Oil Field

The present study is focused on formation evaluation of the Lockhart Limestone in two wells (Meyal-05P and Meyal-10P) located in Northern Deformed Potwar Zone of the Potwar sub-basin, Pakistan. The geological formations ranging from Triassic to Pliocene have been drilled in these wells. The formation evaluation of the Lockhart Limestone mainly involves reservoir potential evaluation, interpretation of depositional environment and transgressive-regressive sequences using petrophysical logs. In either wells, the reservoir characterization is steered by various petrophysical parameters including calculation of volume of shale, porosity, permeability and hydrocarbon saturation. The thickness of the Lockhart Limestone is 50 m and 77 m in the Meyal-05P and Meyal-10P wells, respectively. In Meyal-05P and Meyal-10P wells, the average petrophysical parameters values and ranges are given as follows: volume of shale 48% and 20%; density porosity 1-5.6% and 1-31.7%; neutron porosity 1-23% and 1-42.9%; sonic porosity 1-29% and 1-39%; effective porosity < 1-> 5% and 1-21%; and hydrocarbon saturation 92.21-99.8% and 97-99.6%. The petrophysical parameters indicate that the Lockhart Limestone of Meyal-10P well is quantitatively better reservoir than that of the Meyal-05P. In Lockhart Limestone of either wells, the permeability is < 0.1 mD. The bulk volume water deciphered the presence of vuggy and intercrystalline porosity in the Lockhart Limestone. Similarly, the lithological interpretation using logs shows mainly limestone with minor shales. Different electrofacies are interpreted from the log trends of gamma ray log such as aggrading, prograding and retrograding depositional sequences deposited in tidal channel fill, shallow water, shore line and offshore buildup and regressive-totransgressive shore face depositional setting.

This study tried to monitor sugar cane condition surrounding of oil and gas field area. The spectral approaches were conducted for mapping sugar cane stress. As an initial stage Landsat-8 was corrected radiometrically and geometrically. Radiometric correction is an important stages for spectral approaching. Then all pixel values were transformed to the surface reflectance. Several vegetation indices were calculated to monitor vegetation stress surrounding of oil and gas field. NDVI, EVI, DVI, GVI, GRVI, GDVI and GNDVI were applied for generating tentative sugar cane stress images. The results indicated that sugar cane surrounding of oil and gas field has been influenced by oil and gas field.

This study tried to monitor sugar cane condition surrounding of oil and gas field area. The spectral approaches were conducted for mapping sugar cane stress. As an initial stage Landsat-8 was corrected radiometrically and geometrically. Radiometric correction is an important stages for spectral approaching. Then all pixel values were transformed to the surface reflectance. Several vegetation indices were calculated to monitor vegetation stress surrounding of oil and gas field. NDVI, EVI, DVI, GVI, GRVI, GDVI and GNDVI were applied for generating tentative sugar cane stress images. The results indicated that sugar cane surrounding of oil and gas field has been influenced by oil and gas field.

Numerous studies have investigated the fundamental mechanisms by which CO2 flooding can increase oil production by altering the properties of the hydrocarbon fluid, including oil swelling, viscosity and interfacial tension reductions, and the extraction of light-to-intermediate components. However, the interactions between CO2 and hydrocarbon fluid may also cause several problems, such as asphaltene precipitation due to crude oil&#39;s instability during the CO2 flooding process. This study investigates the complex factors that affect the instability of crude oil, including CO2 injection pressures, temperatures, and crude oil compositions. The light-dead oil samples taken from two Indonesian oil fields were used. The impacts of the instability of crude oil on CO2 displacement performance were also observed to evaluate oil recovery and minimum miscibility pressure (MMP). The observation was performed using a slim tube under varying CO2 high-pressure injections at 90 °C and 70 °C. The...

This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. SPE-227845-MS the approach simplifies facility requirements, minimizes environmental and safety risks associated with handling high-H 2 S flows, and translates to lower equipment and maintenance expenditures related to the subsurface. The field data supports the conclusion that subsurface dilution enables safe well operations, by reducing the rupture exposure radius (RER). This deleted section is not necessary. This technology will help to unlock the sour gas potential at reduced costs. The rigless and remotely operated system allows wells to be quickly restarted, enhancing production continuity, reducing non-productive time (NPT), and extending well lifespan. The flexibility of the system also permits dynamic responses to fluctuating H 2 S levels without costly interventions, securing long-term cost savings and increased profitability. The rigless downhole gas sweetening using insert string e.g. inverse gas lift system presents a breakthrough in high-H 2 S well management by using precision downhole gas dilution to optimize production and reduce processing costs. Its rigless, versatile design promotes sustainable H 2 S management, enhances well productivity, and extends operational efficiency without requiring rig-based intervention. This adaptable, proactive approach to H 2 S management supports industry sustainability goals by offering a low-impact, optimized solution for managing high-H 2 S reservoirs.

This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited.

The northern region of Mozambique has a complex geological history, with an evolution that spans from the Precambrian Era to the Phanerozoic Era. In this work, we have integrated gravity and geothermal data to delineate the geotectonic evolution of the region, by estimating the thickness of the crust and the lithosphere through which was essential to generate a representative crustal model. It was necessary to complement the knowledge of structural geometry and tectonic evolution of the region. The data used in this study are the Bouguer and geoid anomalies, topography data, and radiogenic heat. These data were pre-processed, topography and geoid anomaly data were filtered by low-pass filter in the frequency and harmonic domains to remove undesirable effects associated with the sources. The data were used to estimate the thickness of the crust and lithosphere, as well as to determine the mean density distribution within the mantle. This was achieved by using a one-dimensional approach, considering the principle of local isostatic compensation, associated with equations governing the distribution of temperature in the crust. The Bouguer anomaly was used to generate a representative crustal 2D model of this region. The results showed that the crust is thinner in Nampula and Cabo Delgado provinces, with thickness ranging from 27 to 31 km, whereas in Niassa varies between 33 and 39 km. The analysis of lithospheric thickness indicates that the provinces of Nampula and Cabo Delgado present a thinning of the lithosphere, with values ranging from 150 to 165 km. Rather than Niassa province which exhibits a thicker lithosphere, ranging from 165 to 195 km. The obtained results underwent a comparative analysis with prior investigations, unveiling a noteworthy concurrence among these findings.

The success, safety and stability of treatment methods of bottomhole formation zone depend on adequate bottomhole pressure. The latter is not directly controllable, but it can be changed by adjusting injection pressure. Using the Paccaloni method for any given measured injection rate, the downhole injection pressure can be estimated. In this paper, the Paccaloni method was developed, and the pressure drop changes in the skin zone for horizontal and vertical wells were estimated for planning acid treatment of the bottomhole formation zones in vertical, deviated and horizontal wells. To model pressure and velocity distributions in the bottomhole zone for the case of water injection in a vertical and horizontal wells COMSOL Mathphysics modules were used.

Four subsurface sections and electrical, porosity logs, and gamma-ray logs of the Khasib Formation (age Late Turonian-Lower Coniacian) were studied to identify reservoir characteristics and to evaluate the reservoir properties of the Khasib reservoir units in the East Baghdad oilfield. The lithology of the formation is limestone throughout the whole sequence in all studied wells EB-83, EB-87, EB-92, and EB94. It is bounded conformably from the top by Tanuma Formation and has a conformable lower contact with Kifl Formation. The lower and upper boundaries of the formation were determined using well log analysis, and the formation was divided into three main rock units (Kh1, Kh2, and Kh3), depending on the porosity logs. The porosity was calculated using acoustic or sonic, neutron, and density logs. The effective porosity (average 0.0 -0.32 %) is the predominant porosity in the formation and to less extent; the secondary porosity. The volume of shale is very low (average 0.0 -0.13 %), indicating limestone is the main rock of the Khasib Formation. The study of the reservoir water (average 0.11-1.0%) and hydrocarbon saturations (average 0.0 -0.88 %) showed that the formation contains varying proportions and quantities of water and hydrocarbons suspended in the wall void, and hydrocarbons capable of being produced. The lithological study reflected that the predominant lithic formation is limestone. It was found that Kh 2 unit is the best oil reservoir unit in all selected wells in terms of porosity, water saturation, diagenesis processes, and microfacies analysis.

This article provides a comprehensive reservoir assessment of five wells in the OSA oilfield, Niger Delta, utilizing well log data. The distributions and thicknesses of sand bodies were ascertained within each well in the field utilizing interactive Petrel subsurface software. The quantitative analysis was conducted for the five exploratory wells, with depth ranges of 9476-11234ft for the OSA-11, 10585-11952ft for the OSA-22, 10242-12145ft for the OSA-33, 10282-11656ft for OSA-44 and 9905-11358ft for OSA-55. Five separate porous sand formations were detected in the field (Sand_A1, Sand_B2, Sand_C3 and Sand_D4 and Sand_E5). A petrophysical examination was conducted using a set of wire-line logs, including gamma ray, resistivity, neutron, and density logs from the wells. The average gross thickness of the five reservoirs defined was 3316.76ft, while the average net reservoir thickness was 2660.17ft and the average net pay thickness was 1047.96ft. The calculated shale volume varies from 21 to 32%, with average porosity ranging from 14 to 19% and average water saturation ranging from 35 to 54%. The research provided a foundation for identifying and evaluating hydrocarbon-bearing formations. Furthermore, the research will give adequate background for petroleum engineers to evaluate hydrocarbon reservoirs, plan well completion, and optimize production operations throughout the reservoir's lifespan.

This study is intended to expand the scope of microbial enhanced oil recovery (MEOR) simulation studies from 1D to field scale focussing on fluid viscosity variation and heterogeneity that lacks in most MEOR studies. Hence, we developed a model that incorporates: (1) reservoir simulation of microbe-induced oil viscosity reduction and (2) field-scale simulation and robust geological uncertainty workflow considering the influence of well placement. Sequential Gaussian simulation, co-kriging and artificial neural network were used for the petrophysical modelling prior to field-scale modelling. As per this study, the water viscosity increased from 0.5 to 1.72 cP after the microbe growth and increased biomass/biofilm. Also, we investigated the effect of the various component compositions and reaction frequencies on the oil viscosity and possibly oil recovery. For instance, the fraction of the initial CO2in the oil phase (originally in the reservoir) was varied from 0.000148 to 0.005 to p...

Most of the productive oil fields around the world are water drive reservoirs where water influx has the potential to improve oil recovery considerably. Verifications are required to illustrate the aquifer activation and this needs assessment programs to include diagnosis, classifications and aquifer characterization using mathematical models for accurate simulation of the aquifer behavior. In Qaiyarah Oil Field, there is a big lack in subsurface data to confirm the aquifer&#39;s level of activity although there are some traces of water production from the wells located at the southwest of the field. Based on this fact, a base case simulation has run through making history match for the production and reservoir pressure to confirm the activation of the aquifer. The results showed a fast decline in the reservoir pressure which mismatched the current measured pressure from the field. This led to adopt the option of modelling a simulated properties aquifer to match the production and p...

Matrix acidizing is a good stimulation process in which acid is introduced into the reservoir near the wellbore area via the wellbore or coil tubing. In the oil industry, formation damage is a prevalent problem. Bypassing wellbore damage by producing wormholes in carbonate reservoirs is the main purpose of acidizing the matrix of the formation. When doing lab tests, scientists are looking for a wormhole-inducing injection rate that can be used in the field. Meantime the ongoing works on the Ahdeb oil field&#39;s Mishrif reservoir, several reports have documented the difficulties encountered during stimulation operations, including high injection pressures that make it difficult to inject acid into the reservoir formation; and only a few acid jobs have been successful in Ahdeb oil wells, while the majority of the others have been failures; For this formation, there is a high incidence of oil well stimulation failed. This requires more study. Thus, in this work, we experimented to exa...

Buzurgan oil field suffers from the phenomenon of asphaltene precipitation. The serious negatives of this phenomenon are the decrease in production caused by clogging of the pores and decrease in permeability and wettability of the reservoir rocks, in addition to the blockages that occur in the pipeline transporting crude oil. The presence of laboratories in the Iraqi oil companies helped to conduct the necessary experiments, such as gas chromatography (GC) test to identify the components of crude oil and the percentages of each component, These laboratory results consider the main elements in deriving a new equation called modified colloidal instability index (MCII) equation based on a well-known global equation called colloidal instability index (CII) equation.    The modified (MCII) equation is considered an equation compared to the original (CII) equation because both equations mainly depend on the components of the crude oil, but the difference between them lies in the fact tha...

Depending on the information of some drilled wells in West Qurna oil field (WQ-404 vertical , WQ-416directional and WQ-271 directional high angle deviated well) and horizontal well (HF-69) in Halfaya oil field and studying all the factors affecting the hole cleaning beside the field observations with experience , a horizontal drilling program for West Qurna oil field was prepared. This study aims to introduce a plan to drill a horizontal well in West Qurna oil field due to absence of such well type. This proposal consists of complete drilling plan start by bottom hole assembly (BHA design), casing seat with cementing operation, and mud properties. The available geological information was taken into consideration during the design of the present proposal. .

The Balkassar oil field is situated in the eastern Potwar subbasin, lies on the southern flank of Soan syncline in Himalayan collisional regime. The area represents Indo-Pak and Eurasian blocks of Precambrian to recent time. Thrusting and folding of Himalayan, Indo-Pak plate movement and Salt Range uplift form the structural trap in Balkassar sub-surface (Balkassar anticline). On the basis of information from eleven seismic 2D lines and wells data six reflectors well data, four faults were identified and marked. The structural trend is northeast southwest. Interpretation of seismic 2D data reveals that the study area has undergone intense deformation as a consequence of development of thrusts and backthrusts. The Balkassar anticline is bounded by two thrust faults one from southeast and the other from northwest. Time and depth contour models shows that anticline limbs at north-western side are steep as compared to south-eastern limbs. Seismic interpretation indicates the presence of well-developed anticline bounded by three faults in the cover sequence and one fault in basement and thus the structure may act as a trap for hydrocarbons. The petrophysical analysis of Balkassar-OXY-1 well shows about 83.1% hydrocarbons saturation in the reservoir rocks, hence this study suggest that Balkassar Oilfield has potential to produce hydrocarbons.

The Zagros Fold and Thrust Belt in Iraq contain host prolific hydrocarbons and recently, significant oil reservoirs have been discovered in the Jurassic carbonate rocks. The current work focuses on Water and Hydrocarbon Saturation in the carbonate rocks of the Sargelu Formation (Middle Jurassic) based on a set of conventional Wireline logs which are: Gammaray, Neutron porosity, Bulk Density, three sonic types, all Resistivity, photoelectric, uranium, thorium, and potassium. The Wireline log shows that the Sargelu Formation can be divided into five units based on lithology. These units were derived from different cross plots. The computation of petrophysical properties of this carbonate reservoir is complex due to several washouts and heterogeneities, caused by the exposure of shale which is strongly influencing the reservoir saturation. The Wireline log shows that the average Water saturation in the carbonates of the Sargelu Formation is 20%, with an irreducible Water saturation of 0.2% and an average Hydrocarbon saturation of 30%. Whereas, the water resistivity is 0.03 ohm.m and the Mud filtration resistivity is 0.17 ohm.m.

In open-pit mining, particularly in large-scale operations, the stability of slopes and rock walls is a crucial factor determining the safety and operational status of the mine. A slight change in the slope of the mine walls can lead to a significant increase or decrease in the amount of waste material extracted, thereby profoundly affecting both the economics and safety of the mining operation. Therefore, geotechnical investigations and studies for the design and stability of open-pit walls hold particular importance. The Mouteh Gold Mine is considered one of the major mines operated by the Iranian Mineral Production and Supply Company. Estimating the rock mass strength parameters is one of the most significant challenges in rock engineering. Determining geomechanical and structural properties is essential for modeling and designing the extraction pit. One approach to controlling the behavior of mine walls involves monitoring the final walls and analyzing their displacement magnitude and rate, which helps identify areas with potential instability and issue warnings to prevent accidents. This monitoring can be conducted in both surface and subsurface conditions, each requiring specific tools and methodologies. In this paper, laboratory results and field surveys are utilized to determine these properties.

Evaluation, Lower Safa reservoir, “Pepi” field, Shushan Basin, North western desert, Egypt. The Middle Jurassic Lower Safa Member serves as a hydrocarbon reservoir in Shushan Basin, North Western Desert, Egypt. The present work deals with studying the subsurface setting and reservoir properties of this member to assess its hydrocarbon potentiality in the Pepi field. Seismic interpretation of thirty 2D seismic sections was used to determine the geometry and the detailed structural properties affecting this member. Well-log data available from five well-logs (Pepi-1X, Pepi-2, Pepi-5, Pepi-6, and Pepi-8) was utilized to determine the various reservoir parameters distinguishing the pay zone to highlight the promising locations for further exploration and development. Interpretation of the seismic data showed two master faults (F1 and F2) forming a half-graben block that trends NW-SE and NE-SW, respectively. These faults reflect the structural control of hydrocarbon accumulation in the P...

Different parts of the Lower Cretaceous Alam El Bueib (AEB) and the Jurassic Khatatba source and reservoir rock units in the Faghur basin, like in other basins in the north Western Desert, act as hydrocarbon sources and reservoirs. In the present study, well-log data from five wells in Phiops field and geochemical data from the Neith S-2X well from the neighbor Neith field together with reflection 2D seismic data of thirty (30) lines have been utilized to evaluate the Jurassic-Lower Cretaceous petroleum system in the Faghur basin and to give evidence for future hydrocarbon exploration and development in the study area. Source rock evaluation shows that several units from both Alam El Bueib and the Jurassic Khatatba shale source rocks represent good source rocks. Total organic carbon (TOC) values of the studied units of Alam El Bueib shale source rocks range from 0.27 to 6.39 wt.% that reflect fair to very good source rock, while Toc value for the Alam El Bueib-6 shale source rock is...

The shear wave sonic (S-wave) log data is essential for identifying the reservoir's geomechanical properties, which is an important factor for the drilling, completion, and optimization processes, where obtaining S-wave requires capital investment and reduces the cost. In this paper, we used the multi-layer perceptron (MLPR) and the gradient boosting regression (GBR) to predict the missing S-Wave log data for the Volve Oil Field in the North Sea. Prescriptive and predictive analysis were carried out in series to achieve a high blind data accuracy rate of 0.943 and 0.982 for the multi-layer perceptron regression and the gradient boosting regression, respectively. It was observed that the gradient-boosting algorithm achieved higher accuracy than the MLPR algorithm for the limited dataset. It was also found that hierarchical clustering can reveal information regarding the feature's importance similar to the relevant AI tools, which makes hierarchical clustering a faster tool in eliminating the nonimportant inputs from the dataset while the use of artificial intelligence tools showed a significant effect in predicting the missing values of the sonic wave log and the neutron porosity log in an efficient way by selecting the relevant important features.

The Asmari reservoir in southwest Iran has been producing oil continuously for over 50 years. However, due to an essential pressure decline, the reservoir is now a potential candidate for injection projects. The geomechanical analysis is essential for a successful injection operation to enhance reservoir production and address possible challenges. An accurate estimation of the injection pressure is necessary to maintain optimal conditions during the injection process and reduce possible risks. In this work, a coupled reservoir-geomechanical model, as well as rock mechanical tests, is performed to evaluate not only pressure variation and the associated in situ stress changes but also their potential influences on fault reactivation, reservoir–caprock stability, and surface displacement. For geomechanical evaluation, empirical correlations are derived between static and dynamic rock properties based on core data and existing petrophysical logs for the studied reservoir–caprock system....

Reservoir characterization of the upper part of Qamchuqa Formation at the wells of Miran West-2 (MW-2) and Bazian-1 (BN-1) is studied. This formation typically has low shale content at the BN-1 well. At the same time, in the MW-2 well, the middle part of the studied formation is dominated by shaly and shale intervals, possibly affected by the Sarmord and Balambo depositional environments. Although the upper part of Qamchuqa Formation is mainly composed of dolomite with minor dolomitic limestone, marl and shale are occasionally present. Furthermore, porosity values are commonly less than 15% in both wells; nevertheless, there are a few intervals where porosity significantly increases. The formation at the BN-1 well has a higher porosity than the MW-2 well. Moreover, the secondary porosity is relatively low as 4.0% at the MW-2 well, while in the well of BN-1, it ranges between < 4.0% and 7.5%. The measured permeability of the formation suggests good permeability. According to the shale volume, porosity, and permeability, the upper part of Qamchuqa Formation is subdivided into three reservoir units. RU 1 at the MW-2 well and RU 2 at the BN-1 well have the most substantial reservoir properties. However, the lowest reservoir quality appears within RU 1 of the BN-1 well and RU 2 at the well of MW-2. Additionally, residual hydrocarbons constitute an extensive fraction of the pore spaces, while tiny portions of the moveable one can be discovered along all reservoir units of the formation. Finally, considering the hydrocarbon movability of the MW-2 well, the upper part of Qamchuqa Formation is defined by primarily movable oils in RU 1 and 2. In contrast, moveable oils are detected in almost all of the reservoir units of the BN-1 well.

Roughly 7-10 geothermal wells are drilled in order to provide 1 well producing enough steam to drive a turbine. This well-drilling sunk cost is, however, far from unique to geothermal reservoirs. Rather it is endemic to crustal reservoirs of all fluid types: convention and non-conventional hydrocarbon, groundwater, fossil flow mineralisation, as well as geothermal. E.g., representative of the vast statistical data for onshore oil field well productivity, in the year 2009 the state of Texas had 60 wells producing an average of 645 barrels/day, 2984 wells producing an average of 88 barrels/day, and 80770 oil field wells producing an average of 1 barrel/day. As there is no intrinsic reason to consider geothermal fields significantly different from oil fields (except that the pay fluids are different), the multi-state multi-year US oil field well producer statistics are strong indicators of how rare it is to drill crustal reservoir 'producers': for purely blind drilling, for every geothermal producer, the intrinsic odds are for 50 non-producers (with an additional 1300 wells that would never be considered for drilling). At $100/barrel value of oil, oil field well sunk costs are manageable. At $1/barrel value of hot water, geothermal drilling sunk costs requires a fundamentally different well drilling strategy. Historically geothermal wells are drilled with reference to surface manifestations and geological interpretations of subsurface structure. Given what lognormal-distribution well productivity data tell us about the strong heterogeneity of reservoir flow systems, we can assert that we need greatly improved subsurface flow structure data to guide the drill bit to achieve more costeffective hydrothermal heat extraction. We can take the necessary step by looking below the reservoir surface via innovative use of standard multi-channel seismic sensor array technology as deployed over shale body reservoirs subjected to repeated massive hydrofracture treatments along horizontal wellbores. Unlike oil field flow systems, which are non-flowing until disturbed by reservoir operations, geothermal reservoir flow systems are naturally acoustically noisy, with the noise levels scaling in rough proportion to the volume of naturally occurring fluid flow. Surface sensor array data have demonstrated that acoustic noise generated by shale body fracking practice contain sufficient signal levels that specialised use of otherwise standard seismic processing technology can reliably locate a large range of reservoir subsurface flow structures, most importantly the large-scale reservoir flow patterns associated with large-scale but spatially elusive fracture channels endemic to crustal rock. While the dismal oil field well productivity statistics amply reflects the deficiency of drilling without valid information about subsurface flow targets, it is now possible to identify the fundamental physical reason behind poor well productivities, take technical steps to acquire necessary reservoir flow structure information, and actively upgrade drill site locations to guide the drill bit to the main flow structures in the reservoir fracture system.

From March to September 2016, SEG Advanced Modeling Corporation (SEAM) carried out a realistic, large-scale simulation of monitoring a deepwater turbidite reservoir by geophysical remote sensing. The project, called SEAM Time Lapse, was a joint effort of SEG and SPE, funded by the U.S. Department of Energy (DOE) through the Research Partnership to Secure Energy for America (RPSEA). Its goal was to assess if current numerical methods can simulate temporal changes in the geometry and physical properties of a complex reservoir with the detail and accuracy that are needed to explain and predict the subtle effects seen in time-lapse surveys of real oil fields. The reservoir modelling incorporated coupled effects of fluid flow and deformation during a simulated production scenario with 11 production wells and 6 water-injection wells penetrating the reservoir's three compartments. Field-scale seismic, gravity and electromagnetic surveys were simulated before and after 2 years of production. This six-month project was designed as a pilot for a new multi-year collaborative research effort called SEAM Life of Field which is starting in 2017.

Afield development plan (FDP)  of the Y and J oil fields for cretaceous reservoir (Harth Formation) evaluation and the production of hydrocarbons in the near future in two Y and J oil fields. Open hole logs namely (Gamma ray, Resistivity, Sonic, Caliper and Density) logs were used to determine petrophysical parameters. The parameters determined are; volume of shale, porosity, water saturation, irreducible water saturation and bulk volume of water. The thickness of the reservoir varies between (40 and 120) m. Determining the porosity depending on the porosity of the log (16-28)%  and core  Average porosity (18-37)% values vary between; generally decreasing with depth. Average porosity 33.3%.test is flow crude oil 1000 bll /d.in J field basically water saturation calculation5-16%. And oil saturation (90-80) % and the oil were carried out at a rate of 1000 barrels / day in the complete test of well Y. The amount of the original oil storage OOIP (1039 * 10^6) standard cubic meters. This...

Analyse d'incertitudes des performances d'un réservoir fracturé : étude de cas -Ces dernières années, l'industrie du pétrole a accordé une grande importance à la gestion et à l'analyse d'incertitudes des réservoirs. Le développement d'une méthode permettant de modéliser et de quantifier les incertitudes au cours des études de simulation de réservoir d'une façon efficace et pratique est clairement souhaitable. Des approches différentes telles que la méthodologie des surfaces de réponse (RSM ; Response Surface Methodology) et la simulation de Monte-Carlo ont été utilisées pour évaluer les incertitudes. Au sein de cet article, la méthode de surface de réponse est utilisée pour appréhender les paramètres les plus influents sur les changements en termes de chute de pression et de facteur de récupération, en ce qui concerne leurs niveaux pratiques d'incertitudes au cours du développement d'un modèle de réservoir fracturé. La présente approche est utilisée pour amplifier les paramètres significatifs et développer une équation substitutive compatible et plus réaliste en vue de la prévision de la récupération d'huile à partir d'un réservoir fracturé faiblement perméable typique. Le modèle substitutif permet à l'analyse de Monte-Carlo de déterminer les sensibilités et la quantification de l'incidence de l'incertitude sur les prévisions de production. Les résultats indiquent que la récupération d'huile est plus sensible à la pression de l'aquifère, à la perméabilité de fracture et à la hauteur de bloc. De plus, toutefois, l'interaction entre d'autres paramètres tels que la taille de matrice, la perméabilité de fracture et le volume d'aquifère a montré un certain degré d'importance au cours de cette analyse. L'analyse de Monte-Carlo prévoit un domaine de grande ampleur de récupération d'huile pour l'exploitation de ce champ.

On limited part of the Upper Miocene sandstone oil reservoir of the Ivanić Field, during 2001-2006, a pilot project of alternating water and CO2 injection was performed. During test period oil and gas recovery was significantly increased. Additionally 4,440 m3 of oil and 2.26 x 106 m3 of gas were produced. It has initiated further modelling of sandstone reservoirs in the Ivanić Field in order to calculate volumes availabe for CO2 injection for the purpose of increasing hydrocarbon production from depleated sandstone reservoirs in the entire Croatian part of the Pannonian Basin System (CPBS). In the first phase modelling was based on results of laboratory testing on the core samples. It considered applying analogies with world-known projects of CO2 subsurface storage and its usage to enhance hydrocarbon production. In the second phase, reservoir variables were analyzed by variograms and subsequently mapped in order to reach lithological heterogeneities and to determine reliable average values of reservoir volumes. Data on porosity, depth and reservoir thickness for the "Gamma 3" and the "Gamma 4" reservoirs, are mapped by the Ordinary Kriging technique. Calculated volume of CO2 expressed at standard condition which can be injected in the main reservoirs of the Ivanić Field at miscible conditions is above 15.5 billion m3.

Evaluation and prediction of emulsion flow behavior will play a pivotal role in reduction of flow assurance issue resulting from emulsion. Although emulsions formation cannot be completely stop but can be reduced and mitigated by optimization of water content. In this work, PROSPER a well modeling package was used to develop a wellbore model to investigate water cut increase on pressure gradient within the wellbore during heavy oil recovery. Gradient traverse estimation were implemented at a wellhead pressure of 500 psig and a liquid rate of 1500 STB/day. The model was run for with and without emulsion viscosity for no water cut (base case) and water cut of 25%, 50% and 75%. Results shows that as the water cut increases, the bottom hole flowing pressure(BHFP) and pressure gradient decreases for without emulsion viscosity and increases for with emulsion viscosity scenario.Base case of no water cut gave the same pressure gradient for with and without emulsion viscosity. The sensitivity scenario without emulsion had 3.5%, 6.2%, and 8% reduction in pressure gradient for 25%,50% and 75% water cut when compared with base case. Further analysis reveals that for with emulsion there was 3.4%, 11.2% and 14.6% increase in the pressure gradient for 25%,50% and 75% water cut when compared with base case .For higher water cut (25%, 50%, 75%), there was a separation between the two gradient. The pressure drop increases with emulsion viscosity increase. High water cut increases the difference between the two due to emulsion viscosity increase.

BED 2 field is one of the main producing assets for Bapetco company, Western Desert Egypt, BED 2 Field has hydrocarbon accumulations in Abo Roash, Lower Baharyia and, Upper Kharita formations. The field is a multireservoir started producing gas from Lower Baharyia and, Upper Kharita formations. The initial value of the field water saturation was calculated using Archie's method where, it reached 20%. After years of production, it was decided to monitor the reservoir and measure accurate water saturation using Thermal Decay Time (TDT) tools as the water cut increased significantly. The tool was run in X-3 well over Lower Baharyia and Upper Kharita formations. The hydrocarbon type is Gas-Condensate; the formation water salinity is well determined leading to decreasing saturation calculation uncertainty. Gas Water Contact (GWC) moved up by 9 meters and water saturation increased in Lower Baharyia and Top Kharita formations. The results revealed that the water production intervals must be isolated, resulting in decreasing of water cut and gas production increasing.

BED 2 field is one of the main producing assets for Bapetco company, Western Desert Egypt, BED 2 Field has hydrocarbon accumulations in Abo Roash, Lower Baharyia and, Upper Kharita formations. The field is a multireservoir started producing gas from Lower Baharyia and, Upper Kharita formations. The initial value of the field water saturation was calculated using Archie's method where, it reached 20%. After years of production, it was decided to monitor the reservoir and measure accurate water saturation using Thermal Decay Time (TDT) tools as the water cut increased significantly. The tool was run in X-3 well over Lower Baharyia and Upper Kharita formations. The hydrocarbon type is Gas-Condensate; the formation water salinity is well determined leading to decreasing saturation calculation uncertainty. Gas Water Contact (GWC) moved up by 9 meters and water saturation increased in Lower Baharyia and Top Kharita formations. The results revealed that the water production intervals must be isolated, resulting in decreasing of water cut and gas production increasing.

Abstract
This study aims to evaluate reservoir characteristics of Hartha Formation in
Majnoon oil field based on well logs data for three wells (Mj-1, Mj-3 and Mj-11).
Log interpretation was carried out by using a full set of logs to calculate main
petrophysical properties such as effective porosity and water saturation, as well as to
find the volume of shale. The evaluation of the formation included computer
processes interpretation (CPI) using Interactive Petrophysics (IP) software. Based
on the results of CPI, Hartha Formation is divided into five reservoir units (A1, A2,
A3, B1, B2), deposited in a ramp setting. Facies associations is added to well logs
interpretation of Hartha Formation, and was inferred by a microfacies analysis of
thin sections from core and cutting samples. The CPI shows that the A2 is the main
oil- bearing unit, which is characterized by good reservoir properties, as indicated by
high effective porosity, low water saturation, and low shale volume. Less important
units include A1 and A3, because they have low petrophysical properties compared
to the unit A2.

Polymer-enhanced-oil-recovery (EOR) operation has been implemented for the production of oil from difficult mature oil fields in Oman. The polymer used to sweep oil toward production wells in this EOR technique is resulting in the generation of polymer-flood produced water (PFPW) of increasing viscosity. Current methods of treating oilfield produced water must be reconsidered for the effective treatment of PFPW of such changing quality. In a previous study, the use of polyaluminum chloride (PAC) was proposed for the coagulation of oil in produced water to be separated by flotation and filtration. As such, laboratory tests were conducted to evaluate the applicability of PAC and other chemicals for treatment of PFPW with higher viscosity than ordinary oilfield-produced water. These tests indicated clearly that aluminum sulfate (AS) was more effective for treatment of such higher-viscosity water. A pilot plant developed during the earlier study was used to conduct coagulation/flocculat...

The cross plotting of rock properties for fluid and lithology discrimination was carried out in a Niger Delta oil field using well data X-26 from a given oil field in the coastal swamp depobelt. The data used for the analysis consisted of suites of logs, including gamma ray, resistivity, sonic and density logs only. The reservoir of interest Horizon 1, was identified using the available suite of logs on the interval where we have low gamma ray, high resistivity and low acoustic impedance specifically at depths 10,424ft (3177.24m) to 10 724ft (3268m). We first obtained other rock attributes from the available logs before cross plotting. The inverse of the interval transit times of the sonic logs were used to generate the compressional velocities and the S-wave data was generated from Castagna´s relation. Employing rock physics algorithm on Hampson Russell software (HRS), rock attributes including Vp/Vs ratio, Lambda-Rho and Mu-Rho were also extracted from the well data. Cross plottin...

A new framework is presented that uses production data history in order to build a field-wide performance prediction model. In this work artificial intelligence techniques and data driven modeling are utilized to perform a future production prediction for both synthetic and real field cases. Production history is paired with geological information from the field to build large dataset containing the spatio-temporal dependencies amongst different wells. These spatio-temporal dependencies are addressed by information from Closest Offset Wells (COWs). This information includes geological characteristics (Spatial) and dynamic production data (Temporal) of all COWs. Upon creation of the dataset, this framework calls for development of a series of single layer neural network, trained by back propagation algorithm. These networks are then fused together to form the "Intelligent Time-Successive Production Modeling"(ITSPM). Using only well log information along with production history of existing wells, this technique can provide performance predictions for new wells and initial hydrocarbon in place (IHIP) using a "volumetric-geostatical" method. A synthetic oil reservoir is built and simulated using a commercial reservoir numerical simulation package. Production and well log data are extracted and converted to an allinclusive dataset. Following the dataset generation several neural networks are trained and verified to predict different stages of production. ITSPM method is utilized to estimate the production profile for nine new wells in the reservoir. ITSPM is also applied to data from a real field. The field that is giant oil field in the Middle East includes more than 200 wells with forty years of production history. ITSPM's production predictions of the four newest wells in this reservoir are compared to real production data. First and foremost I wish to offer my sincerest gratitude to my supervisor, Dr Shahab Mohaghegh who has supported me throughout my thesis with his patience and knowledge whilst allowing me the room to work in my own way. I attribute the level of my Masters degree to his encouragement and effort and without him this thesis, too, would not have been completed or written. One simply could not wish for a better or friendlier supervisor. I wish to thank my friends in MRB-135 whom I shared every moment of this work with. Without having the warmth and joyfulness we share in this office I would not be able to carry on with the hard work and finish this thesis. I also wish to thank all my friends; ones who have been beside me and ones who are distant, without their support studying all long days and nights far away from home would not be ever possible. My gratitude also goes to Dr. Khashayar Aminian, Dr. Razi Gaskari, and Dr Grant Bromhal who kindly accepted to be a member of my thesis committee and all made significant contribution to this work through their generous comments. Also, I would like to express my gratitude to Computer Modeling Group, for making the CMG reservoir simulator available to us to perform the reservoir simulations in this work. And most importantly, I wish to thank my parents, although being oceans apart their fond love has certainly made this path much easier. They bore me, raised me, supported me, taught me, and loved me. To them I dedicate this thesis.

Tut Oil Field is located in the northwestern part of the Western Desert, Egypt. This work aims to study the subsurface and reservoir characteristics to evaluate the hydrocarbon potential of Bahariya Formation based on subsurface data available from open-hole well log records of nine wells distributed in the area of study. The subsurface geologic setting, in terms of determining the stratigraphic and structural settings, is gained through the construction of different aligned stratigraphic and structural cross sections, isopach and lithofacies maps. The petrophysical evaluation, in terms of determining the petrophysical characteristics; net pay thickness, effective porosity (∅ eff ), shale content (V sh ), water saturation (S w ) and hydrocarbon saturation ( S h ), is acquired through quantitative computer processed interpretation. The petrophysical characteristics are illustrated laterally in the form of iso-parametric maps and vertically in the form of litho-saturation cross-plots. According to subsurface study and petrophysical evaluation the most productive area is located in central and southern parts of Tut field.

In the Nahotokha oil spill, which occurred in the Japan Sea in the winter of 1997 , recovery operations using buckets hauled up by crane barges and grab dredgers showed good results . It was thought that this method would be more useful than other oil recovery methods for the recovery of high viscosity oil because crane barges and grab dredgers can operate even in rough sea , and crane buckets have proven to be effective for the recovery of oil of high viscosity . However, one drawback of this method is that a huge volume of water is collected together with the oil . A large storage pit and an efficient method for treating the polluted water are therefore needed . Thus, for effective utilization of the bucket recovery method, a method for separating oil and water and increasing the oil/water ratio is needed . were conducted in the present study to find an effective method for separating oil from seawater recovered using buckets in a low-temperature such as the Okhotsk Sea in winter .

In the Nahotokha oil spill, which occurred in the Japan Sea in the winter of 1997 , recovery operations using buckets hauled up by crane barges and grab dredgers showed good results . It was thought that this method would be more useful than other oil recovery methods for the recovery of high viscosity oil because crane barges and grab dredgers can operate even in rough sea , and crane buckets have proven to be effective for the recovery of oil of high viscosity . However, one drawback of this method is that a huge volume of water is collected together with the oil . A large storage pit and an efficient method for treating the polluted water are therefore needed . Thus, for effective utilization of the bucket recovery method, a method for separating oil and water and increasing the oil/water ratio is needed . were conducted in the present study to find an effective method for separating oil from seawater recovered using buckets in a low-temperature such as the Okhotsk Sea in winter .

Steam injection and thermal recovery of oil from the reservoir are increasing day by day. However, the recovery of the heat remained stored in the steam-flooded oil reservoir is nor in practice neither researched previously. A novel concept of steam injection and energy recovery from a light oil reservoir is presented in this paper. Reservoir numerical model of an actual oil field was generated and simulated with steam injection. Different parameters of thermal properties of geologic formations were discussed and adopted as per actual geology of the study area for more realistic simulation of heat storage, dissipation, and losses. After the optimum oil recovery, water was circulated through the same injection well into the reservoir to extract the energy in the form of heat, stored during the steam injection phase. The effects of different completion schemes of injection well were also simulated, discussed and pointed out for optimum oil recovery. Oil recovery factor is the most important parameter from both research and field development point of views. The comparative analysis was also carried out with the oil production without steam injection and found that steam flooding increased oil recovery factor up to more than 15% by decreasing the production time period up to 40% as compared to without steam injection oil production. The transmission of heat through conduction and convection mechanisms in the porous media, and through advective, dispersive and diffusive processes in the fluid was modeled. To fully investigate the feasibility of the concept presented in this paper, the production wellbore modeling was also carried out and temperature profile of recovered heat energy at the wellhead was obtained by acknowledging the thermal losses and found to be very useful for any direct and indirect utilization of heat throughout the energy recovery period of the reservoir.

Steam injection and thermal recovery of oil from the reservoir are increasing day by day. However, the recovery of the heat remained stored in the steam-flooded oil reservoir is nor in practice neither researched previously. A novel concept of steam injection and energy recovery from a light oil reservoir is presented in this paper. Reservoir numerical model of an actual oil field was generated and simulated with steam injection. Different parameters of thermal properties of geologic formations were discussed and adopted as per actual geology of the study area for more realistic simulation of heat storage, dissipation, and losses. After the optimum oil recovery, water was circulated through the same injection well into the reservoir to extract the energy in the form of heat, stored during the steam injection phase. The effects of different completion schemes of injection well were also simulated, discussed and pointed out for optimum oil recovery. Oil recovery factor is the most important parameter from both research and field development point of views. The comparative analysis was also carried out with the oil production without steam injection and found that steam flooding increased oil recovery factor up to more than 15% by decreasing the production time period up to 40% as compared to without steam injection oil production. The transmission of heat through conduction and convection mechanisms in the porous media, and through advective, dispersive and diffusive processes in the fluid was modeled. To fully investigate the feasibility of the concept presented in this paper, the production wellbore modeling was also carried out and temperature profile of recovered heat energy at the wellhead was obtained by acknowledging the thermal losses and found to be very useful for any direct and indirect utilization of heat throughout the energy recovery period of the reservoir.

Many years have passed in oil field development but primary challenges faced by the X reservoir are the rapid decline of formation pressure and the significant solution gas released from the formation, which impairs production. Based on these challenges, a compositional simulation model of the X reservoir was constructed and run to establish the future development plans. The basic reservoir data collection and processing, quality assurance of the data, characteristic pressure-volume-temperature (PVT) matching by ECLIPSE PVTi, and simulation of various adjustment strategies to forecast development plans, as well as data sensitivity analysis and optimization has been included in this study. In addition, to establish a desirable development plan, the simulation model is set up in great consistency with the geological model resulted from the seismic and logging interpretations. Also, emphases are paid on establishing matches with the reported lab data from production wells by PVTi. Resu...

The current study summarized the construction of a three-dimensional geological model of the Aquitanian sediments age, which represented by the Euphrates and Serikagni formation in Ajeel Oil Field, where Ajeel Oil Field has structural closure towards northwest -southeast. Sedimentary of the current study consist of limestone, dolomitic limestone, dolomite (compose of skeletal grains, non-skeletal grains and cement) and the appearance of some anhydrite rocks. The petrographic study of the Euphrates Formation were prepared using a thin section of wells (Aj-1, Aj-4, Aj-5, Aj-6 and Aj-7), Previous studies and geological reports, as well as use well logs data in the statistical analysis by Petrel software using the Neural Network and Train Estimation Model, for divide sedimentary environments of Euphrates Formation. The petrographic analysis showed mudstone, wackstone, packstone and grainstone facies. The sedimentary environment was then determined and the sedimentary model of the current study rocks in the Ajeel field which compared with Wilson scheme where represented by zones (FZ-6, FZ-8, FZ-7) extend through lagoon environment, back shelf and open shelf, through the sedimentary model was determined the type of Euphrates Formation platform(Rimmed Platform).

Mishrif Formation regards one of the most important reservoirs in Iraq.Well logging represents one of the most important tool in the formation evaluation. According to the Petrophysical properties that have been gotten from well logging, Mishrif Formation in terms of reservoirs units, consist of several reservoirs units..Major reservoirs units divided into three reservoir units,MA,MB&MC. Each of these major units divided into minor reservoirs units (MB11,MB12,MC2&MC3).MB major reservoir units represent the best reservoir unit.These reservoirs units separated by cap rocks(mainly tight limestone)(CR1,CR2,CR3,CR4,CR5,CR6,and CR7).CPI were demonstrated for all wells.Hydrocarbon saturation vs. water saturation have been determined for each units.In addition, the types porosity and moveable vs.residual oil were calculated.

Hydrocarbons serve the prime energy source of the world and the backbone to industrial development. Hydrocarbon potential is explored here using the spatial multi-criteria decision-making method. In order to demarcate the hydrocarbon potential zones within Masila oil field, Yemen, various thematic layers of multi-criteria factors affecting the hydrocarbons such as basement depth map (BDM), gravity anomaly map (GAM), magnetic anomaly map (MAM), subsurface faults system map (SFSM), upper syn-rift isopach map (USRIM), post-rift isopach map (PRIM), and lower syn-rift isopach map (LSRIM) were generated using the information extracted from both the geophysical and wells data available for the oil field. Geographical information system (GIS) techniques were used to generate various thematic maps that were subsequently converted to raster format and reclassified into various classes on the basis of their relative importance and the opinion of relevant experts. These thematic maps and their feature classes were assigned weights (eigenvalues) and rank by using the analytic hierarchy process (AHP) and following the theories of multi-criteria analysis (MCA). Furthermore, these maps were superimposed using the weighted linear combination (WLC) model on the GIS platform. The results of the integration of the thematic maps were classified into three classes representing the three hydrocarbon potential zones, namely, high potential zone (39.8%), moderate potential zone (49.1%), and low potential zone (11.1%). The cross plots of occurrence of the hydrocarbon reservoir, existing oil fields, and well locations were inferred for validation. The validation results revealed a good prospect for hydrocarbon potential in the study area. The novel quantitative approach used in the present study is capable of providing comprehensive results and assessment of hydrocarbons in the Masila oil field and other areas as well.

Hydrocarbon is a powerful contributor to development. The present study makes an attempt to use remote sensing data coupled with geophysical and geological data that has been integrated into Arc GIS to delineate favorable zones for hydrocarbon potential in the Masila oil field. Lineaments have been extracted using satellite data and geological data by their surface spectral signatures, whereas the subsurface lineaments have been inferred using geophysical data. Digital image processing of satellite image using ERDAS IMAGINE-14 have been carried out, sequentially using various techniques (Sobal, Laplacian filters and band composite), lineament digitized as layers, layers were converted to raster (grid) format, classified, analyzed, integrated and visualized using Arc GIS. The resulting lineaments obtained from each data, suggests that most of the lineaments are trended in NW-SE which coincides and are in conformity with the existing trend of the study area. The output potential map was classified into five zones of hydrocarbon potentiality, namely very high, high, moderate, low and very low potential zones. The hydrocarbon evaluation results of the present study reveal that 6.9% of the total area falls under very high potential, 14.2% highly potential, 21.3% moderately potential, 25.7% low potential and 31.9% falls under very low potential zones. The zones were verified with oil fields and existing wells in the area which shows a positive correlation. Such studies are significant for hydrocarbon potential resource planning and management. Further, the methodology used for this study can be, replicated in another similar geological setup elsewhere for mapping hydrocarbon potential zones.