Southern Iraqi Oil Fields Research Articles

Construction of Mechanical Earth Modeling for Mitigating Wellbore Instability in Tanuma Shaly Formation -Southern Iraqi Oil Field

Wellbore instability has become an increasing concern for horizontal and extended-reach wells, especially through shale cap rocks. This paper presents a comprehensive analysis of the factors that led to the wellbore being unstable in the Tanuma Formation, the Nasiriyah oilfield in southern Iraq. By constructing a mechanical earth model using open-hole wireline data from two drilled wells. Mohr-Coulomb, Mogi-Coulomb, and Modified Lade failure criteria are used to analyze the breakouts and determine the density of mud that is required for a safe wellbore wall. The results indicated that the Mogi-Coulomb criterion is more similar to the actual well failure than the other two criteria. The wellbore instability findings showed that the most stable wells are those that are vertical and have a low deviated angle (less than 10°), and it is advised that these wells be drilled with a mud weight of 11.3 to 14 ppg. The acceptable range for the weight of the mud for horizontal and greatly deviated wells is between 11.9 and 13.8 ppg. Consequently, the future wells development plan for the studied region is improved and leads to cost reductions.

Assessing Cutoff Values and Evaluating Petrophysical Properties of a Shaly-Sand Reservoir with Heterogeneous Properties in a Southern Iraqi Oil Field

Assessing Cutoff Values and Evaluating Petrophysical Properties of a Shaly-Sand Reservoir with Heterogeneous Properties in a Southern Iraqi Oil Field

Investigating the Bubble Point Pressure Discrepancy by History Matching for Mishrif Reservoir, Southern Iraqi Oil Field

Carbonate reservoirs have been a primary focus for academics and oil and gas companies for many years. However, the complex nature of these rocks has always posed challenges. This is particularly true in the study area, which is located in the unstable Mesopotamian Basin, where multiple oil fields produce hydrocarbons from NW-SE-trending anticlines along the Zagros Fold-Thrust Belt. The primary goal of reservoir simulation is to forecast reservoir performance and apply different techniques to improve hydrocarbon recovery under different conditions. The study area faces a problem of discrepancy in the bubble pressure at the same reservoir unit, which is attributed to the faults in the Mishrif reservoir. A study was conducted to investigate the causes of this phenomenon. The proposed method for verification involves simulating history matching using the Petrel platform after building two geological models on the probability of the fault and the reef; as a result of seismic survey interpretation. Field data for gas production of the reservoir and Pressure-Volume-Temperature analyses, especially the wells (well pad F), were used to determine the causes of the discrepancy. The current study found that the calculated and observed data match more consistently in the case of the fault rather than in the case of the reef, indicating the presence of fault in the area near the well pad F. This caused compartmentalization, leading to the discrepancy in the bubble pressure. This study could significantly improve regional exploration, especially in Iraq.

Technology Focus: Drilling Automation and Innovation (February 2024)

In recent years, operators and service companies have optimized drilling activities and reduced operational costs by accelerating the deployment of digital solutions. Among other applications, predictive data analytics are commonly used to estimate rock properties, reduce operational uncertainty, improve equipment maintenance processes, and optimize scarce human resources on specific tasks. Not surprising, then, is the number of initiatives to maximize the value of data and new machine-learning models to understand complex operations and the different levels of drilling automation around the world. The selection of technical papers for this month highlights some interesting examples implemented in diverse geographies. Sustainability appears today as a key driver for innovation. The complex process of decarbonization of our industry can be accelerated with the potential larger-scale application of emerging solutions with proven tangible impact. For instance, rig and equipment automation are a reality, with the capacity to lower emissions in drilling operations and help obtain improved and more-consistent results. Papers SPE 216249 and IPTC 22975 illustrate examples of actual benefits in different projects. The task of collecting, processing, organizing, and making sense of drilling information from multiple sources with minimum time requirements remains an opportunity for improved decision-making in project management. Paper OTC 32978 describes one case with the use of artificial intelligence for automatic classification of daily drilling reports as an enabler for better planning and accurate risk analysis. Worth emphasizing is the importance of extended reality as a growing and promising alternative with untapped potential in well construction, mainly as a resource for active learning and a collaboration tool among multidisciplinary teams. Paper SPE 212532, included in the additional recommended reading, gives an interesting overview of current applications associated with drilling operations and challenges ahead. Recommended additional reading at OnePetro: www.onepetro.org. SPE 217113 Machine-Learning Techniques for Real-Time Prediction of Essential Rock Properties While Drilling by K.W. Amadi, Australian University, et al. SPE 212532 Extended Reality and Gamification for Drilling by Crispin Chatar, SLB, et al. SPE 213043 Ensemble Machine Learning for Data-Driven Predictive Analytics of Drilling Rate of Penetration Modeling: A Case Study in a Southern Iraqi Oil Field by Dhuha T. Al-Sahlanee, BP, et al.

Permeability Estimation for Upper Shale Member in Southern Iraqi Oil Field Using Machine learning and Hydraulic Flow Units Methods

Permeability estimation in the Upper Shale Member is rather complex due to the heterogeneity. Conventional logs do not provide permeability directly, but the core data does. Core operations and analysis processing are all costly. An alternative method is used by dividing the reservoir rock into groups (rock types) with similar characteristics in porosity and permeability for cored wells. These identified groups for the core wells can be applied to the uncored wells to predict their groups and permeabilities. Four wells were used in this study: one cored well and three uncored wells. Two classification methods of rock types were used; the first is the machine learning method (supervised and unsupervised), a new technics invention, and the second method is the hydraulic flow unit. Four groups were selected by using Machine Learning and hydraulic flow unit methods. A regression equation for each rock type was obtained to predict permeability. Then, establishing a relationship between the results of the core data groups and the logs' responses for the core well is referred to as "correlation," which is training the logs that provide an estimating model. A validation check was completed by comparing the rock type and permeability estimation from the core with the rock type and permeability estimation from the logs, which were highly matched. Finally, The rock type and permeability can be estimated for the uncored wells using only the logs that were learned from the generated training data set for the cored wells. Due to the use of more than one model to predict permeability, it was clear that one was more compatible than the other. The flow zone indicator, a classical method, still has a better rock type and permeability estimation than the new techniques, which use data mining and mathematical algorithms on a clustering basis.

Evaluation of the Mishrif Formation Using an Advanced Method of Interpretation

The Mishrif Formation is one of the most important geological formations in Iraq consisting of limestone, marl, and shale layers since it is one of the main oil producing reservoirs in the country, which contain a significant portion of Iraq's oil reserves. The formation has been extensively explored and developed by the Iraqi government and international oil companies, with many oil fields being developed within it. The accurate evaluation of the Mishrif formation is key to the successful exploitation of this field. However, its geological complexity poses significant challenges for oil production, requiring advanced techniques to accurately evaluate its petrophysical properties. This study used advanced well-logging analysis techniques, including mineralogical inversion with the Quanti-Elan model employed in Schlumberger's Techlog software to evaluate this formation. The lithology, clay volume, porosity, permeability, and hydrocarbon saturation data were obtained from the open hole logging of three wells in a southern Iraqi oil field. The environmental correction was applied for open-hole logging tools, and the primary mineral of the formation was determined using porosity log cross-plotting. Pickett plot technique was utilized to determine water resistivity and Archie's parameters, and the reconstruction log was generated based on volumetric and response parameters for each component. Based on thorough analysis, the clay volume of the Mishrif formation is estimated to be about 10%, which is a common value for this rock type. The porosity was computed based on the total fluid volume, ranging from 11% to 14%, and water saturation was determined using Archie's equation. The final results of the volume of each component for rock and fluid are presented using computer programming interpretation. The results of this study provide valuable insights into the petrophysical properties of the Mishrif formation and are expected to inform for better interpretation and evaluation of petrophysical properties of similar formations, which is essential for optimum field development planning as well as minimising the uncertainties.

New Correlation for Predicting Undersaturated Oil Compressibility for Mishrif Reservoir in the Southern Iraqi Oil Fields

Reservoir fluids properties are very important in reservoir engineering computations such as material balance calculations, well testing analyses, reserve estimates, and numerical reservoir simulations. Isothermal oil compressibility is required in fluid flow problems, extension of fluid properties from values at the bubble point pressure to higher pressures of interest and in material balance calculations (Ramey, Spivey, and McCain). Isothermal oil compressibility is a measure of the fractional change in volume as pressure is changed at constant temperature (McCain). The most accurate method for determining the Isothermal oil compressibility is a laboratory PVT analysis; however, the evaluation of exploratory wells often require an estimate of the fluid behavior prior to obtaining a representative reservoir sample. Also, experimental data is often unavailable.Empirical correlations are often used for these purposes.This paper developed a new mathematical model for calculating undersaturated oil compressibility using 129 experimentally obtained data points from the PVT analyses of 52 bottom hole fluid samples from Mishrif reservoirs in the southern Iraqi oil fields. The new undersaturated oil compressibility correlation developed using Statistical Analysis System (SAS) by applying nonlinear multiple regression method. It was found that the new correlation estimates undersaturated oil compressibility of Mishrif reservoir crudes in the southern Iraqi oil fields much better than the published ones. The average absolute relative error for the developed correlation is 7.16%.

Estimation Pore and Fracture Pressure Based on Log Data; Case Study: Mishrif Formation/Buzurgan Oilfield at Iraq

Prediction of the formation of pore and fracture pressure before constructing a drilling wells program are a crucial since it helps to prevent several drilling operations issues including lost circulation, kick, pipe sticking, blowout, and other issues. IP (Interactive Petrophysics) software is used to calculate and measure pore and fracture pressure. Eaton method, Matthews and Kelly, Modified Eaton, and Barker and Wood equations are used to calculate fracture pressure, whereas only Eaton method is used to measure pore pressure. These approaches are based on log data obtained from six wells, three from the north dome; BUCN-52, BUCN-51, BUCN-43 and the other from the south dome; BUCS-49, BUCS-48, BUCS-47. Along with the overburden pressure gradient and clay volume, which were also established first, data such as gamma ray, density, resistivity, and sonic log data are also required. A key consideration in the design of certain wells is the forecasting of fracture pressure for wells drilled in the southern Iraqi oilfield of Buzurgan. The pressure abnormality is found in MA, MB21, MC1 and MC2 units by depending on pore pressures calculated from resistivity log. In these units, depths and its equivalent normal and abnormal pressure are detected for all sex selected wells; BUCS-47, BUCS-48, BUCS-49, BUCN-43, BUCN-51 and BBCN-52. For MA, MB21, MC1, and MC2 units, the highest difference in pore pressure values are 1698 psi @ 3750 m (BUCN-51), 3420 psi @ 3900 m (BUCN-51), 788 psi @ 3980 m (BUCS-49), and 5705 psi @ 4020 m (BUCN-52). On other hands, MB11 and MB12 units have normal pressure trend in all studied wells. Finally, the results show that the highest pore and fracture pressure values is existed in North dome, in comparison with that obtained in south dome of Mishrif reservoir at Buzurgan oilfield.

Using Smart Completion Technology to Control Water Coning Problems and Increase Oil Recovery in a Southern Iraqi Oilfield

This research describes the using of a new well completion technology system that enhance the homogeneous and heterogeneous reservoir deliverability and the production performance gained through a completion technique using Autonomous Inflow Control Valve (AICD) by self-decreasing/delaying water and gas progress and promoting increasing in oil production, therefore, equalizing the drawdown (∆P=Pi-Pwf) along the well and provide a dynamic water shut-off operation and significantly increasing the economic life of a well and therefore, reducing capital and operational expenditures for the field development.
 The research presents a production performance simulation results for a conventional and smart well completion technology in a horizontal well in a southern Iraqi oilfield for two stages during well life; early stage (till 2018) and late stage (till 2033). For early stage of well life, there was no significant difference in results when comparing between the conventional completion design and the smart completion design. In the contrast, the simulation results for the late life of the well showed that the well can produce for approximately 1056.7 barrel per day crude oil with a water-cut of 82 % at the year of 2033. The also revealed that the results showed that the cumulative oil production from the year of 2018 till 2050 will be 23 million barrel of crude oil and 44 million barrel of water when the well is completed with conventional completion design. When the completion design has been changed and equipped with autonomous inflow control devices (AICDs) technology and simulated the production performance by NETool Software. The simulation results showed that the oil production has been increased by 891 barrel per day (1947.3 barrel per day) and the water cut has reduced significantly in comparison with the conventional production completion by 17 % (65.4 %) at the year of 2033. The results revealed that the cumulative oil production from the year of 2018 till 2050 will be 31 million barrel of crude oil and 33 million barrel of water.
 It has been concluded, from the reservoir and production simulation, that the application of the technology is successful and showed a clear advantage of using Autonomous Inflow Control Device (AICD) that provides better water influx control profile.

Perforation location optimization through 1-D mechanical earth model for high-pressure deep formations

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

Using of surface back pressure with water based mud in managed pressure drilling technique to solve lost circulation problem in Southern Iraqi Oil Fields

Many drilling problems are encountered continuously while drilling oil wells in the southern Iraqi oil fields. Many of these problems are ineffectively handled resulting in a longer non-productive time. This study aims to identify the formations such as Dammam, and Hartha formations،diagnose potential problems and provide the solution for lost circulation problem. After conducting a comprehensive study on the subject and based on available data, previous studies and some information, the managed pressure drilling (MPD) method was the best technique to solve this problem. This process may use various techniques including control of back pressures .Thus, reducing the risk and control the costs of drilled wells, which have narrow pressure window by managing the wellbore pressure profile. The well plan software program provided by Halliburton Company was used, this software is based on a database and data structure common to many of Landmark’s drilling applications. Mud used with various injection rates to choose the rate that provides the conditions to achieve the best drilling process, as it using mud weights of (8.8 -8.7 ) ppg and applied a surface back pressure (50 psi). Depending on specifications of second hole the optimal injection rate was chosen using the (hydraulics) program. As a results, rate of water injection (850) gpm, is the best which it provides a good efficient cutting transport ratio (CTR), which means high stability and preventing formation damage in addition to controlling in mud losses

Effect of Pressure and Temperature Change on Undersaturated Oil Viscosity

A study has been done based on data received from one of the southern Iraqi's oil fields, consists of eighty eight experimental points of oil viscosity at known pressure and temperature above the bubble point pressure.
 Fourteen formulas assumed to define the effect of pressure and temperature change on undersaturated oil viscosity. Every formula gives a value of viscosity at any temperature and pressure (above bubble point) depending on a known value of
 viscosity at known pressure and temperature. Depending on the least squares method, the constants of these formulas are calculated.
 A formula appeared to have the minimum average absolute error (4.8 %) with a value of correlation coefficient equal to (0.8996) is selected to be the best formula adopted in this study. The most proper formula has been compared with two correlations (Khan's correlation and Vasquez and Beggs correlation) and it appeared to be better than the both correlations.

Stress Ratio Method to Predict Fracture Pressure Gradient in Southern Iraqi Deep Wells

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

An approach for applying managed pressure drilling techniques to troublesome formations in an oil well in southern Iraq

Many southern Iraqi oil field formations, such as Dammam and Hartha, are characterised as loose formations, making overbalanced drilling difficult due to increased frequency and volume of mud losses. Managed pressure drilling techniques (MPD) may thus be applied. This process uses conventional hydrostatic column pressure and annular friction pressure in addition to the surface back pressure to generate a constant bottomhole pressure (CBHP) to drill such formations, which enables the use of the lowest mud weight (closest to pore pressure) and back pressure treatment utilising a choke manifold during the drilling process to maintain an equivalent circulating density (ECD) slightly greater than the pore pressure, reducing the risk of mud loss, and the concomitant stuck pipes and non-productive time (NPT), thus enhancing drilling efficiency. In this paper, Wellflo software was utilized to model multi-phase flow in wells to examine the use of aerated mud used at different injection rates for gas and liquid to identify the best injection rate for drilling operations without losses. Several cases were examined using various mud weights and surface back pressure of the assumed injection rates, to choose the appropriate mud weight and the surface back pressure ranges. The highest pore pressure gradient expected in such holes is 0.465 psi/ft, and consequently, the minimum required mud weight was 8.95 ppg, in order to ensure control and avoid loss; however, due to back pressure and friction pressure in the annular region, this weight leads to problems in some formations. A mud weight of 8.8 ppg was therefore chosen as the closest feasible weight to pore pressure, with back pressures of 200 and 250 psi. A gas injection rate of 1,200 gpm was selected as the best injection rate for various liquid rates (581, 631, 681,731, and 781 gpm). The use of aerated mud at 8.8 ppg mud weight increased the penetration rate, offering a more efficient cutting transportation ratio (CTR) and allowing more control over wellbore instability and formation damage, as well as limiting mud losses.

Correlation of Minimum Miscibility Pressure for Hydrocarbon Gas Injection In Southern Iraqi Oil Fields

One of the most important enhanced oil recoveries methods is miscible displacement. During this method preferably access to the conditions of miscibility to improve the extraction process and the most important factor in these conditions is miscibility pressure. This study focused on establishing a suitable correlation to calculate the minimum miscibility pressure (MMP) required for injecting hydrocarbon gases into southern Iraq oil reservoir. MMPs were estimated for thirty oil samples from southern Iraqi oil fields by using modified Peng and Robinson equation of state. The obtained PVT reports properties were used for tunning the equation of state parameters by making a match between the equation of state results with experimental PVT data. The values ​​of the MMPs inputs into the statistical program to find a correlation for the value of miscibility pressure with the properties and composition of the reservoir oil and injected gas. Using a nonlinear formula, a good correlation was obtained. When comparing the present correlation with the many measured data, a superbly result of present correlation was obtained

Correlation of Minimum Miscibility Pressure for Hydrocarbon Gas Injection In Southern Iraqi Oil Fields

One of the most important enhanced oil recoveries methods is miscible displacement. During this method preferably access to the conditions of miscibility to improve the extraction process and the most important factor in these conditions is miscibility pressure. This study focused on establishing a suitable correlation to calculate the minimum miscibility pressure (MMP) required for injecting hydrocarbon gases into southern Iraq oil reservoir. MMPs were estimated for thirty oil samples from southern Iraqi oil fields by using modified Peng and Robinson equation of state. The obtained PVT reports properties were used for tunning the equation of state parameters by making a match between the equation of state results with experimental PVT data. The values ​​of the MMPs inputs into the statistical program to find a correlation for the value of miscibility pressure with the properties and composition of the reservoir oil and injected gas. Using a nonlinear formula, a good correlation was obtained. When comparing the present correlation with the many measured data, a superbly result of present correlation was obtained

Proxy modelling for rapid optimisation of miscible CO<SUB align="right">2-WAG injection in heterogeneous clastic reservoirs: a case study from Southern Iraqi oil fields

Multiple simulation runs are required to optimise and quantify uncertainty and sensitivity analysis to determine and rank the impact of reservoir and operating parameters on the incremental oil recovery (ΔRF) under miscible CO2-WAG flooding. The central composite design (CCD) was employed to create a statistical proxy model for ΔRF as a function of seven reservoir and operating parameters. Statistical analysis was employed to check the model adequacy. The importance and effect of variables that result to higher predicted ΔRF were investigated. As an analogue of the Nahr Umr reservoir, the reservoir understudy, the proxy model can be roughly applied to predict the ΔRF during the miscible CO2-WAG injection at depending on uncertainty. The reliability of the proxy model has been demonstrated based on many statistical tools. [Received: 29 July 2019; Accepted: 24 November 2019]

Proxy modelling for rapid optimisation of miscible CO<SUB align="right">2-WAG injection in heterogeneous clastic reservoirs: a case study from Southern Iraqi oil fields

Multiple simulation runs are required to optimise and quantify uncertainty and sensitivity analysis to determine and rank the impact of reservoir and operating parameters on the incremental oil recovery (ΔRF) under miscible CO2-WAG flooding. The central composite design (CCD) was employed to create a statistical proxy model for ΔRF as a function of seven reservoir and operating parameters. Statistical analysis was employed to check the model adequacy. The importance and effect of variables that result to higher predicted ΔRF were investigated. As an analogue of the Nahr Umr reservoir, the reservoir understudy, the proxy model can be roughly applied to predict the ΔRF during the miscible CO2-WAG injection at depending on uncertainty. The reliability of the proxy model has been demonstrated based on many statistical tools. [Received: 29 July 2019; Accepted: 24 November 2019]

Suggested Ideas to Manage Produced Water in Southern Iraqi Oil Fields

Suggested Ideas to Manage Produced Water in Southern Iraqi Oil Fields

An investigation of the optimum separation conditions in the Degassing stations of one of southern Iraqi oil Field

In field separation facilities operation, operators tend to determine the optimum conditions to maximize revenue.
 The object of this study is to investigate the present number of separation stages and their optimal conditions for degassing stations of oil Field. 
 A computer program model was written to predict the optimal conditions for oil field gas-oil separation stations subject to a given crude oil composition , flow rate and feed temperature and pressure using flash calculations with modified Soave-Redlich-Kwong Equation of state.
 Nine Bottom-hole well samples of reservoir crude oil was collected and subjected to PVT analysis commonly performed on crude oil, Surface stage separators gas samples at steady condition were taken and analyzed by gas chromatography apparatus to determine the gas composition.
 A good agreement was found by comparing theoretical and experimental prediction for gas composition.
 The results indicate that the present five separation stages is the optimum number and the values obtained for these optimum stages pressure are (514.7,119.7,42.7,26.7,14.7 psig) for Summer and (464.7,119.7,42.7,26.7,14.7 Psig) for Winter where the current operation pressures are (614.7,119.7,42.7,26.7,14.7 psi) for Summer and Winter. The total liquid yields in stock tank reaches (1.29, 1.31 %) for summer and winter respectively and the stock tank API Gravity reaches (0.41, 0.42) for summer and winter respectively.