Halfaya Oilfield Research Articles

A Novel Nanocomposite as a Corrosion Inhibitor in Halfaya Oilfield

A Novel Nanocomposite as a Corrosion Inhibitor in Halfaya Oilfield

Analytical and descriptive study of the production behavior for pilot multi-stages hydraulic fracturing wells in southeast Iraq

The hydraulic fracturing technique is a widely used technique worldwide, making it interesting to study. This technique was applied for the first time in Iraq on a tight carbonate reservoir in the Halfaya oil field. In this field, the oil production rates, and flowing pressure were low during production periods reflecting a problem for the development plan designed to increase production using a hydraulic fracture technique. Initially, the hydraulic fracture well showed high oil-producing rates, but then, quickly experienced a high decline failing to keep a stable production rate. To address this problem, it is important to describe and analyze the behavior of pilot hydraulic fracturing wells during their production period, study the inflow performance relationship (IPR), and determine the optimum wellhead pressure above the bubble point pressure (Pb) to avoid loss of lifting energy. Furthermore, it identifies the allowable flow rate to keep stable production, investigates the effect of selecting internal tubing size, and reveals a future production procedure for hydraulic fracture wells. This study reveals that the transient inflow performance relationship observed in the production history of hydraulic fracture well in the tight carbonate reservoir and traditional inflow performance relationship concepts are not applicable. The optimum wellhead pressure for stability in production for Wells w-5 and w-55 is determined to be 750 and 580 psi with optimum rates of 800 and 450 Bbl/D, respectively. The results also showed that producing at a high flow rate may cause a depletion in the fracture potential storage without giving an opportunity for a reservoir to compensate for the produced fluid into fracturing potential storage. The internal tubing size has a passive effect on the hydraulic fracture well, as an increase in size causes an unstable flow zone. Lastly, future production procedures emphasize keeping wellhead pressures stable or increasing them if they drop. This can be accomplished by re-adjusting the choke size according to any changes observed.

A Simple Dispersive Liquid-Liquid Microextraction for the Determination of Copper II in the Water Samples of the Halfaya Oil Field in Maysan

Background: Copper, an important trace element for life on Earth, is crucial to many metabolic processes. This includes its role in the production and breakdown of nucleic acids and the metabolism of proteins, lipids, and carbohydrates. Objective: We aim to integrate DLLME with a spectrophotometric method to establish a novel approach for quantifying trace amounts of copper in water samples. Methods: In this study, a new ligand known as a 2-(4 aminophenol) benzimidazole azo derivative was successfully synthesized. This ligand was created by converting 2-(4-aminophenyl) benzimidazole into a diazonium salt and coupling it with 8-hydroxyquinoline in an alkaline environment. The resulting product was a brown azo dye, which served as the ligand for detecting copper (II) in aqueous samples. Results: To analyze copper (II) in both pure and aqueous samples, we developed and validated micro-extraction techniques combined with UV-Vis measurement. Specifically, we used the DLLME (dispersive liquid-liquid microextraction) method to separate, enrich, and assess copper (II) in both its pure form and in aqueous samples. UV-Vis spectroscopy at a wavelength of 503 nm was used for this purpose. We considered several variables during the experiment, including the type and volume of the dispersive solvent, the extraction solvents, the temperature, the reaction duration, and the centrifuging time. By optimizing these conditions, we achieved linear procedures within the concentration range of (1.0–25.0) and (2.0–25.0) μg/mL for spectroscopy and DLLME methods, respectively. For the spectroscopic and DLLME approaches, the coefficient of determination (R2) was found to be 0.9963 and 0.9979 for the spectrophotometric and DLLME methods, respectively. The limit of detection (LOD) for copper (II) was found to be 0.23 and 0.04 μg/mL, respectively. Moreover, the recovery of the target analyte in aqueous samples was found to be between 95.6% and 101% for the spectroscopy method and between 102.4% and 108.2% for the DLLME method. Conclusions: These results demonstrate the effectiveness and accuracy of both methods in analyzing copper (II) in aqueous samples.

Logging Evaluation of Irreducible Water Saturation: Fractal Theory and Data-Driven Approach—Case Study of Complex Porous Carbonate Reservoirs in Mishrif Formation

Evaluating irreducible water saturation is crucial for estimating reservoir capacity and developing effective extraction strategies. Traditional methods for predicting irreducible water saturation are limited by their reliance on specific logging data, which affects accuracy and applicability. This study introduces a predictive method based on fractal theory and deep learning for assessing irreducible water saturation in complex carbonate reservoirs. Utilizing the Mishrif Formation of the Halfaya oilfield as a case study, a new evaluation model was developed using the nuclear magnetic resonance (NMR) fractal permeability model and validated with surface NMR and mercury injection capillary pressure (MICP) data. The relationship between the logarithm mean of the transverse relaxation time (T2lm) and physical properties was explored through fractal theory and the Thomeer Function. This relationship was integrated with conventional logging curves and an advanced deep learning algorithm to construct a T2lm prediction model, offering a robust data foundation for irreducible water saturation evaluation. The results show that the new method is applicable to wells with and without specialized NMR logging data. For the Mishrif Formation, the predicted irreducible water saturation achieved a coefficient of determination of 0.943 compared to core results, with a mean absolute error of 2.37% and a mean relative error of 8.46%. Despite introducing additional errors with inverted T2lm curves, it remains within acceptable limits. Compared to traditional methods, this approach provides enhanced predictive accuracy and broader applicability.

Wellbore Instability Analysis to Determine the Safe Mud Weight Window for Deep Well, Halfaya Oilfield

Wellbore instability is one of the most common issues encountered during drilling operations. This problem becomes enormous when drilling deep wells that are passing through many different formations. The purpose of this study is to evaluate wellbore failure criteria by constructing a one-dimensional mechanical earth model (1D-MEM) that will help to predict a safe mud-weight window for deep wells. An integrated log measurement has been used to compute MEM components for nine formations along the studied well. Repeated formation pressure and laboratory core testing are used to validate the calculated results. The prediction of mud weight along the nine studied formations shows that for Ahmadi, Nahr Umr, Shuaiba, and Zubair formations ranges between 12.5 to 15 ppg. The predicted safe mud weight value seems to be narrow with a well deviation higher than 350. Therefore, for Ahmadi, Nahr Umr, Shuaiba, and Zubair formations, the wellbore appears unstable compared to other formations. The results of stability analyses indicate that the breakout mud weight wasn’t affected by wellbore azimuth because of low-stress contrast. Furthermore, shear failure can be prevented by drilling the well with an inclination of less than 350. As well as, to prevent breakdown the well should be drilled with an inclination between 25o to 65o in the direction of minimum horizontal stress. These outcomes could be used to prevent wellbore instability and determine a safe mud-weight window when planning to drill nearby wells in the future.

Maximizing Production Profits: Optimizing Gas Lift Design in the Halfaya Oil Field

Gas lift is one of the most common artificial lift methods which is effectively utilized in the oil industry for enhancing production. However, proper gas allocation into wells can be challenging due to various limitations such as shortage in injected gas and economic considerations. Therefore, the current research is conducted to address the critical requirement to effectively distribute gas to maximize profits in the Halfaya Oil Field- Mishrif formation. Continuous gas lift is one of the most commonly used artificial lift methods. To enhance production rate, a sufficient amount of gas is injected into the production tubing at specific depths to reduce the liquid column pressure as each well has an optimal point for production in an oil reservoir. On the other hand, constraints of gas availability restrict achieving the optimal state of production. Such restrictions combined with economic limitations including high gas prices and compression costs, emphasized the necessity for optimal methodology to enhance oil production. Aside from the importance of the Halfaya oil field, there are limited relevant studies on artificial lifting methods specifically associated with the gas-lifting method used in this paper. Thus, the purpose of the current investigation is to propose a well-tested gas lifting design for oil production improvement. The approach combines the skill of the fmincon function built in MATLAB as an optimizer and the PIPESIM network model to create gas lift performance curves. This resulted in an oil production rate of 18860 STB/d, with a gas lift rate of 9.42 mmscf/d. Establishing such a systematic optimization process can manage the challenges of gas allocation in the Halfaya Oil Field towards maximizing production rates and ultimately increasing net profits.

Using ANN for well type identifying and increasing production from Sa’di formation of Halfaya oil field – Iraq

Abstract The current study focuses on utilizing artificial intelligence (AI) techniques to identify the optimal locations of production wells and types for achieving the production company’s primary objective, which is to increase oil production from the Sa’di carbonate reservoir of the Halfaya oil field in southeast Iraq, with the determination of the optimal scenario of various designs for production wells, which include vertical, horizontal, multi-horizontal, and fishbone lateral wells, for all reservoir production layers. Artificial neural network tool was used to identify the optimal locations for obtaining the highest production from the reservoir layers and the optimal well type. For layer SB1, the average daily production is 291.544 STB/D with the horizontal well, 441.82 STB/D with the multilateral well, and 1298.461 STB/D with the fishbone well type. Also, for the SB2 layer: 197.966, 336.9834, and 924.554 STB/D, and for the SB3 layer: 333.641, 546.6364, and 1187.159 STB/D for the same well type sequence. The cumulative production for each formation layer is 22.440 MMSTB from the horizontal well, 59.05 MMSTB from the multilateral well, and 84.895 MMSTB from the fishbone well types for the SB1 layer; 48.06, 70.1094, and 160.254 MMSTB for SB2; and 75.2764, 111.7325, and 213.1291 MMSTB for SB3 for the same well types.

Reservoir Evaluation Model of the Khasib Formation in Halfaya Oil Field, Mesan Governorate, Southern Iraq.

Evaluating the reservoir characteristics of a formation or geological unit constitutes an essential element and an effective tool in leading the successful exploration project currently prevailing. The Khasib Formation, which belongs to the secondary depositional cycle (Turonian - Lower Campanian) in the study area within Mesan governorate southern Iraq, was chosen as a study site, as the Khasib is one of the main reservoirs within the Mesan oil fields. Seven wells were selected distributed over the field area, which structurally, is represented by two domes oriented from NW to SE, in addition to a thin dome with a length of 38000 m. and a width of 12000 m. The corrected well logs were used as input by creating an Excel sheet and then processing that data through the Petrel Software to prepare maps, sections and Three dimensional diagrams. The Cross-plot diagrams showed that the limestone (calcite) is a main lithology of Khasib with some dolomite. 3-dimensional petrophysical models were prepared, through which identified three reservoir units: (Khasib-A, Khasib-B and Khasib-C). The porosity model shows that there is a good percentage of porosity within the Khasib-A unit, with a low percentage in unit-B. As for unit-C, it was characterized by the best porosity percentages. The water saturation model showed a high percentage at Khasib-A unit, reaching 80%, and it increased at unit-B, reaching 90%, while unit-C was characterized by the lowest percentage of water saturation. The volume of shale model indicates low to moderate rates in the Khasib-A unit, and a slight increase in unit-B, while unit-C showed a low rate of shale volume within the three units with very low values in most of the study wells, which confirms the superior quality of this reservoir unit, which can be considered the main productive reservoir unit of the Khasib Formation in the Halfaya oil field.

3D Geological Model for Sadi Reservoir in Halfaya Oil Field

3D Geological Model for Sadi Reservoir in Halfaya Oil Field

The Optimum Production Management for Production Problems in Sadi Reservoir of Halfaya Oil Field

The Optimum Production Management for Production Problems in Sadi Reservoir of Halfaya Oil Field

Evaluating Petrophysical Properties of Sa'di Reservoir in Halfaya Oil Field

The petrophysical characteristics of five wells drilled into the Sa'di Formation in the Halfaya oil field were evaluated using IP software to determine a reservoir and explore hydrocarbon reserve zones. The lithology was evaluated using the M-N cross-plot method. The diagram showed that the Sa'di Formation was mainly composed of calcite (represented by the limestone region) is the main mineral in the Sa′di Reservoir. Using a density-neutron cross plot to identify the lithology showed that the formation mainly consists of limestone with minor shale. Gamma-ray logs were employed to calculate the shale quantity in each well. The porosity at weak hole intervals was calculated using a sonic log and neutron-density log at the reservoir unit. Additionally, Archie's equation is applied to calculate fluid saturation using resistivity data. The reservoir water saturation in the uninvaded zone is calculated using Archie's equation, which determines the most essential element utilized in log evaluation. Finally, the permeability was measured using a flow zone indicator. The results indicate that the limestone and shale that the cuttings description report enhanced comprise most of the Sa'di reservoir. At the HF-316 and HF-21 wells, the core porosity was verified. In an uninvaded zone, the Archie equation offers the best estimation. Three equations were derived from the core data's porosity-permeability connection using a cross-plot of the reservoir quality index and normalized porosity index. According to the general interpretation, zones B1, B2, and B3 contain the most hydrocarbons; however, the B2 zone, the best layer in the Sa'di reservoir, has the highest hydrocarbon concentration. This is close to previous studies and field results. Finally, Sa'di A is formed mainly of mud lime and contains no hydrocarbons. As a result, Sa'di A was separated into A1 and A2 based on the percentage of shale difference.

Petrophysical Analysis Based on Well Logging Data for Tight Carbonate Reservoir: The SADI Formation Case in Halfaya Oil Field

Carbonate reservoirs are an essential source of hydrocarbons worldwide, and their petrophysical properties play a crucial role in hydrocarbon production. Carbonate reservoirs' most critical petrophysical properties are porosity, permeability, and water saturation. A tight reservoir refers to a reservoir with low porosity and permeability, which means it is difficult for fluids to move from one side to another. This study's primary goal is to evaluate reservoir properties and lithological identification of the SADI Formation in the Halfaya oil field. It is considered one of Iraq's most significant oilfields, 35 km south of Amarah. The Sadi formation consists of four units: A, B1, B2, and B3. Sadi A was excluded as it was not filled with hydrocarbons. The structural and petrophysical models were built based on data gathered from five oil wells. The data from the available well logs, including RHOB, NPHI, SONIC, Gamma-ray, Caliper, and resistivity logs, was used to calculate the petrophysical properties. These logs were analyzed and corrected for environmental factors using IP V3.5 software. where the average formation water resistivity (Rw = 0.04), average mud filtrate resistivity (Rmf = 0.06), and Archie's parameters (m = 2, n = 1.9, and a = 1) were determined. The well-log data values calculated the porosity, permeability, water saturation, and net-to-gross thickness ratio (N/G).

Optimization of Gas Lifting Design in Mishrif Formation of Halfaya Oil Field

The optimization of artificial gas lift techniques plays a crucial role in the advancement of oil field development. This study focuses on investigating the impact of gas lift design and optimization on production outcomes within the Mishrif formation of the Halfaya oil field. A comprehensive production network nodal analysis model was formulated using a PIPESIM Optimizer-based Genetic Algorithm and meticulously calibrated utilizing field-collected data from a network comprising seven wells. This well group encompasses three directional wells currently employing gas lift and four naturally producing vertical wells. To augment productivity and optimize network performance, a novel gas lift design strategy was proposed. The optimization of gas allocation was executed to maximize oil production rates while minimizing the injected gas volume, thus achieving optimal oil production levels at the most effective gas injection volume for the designated network. The utilization of the PIPESIM Optimizer, founded on genetic algorithm principles, facilitated the attainment of these optimal parameters. The culmination of this study yielded an optimal oil production rate of 18,814 STB/d, accompanied by a gas lift injection rate of 7.56 MMscf/d. This research underscores the significance of strategic gas lift design and optimization in enhancing oil recovery and operational efficiency in complex reservoir systems like the Mishrif formation within the Halfaya oil field.

Utilizing Reservoir Model to Optimize Future Oil Production for Hydraulic Fracture Wells in Tight Reservoir

The tight oil reservoir has low porosity and permeability generally suffers from rapid declines in production rates for oil wells, especially in southeast Iraq in the Halfaya oil field of the Sadi Formation, which is considered as tight oil reservoir with a reserve of about 25%; their OOIP accounts for more than a quarter of the total in the H oilfield. Implementing a pilot hydraulic fracture technique was a focus of attention in Iraq to increase the production rates, but the main issue faced in hydraulic fracturing wells was producing with a high oil rate for a short period of time then starting to decline rapidly, so a reservoir dynamic model was utilized to achieve the purpose of this study. The purpose of this study is to predict the production rate to prolong the production stabilization in horizontal and vertical hydraulic fracturing wells in order to avoid highly depleted fracture storage capacity and production below the bubble point. Recognize a practical procedure with horizontal hydraulic fracturing wells to reach stabilization. The reservoir simulator results show that a good history matches till 2021, predicting the rates that stabilize the production with flowing pressure above the bubble point pressure till 2025, producing rates for an eight-stage well with 700 BOPD and 900 BOPD for an eleven-stage well, whereas the rate for a vertical hydraulic fracture well is 225 BOPD. A practical procedure in horizontal hydraulic fracturing wells is achieved by keeping the wellhead pressure constant during the production period to stabilize transient behavior.

Estimation of the Fracturing Parameters and Reservoir Permeability Using Diagnostic Fracturing Injection Test

The term "tight reservoir" is commonly used to refer to reservoirs with low permeability. Tight oil reservoirs have caused worry owing to its considerable influence upon oil output throughout the petroleum sector. As a result of its low permeability, producing from tight reservoirs presents numerous challenges. Because of their low permeability, producing from tight reservoirs is faced with a variety of difficulties. The research aim is to performing hydraulic fracturing treatment in single vertical well in order to study the possibility of fracking in the Saady reservoir. Iraq's Halfaya oil field's Saady B reservoir is the most important tight reservoir. The diagnostic fracture injection test is determined for HF55using GOHFER software. Models for petrophysics and geology were calibrated using the diagnostic fracture injection test results after the petrophysical and geomechanical parameters of the rock have been determined. The HF55 vertical well, which penetrates the Saady reservoir, has well logs that have been used to evaluate the petrophysical and geomechanical parameters. These estimates have been supported by findings from the diagnostic fracture injection test through the utilization of standard equations and correlations. The findings of the diagnostic fracture injection test, often known as the diagnostic fracture injection test, are very compatible with the findings of the well logs. The diagnostic fracture injection test pre-falloff test event was examined to determine the instantaneous shut-in pressure and fracture gradient. In the meantime, Closure pressure, process zone stress, fracturing fluid efficiency, closure gradient, critical fissure opening pressure, storage correction factor, permeability, and pressure-dependent leak-off coefficient were all determined using the G function on plot. With the help of a specific software, the petrophysical and geomechanical properties of a single vertical well [HF55] was found. Saady B reservoir's upper and lower sections, along with it are therefore predicted to have the full range of petrophysical and geomechanical features. With the use of DFIT analysis, these features serve as the foundation for developing fracturing models.

Asphaltene Precipitation Investigation Using a Screening Techniques for Crude Oil Sample from the Nahr-Umr Formation/Halfaya Oil Field

Many oil and gas processes, including oil recovery, oil transportation, and petroleum processing, are negatively impacted by the precipitation and deposition of asphaltene. Screening methods for determining the stability of asphaltenes in crude oil have been developed due to the high cost of remediating asphaltene deposition in crude oil production and processing. The colloidal instability index, the Asphaltene-resin ratio, the De Boer plot, and the modified colloidal instability index were used to predict the stability of asphaltene in crude oil in this study. The screening approaches were investigated in detail, as done for the experimental results obtained from them. The factors regulating the asphaltene precipitation are different from one well to another, from the high-pressure-temperature reservoir to surface conditions. All these factors must be investigated on a case-by-case basis. Because the Halfaya oil field is still developing its petroleum sector, modelling, and forecasting the phase behavior and asphaltene precipitation is crucial. This work used crude oil bottom hole samples with an API of equal to 27 from a well in the Halfaya oil field/Nahr-Umr formation to create a thermodynamic model using Multiflash software. The data included the compositional analysis, the PVT data, and reservoir conditions. The thermodynamic model of asphaltene phase behavior was proposed using the Cubic-Plus association equation of state. All the screening techniques' results revealed the presence of an asphaltene precipitation issue (asphaltene unstable), which was confirmed by a thermodynamic fluid model. The aim of this paper is to predict the problem of asphaltene precipitation so that future proactive remedial methods can be developed to decrease the time and expense associated with it.

Determining the effect of mineral scaling formation under different injection water sources on the performance of Mishrif carbonate reservoir in Halfaya oilfield, Southern Iraq

The chief source of the oilfield scale is the mixing of incompatible waters. This study demonstrated that mixing the reservoir of Mishrif formation (Halfaya oilfield) with six types of injection water sources, including Tigris River water, producing water formation, Gulf seawater, Marshes water, Middle Kirkuk formation water, and Main Outfall Drain water (AL-Masab AL-Aam Channel), leads to the formation of salt crusts that cause the reduction of reservoir rock permeability. According to the Piper diagram, the Mishrif formation water of all extant water samples was of the sodium chloride type (NaCl), except for HF-81, which was between (NaCl) and mix (CaMgCl) type. A geochemical simulation model of water alignment (PHREEQC) was used to simulate this problem, and it revealed the mineral scaling from mixing processes. These minerals precipitate in rock pores and clog them, which then cause damage to the petrophysical properties of the reservoir and prevent the passage of liquids. Results showed that the best water types used for injection are Middle Kirkuk formation water, followed by the general downstream, then Gulf seawater, but treatment before injection is needed. The study of geochemical modeling method can help to better understand scaling issues by efficiently identifying the best injection water from various selected types with the lowest possible cost, which in turn improves oil production.

Development of 3D Geological Model and Analysis of the Uncertainty in a Tight Oil Reservoir in the Halfaya Oil Field

A geological model was built for the Sadi reservoir, located at the Halfaya oil field. It is regarded as one of the most significant oilfields in Iraq. The study includes several steps, the most essential of which was importing well logs from six oil wells to the Interactive Petrophysics software for conducting interpretation and analysis to calculate the petrophysical properties such as permeability, porosity, shale volume, water saturation, and NTG and then importing maps and the well tops to the Petrel software to build the 3D-Geological model and to calculate the value of the original oil in place. Three geological surfaces were produced for all Sadi units based on well-top data and the top Sadi structural map. The reservoir has been divided into 85 sublayers in the vertical direction and 170*143 grid cells in the x-y direction, totalling 2,066,350 grid cells. The Sequential Gaussian Simulation technique is used to fill 3D grid cells with property values in locations far from wells after upscaling the well log data, then distributed across all reservoir zones. The standard original oil in place has been calculated, uncertainty evaluation was used to obtain more accurate results. Model Risk Analysis employs Monte Carlo Simulation to generate the pessimistic, most likely, and optimistic reserve values (P90, P50, and P10). The uncertainty was affected by the oil formation volume factor, oil depth, petrophysical model (porosity, water saturation, and NTG), and reservoir geometric structure (horizons and zones).

Study on the Construction Method of Leakage Pressure Body in Fractured Formation

Lost-circulation is one of the major challenges in fractured formations limiting the optimized fast drilling, which is prone to huge economic and environmental losses. The leakage pressure prediction has been a major concern in the industry. To solve this problem, a method for the construction of leakage pressure body in fractured formations is proposed in this paper. First, a leakage pressure prediction model for different fracture scales is optimized. Secondly, a fitted relationship between leakage pressure differential and leakage rate is developed based on the leakage data of the actual drilled wells, which is used to correct the leakage pressure in the priority formation. Finally, a three-dimensional (3D) body of regional stratigraphic leakage pressure is established based on kriging interpolation. This paper presents an example analysis of a fractured formation in the Halfaya oil field. The result shows that the modified formation leakage pressure profile matches the field drilling conditions. The 3D visualization of the regional leakage pressure provides a more intuitive understanding of the distribution of leak-prone formations in the area, which can provide a targeted decision basis for leakage prevention and plugging in the area.

Optimization of Control Loops and Operating Parameters for Three-Phase Separators Used in Oilfield Central Processing Facilities

In this study, the Stokes formula is used to analyze the separation effect of three-phase separators used in a Oilfield Central Processing Facility. The considered main influencing factors include (but are not limited to) the typical size of oil and water droplets, the residence time and temperature of fluid and the dosage of demulsifier. Using the “Specification for Oil and Gas Separators” as a basis, the control loops and operating parameters of each separator are optimized Considering the Halfaya Oilfield as a testbed, it is shown that the proposed approach can lead to good results in the production stage.