistic evaluation process. In the second stage, the multi-resolution graphic clustering method was employed to separate the sequential electrofacies which resulted in the identification of four electrofacies with different geological reservoir properties. The vertical variations of the rock type for Rumaila formation are based on four log facial groups. These log groups are categorized according to porosity and shale volume of formation based on responses to well logs after division of Rumaila formation into four units (Ru-1, Ru-2, Ru-3, and Ru-4).A 3D rock type model for Rumaila Formation was performed using Petrel software in order to illustrate the horizontal distribution of rock type along the Ahdeb field and showing the best characterized of reservoir rock type in any unit of Rumaila Formation. Cluster analysis technique classified porosity and shale volume, which were calculated for Rumaila Formation using well logs, into four similar characteristics rock types: rocktype-1, rock type-2, rock type-3 and rock type-4. A 3D Petrel model of rock type shows that rock type-2 has better reservoir quality than other rock types in Rumaila Formation which is characterized by high porosity and low shale volume. The model clarifies the distribution of rock type-2 in the Ahdeb field at units Ru-1 and Ru-3 of Rumaila Formation

The distribution of alkanes in the Lower Cretaceous and Jurassic deposits of the Borovoye oil field, which is part of the East Sabun structural-formation zone of local compression in the eastern part of the West Siberian Plate, is considered. The core material of exploration wells was studied. The bitumoid of rocks contains C8–C40 hydrocarbons, including n-alkanes, isoprenoids, n-alkylbenzenes, naphthalenes, and phenanthrenes, this is determined by chromatography-mass spectrometry, and the molecular mass distribution of n-alkanes and isoprenoids is considered. The lithological and petrographic characteristics of the rocks were studied by optical microscopy. Based on the results of the analysis of hydrocarbons in the Jurassic sediments, a closed oil and gas complex is identified, it’s including: the parent rocks of the Tyumenskaya and possibly Marianovskaya formations, a reservoir in the upper Tyumenskaya and Naunakskaya formations, fluid barriers — the Marianovskaya formation at the top and the Radomskaya pack at the bottom. In the marginal parts of the complex, there is a drop in the concentration and depletion of the composition of hydrocarbons, which is characteristic of filtration. In the Cretaceous sediments, the transit movement of alkanes up to C21 from the Jurassic zone of oil occurrence is recorded. The composition and content of heavier hydrocarbons vary from layer to layer, probably a function of the syngenetic bitumoid of the rocks. In the considered sandstones of Cretaceous deposits, low concentrations of extracted organic substances are consistently recorded, without a significant trend within the section, which may indirectly indicate the absence of geological conditions for the accumulation of hydrocarbons and the formation of non-structural deposits in the Lower Cretaceous section of the Borovoye field.

The petrophysical analysis is very important to understand the factors controlling the reservoir quality and production wells. In the current study, the petrophysical evaluation was accomplished to hydrocarbon assessment based on well log data of four wells of Early Cretaceous carbonate reservoir Yamama Formation in Abu-Amood oil field in the southern part of Iraq. The available well logs such as sonic, density, neutron, gamma ray, SP, and resistivity logs for wells AAm-1, AAm-2, AAm-3, and AAm-5 were used to delineate the reservoir characteristics of the Yamama Formation. Lithologic and mineralogic studies were performed using porosity logs combination cross plots such as density vs. neutron cross plot and M-N mineralogy plot. These cross plots show that the Yamama Formation consists mainly of limestone and the essential mineral components are dominantly calcite with small amounts of dolomite. The petrophysical characteristics such as porosity, water and hydrocarbon saturation and bulk water volume were determined and interpreted using Techlog software to carried out and building the full computer processed interpretation for reservoir properties. Based on the petrophysical properties of studied wells, the Yamama Formation is divided into six units; (YB-1, YB-2, YB-3, YC-1, YC-2 and YC-3) separated by dense non porous units (Barrier beds). The units (YB-1, YB-2, YC-2 and YC-3) represent the most important reservoir units and oil-bearing zones because these reservoir units are characterized by good petrophysical properties due to high porosity and low to moderate water saturation. The other units are not reservoirs and not oil-bearing units due to low porosity and high-water saturation.

Thirty four cuttings samples from the Jurassic rock succession in well Balad-1 in the Balad Oil Field, Central Iraq have been collected. Using various organic geochemical techniques, the organic matter’s quantity, quality, maturity, and their source rock’s depositional setting were determined. The samples were evaluated to determine the amount of their organic matter content, type of organic matter, δ13C carbon isotopes abundance for both saturated and aromatic, and molecular properties. The results of organic geochemistry analysis show that Sargelu, Gotnia, and Chia Gara formations contain fair to decent amounts of organic matter. Naokelekan Formation encompasses fair to excellent organic matter, while Najmah Formation comprises very high to exceptional organic matter. The analyzed samples revealed the existence of kerogen types III and II/III mainly within oil window. Thermal maturity related biomarkers are in a good agreement with Rock-Eval parameters, but did not reach equilibrium phase. Source related biomarkers show that these rock units rich in organic matter were mainly deposited in an anoxic marine depositional setting which consists of carbonate influenced by terrestrial input.

Ahdeb is one of the Iraqi oil fields, its crude characterized by medium API (22.5-28.9) and highly reservoir pressure depletion from Khasib formation due to lack of water drive. This makes it difficult to produce economic oil rates. Therefore, many water injection wells were drilled by the operators to maintain the reservoir pressure during production. In addition to that, electrical submersible pumps (ESP) were used in some productive wells. This study suggests exploitation of gas associated with oil production to be recycled to lift oil as a substitute for the ESP .The work in this study includes using PIPSIM software to build a model of four studied productive wells (AD1-11-2H, AD2-15-2H, AD4-13-3H, A4-19-1H) after choosing the suited correlation for each well. According to the statistical results, Mukherjee & Brill correlation is the best option for all wells. The use of PIPESIM software include determining artificial lift performance to determine the optimum amount of gas injected, optimum injection pressure as well as the optimum injection depth and knowing the impact of these factors on production, as well as the determination of the optimal injection conditions when water cut changes. According to the current circumstances of the wells, the depth optimized for injection is the maximum allowable depth of injection which is deeper than the packer by 100 ft and the amount of injection gas is (1.5, 1, 1, and 1) MMscf/day for wells (AD2-11-2H, AD2-15-2H, AD4-13-3H, and AD4-19-2H) sequentially and injection pressure (2050, 2050, 2050, and 2000) psi for wells (AD2-11-2H, AD2-15-2H, AD4-13-3H, and AD4-19-2H) sequentially.

Petrophysical properties of the Mishrif reservoir at Noor oil field have been done. Based on the interpretation of the open hole data from wells (No-1, 2, 3, 4, and 5) .Which have been calculated total porosity, effective and secondary porosity, water and hydrocarbon saturation (moveable and residual hydrocarbon) in invaded and uninvaded zones. Depends on the calculated of petrophysical properties, Mishrif Formation can be divided into eight reservoir units (RU-1 to 8), separated by eight caped rock units (barrier) (Bar-1 to Bar8). Three-dimensional reservoir model of oil saturation was constructed using the Petrel Software, (2009). Distribution of these petrophysical properties for each reservoir unit within the studied field has been done. The results showed that the best reservoir units are the second, fourth and first reservoir unit. It’s worth mentioned here that the heterogeneity of the thicknesses of these units and its individual direction. In addition, observed that the oil saturation increases towards the north of the field at the well (No-5) and the center of the field at the well (No-4).

Single well modeling technique is considered as an important tool in simulation studies that deal with the near well issues (i.e. water coning, optimum perforation intervals, etc.); or it may be used in the determination of the final acceptability of the entire field model (1). In this study, this technique is adopted to study and characterize one of the producing wells in Buzurkan oil field which is BU-3. The probability of the increase of water production will be tested with different production schemes, because if the well has to produce with certain water rate, the surface facilities have to be designed to be suitable for that rate. Water saturation distribution around the well is also inspected through the history of the well to determine the reason behind water production. CMG simulator has been used to perform this study. The results matching are based on the pressure and the produced water cut history and show good match in both cases. The model showed that there is a significant increase in water production with increase of oil rate due to water coning.

An understanding of subsurface layers and their depth in oil and gas fields is one of the most important issues in all stages of field development from exploration to production. Several methods are available for studying subsurface geology. The geostatistical modeling method was used in this study. The subsurface layers and the structure of deep geology in an oil field were modeled and identified in the first stage, followed by identifying the areas prone to drilling mud loss in this oil field in the next stage. This study sought to develop a 3D model for the reservoir and the fractures in this formation by geostatistical methods. To develop this model, the data of 389 wells drilled in one of the southwestern fields of Iran were converted to a format suitable for entering the software after analysis, and the model was presented after data processing. The results of the study showed that the structure of subsurface geology in the studied oil field is of the asymmetric anticline type and most mud loss occurs in the western and southern parts of the oil field.

Oil field A, situated in Bohai Bay, was discovered in 1999 and has been developed as one of the most productive oil assets in China. It continues to hold significant growth potential for the future. Though the field contains a large amount of resources remaining to be developed, seismic imaging has been challenging in area 5, resulting in structural uncertainty for reservoir interpretation and well planning. In the past three decades, several 2D and 3D seismic surveys have been acquired, processed, and reprocessed in this area. However, due to the existence of complicated gas clouds, which are shallow, multilayered, and extensive, obscured sub-gas-cloud images appear in all legacy seismic results, making fault interpretation under the gas clouds almost impossible. To improve the sub-gas-cloud image and overall structural interpretability, a narrow-azimuth full-field ocean-bottom cable (OBC) acquisition was conducted in field A during 2018 and 2019, and later, a compressive seismic imaging (CSI)-based full-azimuth and large-offset OBC infill survey was acquired in area 5, covering the widest gas cloud. Through high-fidelity signal processing, full-waveform inversion (FWI)-driven velocity model building, and imaging using both Kirchhoff migration and reverse time migration (RTM), the seismic image quality beneath complicated gas clouds is improved significantly. It is the first time that sub-gas-cloud faults and the Base of Guantao event have been imaged by seismic without significant dim zones. CSI acquisition, FWI, and RTM are the key elements to resolve gas-cloud-related challenges in area 5.

Estimation of mechanical and physical rock properties is an essential issue in applications related to reservoir geomechanics. Carbonate rocks have complex depositional environments and digenetic processes which alter the rock mechanical properties to varying degrees even at a small distance. This study has been conducted on seventeen core plug samples that have been taken from different formations of carbonate reservoirs in the Fauqi oil field (Jeribe, Khasib, and Mishrif formations). While the rock mechanical and petrophysical properties have been measured in the laboratory including the unconfined compressive strength, Young's modulus, bulk density, porosity, compressional and shear -waves, well logs have been used to do a comparison between the lab results and well logs measurements. The results of this study revealed that petrophysical properties are consistent indexes to determine the rock mechanical properties with high performance capacity. Different empirical correlations have been developed in this study to determine the rock mechanical properties using the multiple regression analysis. These correlations are UCS-porosity, UCS-bulk density, UCS-Vs, UCs-Vp Es-Vs, Es-Vp, and Vs-Vp. (*). For example, the UCS-Vs correlation gives a good determination coefficient (R2= 0.77) for limestone and (R2=0.94) for dolomite. A comparison of the developed correlations with literature was also checked. This study presents a set of empirical correlations that can be used to determine and calibrate the rock mechanical properties when core samples are missing or incomplete.

The Mauddud reservoir, Khabaz oil field which is considered one of the main carbonate reservoirs in the north of Iraq. Recognizing carbonate reservoirs represents challenges to engineers because reservoirs almost tend to be tight and overall heterogeneous. The current study concerns with geological modeling of the reservoir is an oil-bearing with the original gas cap. The geological model is establishing for the reservoir by identifying the facies and evaluating the petrophysical properties of this complex reservoir, and calculate the amount of hydrocarbon. When completed the processing of data by IP interactive petrophysics software, and the permeability of a reservoir was calculated using the concept of hydraulic units then, there are three basic steps to construct the geological model, starts with creating a structural, facies and property models. The reservoirs were divided into four zones depending on the variation of petrophysical properties (porosity and permeability). Nine wells that penetrate the Cretaceous Formation (Mauddud reservoir) are included to construct the geological model. Zone number three characterized as the most important due to it Is large thickness which is about 108 m and good petrophysical properties are about 13%, 55 md, 41% and 38% for porosity, permeability, water saturation and net to gross respectively. The initial oil and gas in place are evaluated to be about 981×106 STB and 400×109 SCF.

Al-Ma'ail river is one of the small Iraqi rivers, as it extends over a distance of approximately 47 km. Al-Ma'ail river is located next to Halfaya oil field, which is the main source of pollution to Al-Ma’ail river, consequently, the environmental quality of Al-Ma'ail river is under great pressure from a variety of human activities. Although water is commonly used as an indicator of contamination by heavy metals, sediments are considered as water important in assessing the environmental situation. In this study, water and sediment samples were analyzed to assess the pollution status of heavy metals in Al-Ma'ail river, with the aim of determining its ability to sustain aquatic life. Samples were taken from five sites along Al-Ma'ail river between the branch area of Al-Ma'ail river from the Al-Kahla river (which also branches from Tigris River upon its exit from Amara City), until Al-Ma'ail river reaches pond of Umm Al-Na'aj (marshland). Ten Water and five sediment samples were collected in August 2020. Samples were analyzed for eight heavy metals: As, Cd, Cr, Cu, Pb, V, Ni and Zn, using AAS techniques. As for the water samples, all the concentrations were over the standards (except Zn which was within the limits in all samples), While Cu concentration in (samples SW1 to SW7) are within the standards (except SW8 and SW9 are close U.S.EPA and within WHO). Concentrations of heavy metals in sediments were over the limits in all samples. The bio-concentration values of heavy metals were calculated and all metal rates were found within the acceptable range for the U.S. EPA, except for vanadium, which was higher than the permissible limit and was a bio-accumulative and considered as an indicator of oil pollution. The results indicate the presence of long-term contamination of the eight selected heavy metals in the river sediments which may be of concern to the health of the aquatic ecosystem.

Static experiments and dynamic displacement experiments were conducted to quantitatively determine the amount of precipitate generated by the CO2-formation water reaction at different temperatures, pressures, and scaling ion concentrations during CO2 flooding in the Chang 8 block of Changqing Oilfield, the influence of precipitate on the physical properties of reservoirs was investigated, and the corresponding mathematical characterization model was established. The mathematical characterization equation was used to correct the numerical simulation model of E300 module in Eclipse software. The distribution pattern of inorganic salt precipitates during continuous CO2 flooding in Chang 8 block was simulated, and the influence of inorganic salt precipitates on oil recovery was predicted. The inorganic salt precipitate generated during CO2-formation water reaction was mainly CaCO3, and the pressure difference and scaling ion concentration were proportional to the amount of precipitate generated, while the temperature was inversely proportional to the amount of precipitate. The rate of core porosity change before and after CO2 flooding was positively correlated with temperature and flooding pressure difference. The core porosity increase in the CO2-formation water-core reaction experiment was always lower than that of CO2-distilled water-core reaction experiment because of precipitation. The area around the production wells had the most precipitates generated with the injection of CO2. The oil field became poor in development because of the widely distributed precipitate and the recovery decreased to 33.45% from 37.64% after 20-year-CO2 flooding when considering of precipitation.

A dozen of inversion methods are applied and tested to estimate the permeability of the area where gas-fingering event has taken place in an Iranian carbonate reservoir located southwest of Iran. In a previous work, the gas-fingering event was detected by inverting the 3D seismic data and in this study the permeability model in that area is estimated. Because the lateral area of the gas-fingering event is narrow, the whole system conducting the injected gas can be considered as one rock unit system and therefore the assumption of horizontal linear steady-state flow can be applied. Inversion methods are exploited to determine the permeability in the interval of interest. The interval of interest is located at the crest and involves four wells among which one is the gas-injection well. To investigate the feasibility of such an approach and select the best possible inversion method, first a controlled experiment for the system is designed and studied. The porosity values of the system are known from seismic data inversion and the permeability values are the desired parameters. The permeability values at well locations are known via well-test data and are used as constraints in the inversion procedure. The interval of interest is discretized and a simulator is used to simulate the fluid flow in the controlled system in order to apply and validate the inversion methods. All calculations are performed in the MATLAB environment. According to the results from the controlled experiment, the Maximum Entropy and Total Variation methods were found to be the best two inversion methods which were successful in retrieving the true permeability model. Similar comparative study using different inversion methods is performed for the real case for which the results retrieved by the Total Variation method is most reliable as it suggests the best recovery of the permeability value for the check-well. An estimation of the fracture permeabilities for the area under study also indicated that the inverted permeability values are most representing the fracture permeabilities rather than the matrix. The results of this study will be used to tune the field simulation model in terms of rock and fluid properties, consider the inverted permeability model as further constraints for the reservoir history-matching of the oil field, reconsider the factors involving the gas injection plan for the oil field, and obtain insights for further field development plans in other nearby oil fields.

The article substantiates the need to perform additional experimental studies of reservoir fluids, the results of which are used as input data for the implementation of oil field development projects. The methods of experimental research used in «Giprotyumenneftegaz» are briefly described and their main features are described.

Geological modeling is very important in reservoir study, where it is described the framework of the structure and provided a distribution of petrophysical properties, the geological model helps to comprehend the fluid flow behavior affected by the heterogeneity of reservoir, also it is used to calculate oil initially in place and to choose the new well location in reservoir management. In this study, a geological model is built for Nahr Umr Formation based on data of 11 wells (SU-2, SU-3, SU-4, SU-5, SU-6, SU-7, SU-9, SU-10, SU-11, SU-13, and SU-14), including the location of wells, well tops, also contour map of the Nahr Umr Formation in Subba oil field is utilized. The structural model is constructed for the Nahr Umr Formation, which consists of two domes. The formation is composed of sandstone mainly interbedded with shale. The formation is divided into four units (B1, B2, C1, and C2) depending on well log data, each unit is divided into layers for getting better distribution of petrophysical properties, where unit B2 is divided to the number of layers is higher than other units due to its heterogeneity. The variogram is used as a geostatistical method to predict the petrophysical properties at unsampled locations, experimental variogram is calculated from well log data in a horizontal and vertical direction. The spherical variogram model shows a good fitting with the experimental variogram. Sequential Gaussian algorithm is used in distribution of petrophysical properties in a geological model which shows good petrophysical properties in unit B2 and unit B1, while units C1 and C2 are highly saturated with water.

Hydraulic fracturing has been used as one of the stimulation techniques to economically increase oil and gas production by creating small cracks in subsurface geologic formations to allow oil or gas to move toward a producing well. Hydraulics plays a vital role in many oil field operations including drilling, completion, fracturing and production. In the case of fracturing, however, the role of hydraulics becomes important since optimized hydraulics can minimize the cost and conversely, any miscalculations may cause problems such as the fluid loss or may potentially even lead to loss of the well. The current methods of the hydraulic calculation for non-Newtonian fluids necessitate determination of the robust model. This paper presented a new method for calculating pressure losses in the hydraulic fractures. The objective of this study was to develop the generalized model for hydraulic calculation for non-Newtonian fluid and run the case studies for the model validation. In the present work, detailed algorithm for the hydraulic calculation has been developed and then programmed in C++. The only input to the program is the raw rheological data, shear stress versus shear rate and the geometrical characteristics of the slit. Model validation with the new method has established a very small percentage difference between the values predicted by the model and experimental data. The results demonstrate that the new method is accurately predicting the pressure drop in both laminar and turbulent flow regimes. It is shown that the fluid behavior is more accurately represented using the new method than that with the standard fluid models available in the petroleum industry. Further validation and development to be carried out using experimental data for variety of fluid types.