bluuebunny/crossref_metadata_2025 huggingface dataset:
A Novel Emulsified Acid for Deep Wells Stimulation: Rheology, Stability, and Coreflood Study
Authors: Ahmed Musa , Sultan Abdullah , Qiu Xiangdong , Sidaoui Ziad , Ali Al-Amri Ahmad
Published: October 2018

The main objective of matrix acidizing is to create deep channels(wormholes) that bypass the damaged zone around the wellbore, which eventually, will increase the productivity or injectivity of the well. HCl-diesel emulsified acid is used to achieve that goal as well as other objectives such as prevention of tubing corrosion. The cost of HCl-emulsified acid could be lower by reducing the cost of either the surfactant (emulsifier) or the continuous phase (diesel). Hence, in this study, a low-cost, more efficient emulsified acid is proposed, with cheaper solid stabilizer (nanoparticle) instead of surfactant, and less expensive continuous phase; waste oil instead of diesel. Rheology, stability and coreflooding experiments were performed at high-pressure high-temperature (HPHT) of a typical reservoir conditions in the Middle East. This study addresses the feasibility of a novel waste oil emulsified acid system in acid stimulation treatment. In particular, rheology and stability of the emulsion and reactivity with limestone reservoir rock at HPHT were investigated. The reactivity was carried out through a series of core flow experiments at HPHT and compared with the conventional diesel emulsified acid. Stability experiments were conducted at 375 °F. Coreflood experiments were conducted using Indiana limestone 12″ cores and 1.5 in diameter. The initial permeability of the cores was in the range of 2-4 md. The pressure and temperature were 3000 psi and 275 °F, respectively. Four injection rates were used 0.5, 2, 5, and 10 ml/min. For better comprehension for resulted wormhole characteristic from both stimulation fluids under investigation, the CT-scan image for the Indiana limestone cores after injection of both waste oil and diesel emulsified acids were performed and analyzed through a high resolution imaging and visualization software.

From the laboratory results, the novel waste oil emulsified acid system showed a good potential as a stimulation fluid. For instance, it achieved lower pore volume of acid to break through (PVBT) compared to both conventional diesel emulsified acid and plain HCl. Moreover, diesel emulsion presented a better performance at lower injection rates whereas waste oil emulsion performed superiorly at higher rates. Thisindicates that, diesel emulsion is still better in terms of stimulation efficiency, however, waste oil emulsified acid still could be recommended in acid stimulation since it has low cost and acceptable performance. Furthermore, CT scan analysis shows that waste oil emulsified acid was capable of achieving narrow, branch-free, and deep wormhole which are the desired characteristic for any potential stimulation fluid.

The novelty of this work comes from the fact that waste oil emulsified acid performance for carbonate acid stimulation has not been addressed before and hence this work to fill in the gap.
The impact of hydraulic fracturing on the deliverability of multilateral wells at dry gas reservoirs
Authors: Ahmed M. Elmuzafar , Elnuaim Sami , Abdulazeem Ahmed
Published: October 2018

The use of multilateral wells became significant in the recent years for both oil and gas development projects due to its maximum productivity resulting into fewer dollars per SCF development cost. However, there is a common mistake during the planning phase of these complex wells. They usually overestimate/underestimate the production from these complex well due to the lack of analytical well productivity estimation models in the literature which would require expensive numerical modeling. This paper investigates the effect of hydraulic fracturing on the productivity of this kind of wells and other factors like the anisotropy and lateral length as well as the fracture conductivity.

22 different scenarios were investigated to study the effect of different variables on the deliverability of the multilateral well. The base case scenario was built using ECLIPSE simulator. The effect of the lateral length and the number of laterals were studied then the fracture effect introduced to the base case starting from 1 stage fracturing up to 8 stage fracturing. Furthermore, the reservoir anisotropy and the fracture conductivity was explored. All these data sets were analyzed and combined using regression techniques to get one mathematical model that can predict the productivity in a simplified procedure. Vogel-type was used to get the final productivity model.

Based on the results, it was found that the most significant parameters that affect the study are reservoir anisotropy, and the fracture width. It was observed that changing the number of fracture stages is significant specially in the 8 laterals case as compared to the 4 and 6 lateral cases respectively. In addition, changing the number of lateral while holding the number of fracture stages constant showed small effect on 1 and 3 stage fractures compared to the significant effect in the 2 and 4 stage fracture. Changing the total length of the laterals plus the main horizontal stem also have great influence in the productivity. The effect of the fracture width and reservoir anisotropy which was found to be the most affecting parameter.

The mathematical model is simple to be used for quick estimation of the productivity relationship multilateral dry gas wells with very good accuracy in a way that save a lot of effort and time. And also can be implemented in simulator to save a great computational effort. The model was tested using different cases and found to give reasonable results with small average error.
Investigating the effect of hydraulic fracturing in the pressure transient response for multilateral wells in dry gas reservoirs
Authors: Ahmed M. Elmuzafar , Abdalla Mohamed
Published: October 2018

Using pressure transient testing is very useful to identify reservoir properties, such as permeability, and reservoir size. However, it can also be used as an evaluation tool to test the success of the fracturing process as well as identifying the fracture properties such as conductivity and size. This paper presents an investigation of the fracture properties and their effect on pressure and pressure derivative signature in multilateral wells at dry gas reservoir as well as the effect of the number of laterals, length of laterals and reservoir anisotropy.

The base case scenario was built using ECLIPSE simulator. More than 20 scenarios were used to generate the data and use the early production region as the drawdown feed data. different scenarios were investigated to analyze the pressure derivative signature and hence study how hydraulic fracture stages will appear in the curve and how can we utilize that to characterize our fracture. The effect of the lateral length and the number of laterals were studied then the fracture effect introduced to the base case starting from 1 stage fracturing up to 8 stage fracturing. Furthermore, the reservoir anisotropy and the fracture conductivity was explored.

The results of this study can be used as qualitative method to judge the success of the fracturing job by comparing the response before and after the fracturing. It was noticed that increasing the number of lateral and the length of lateral shifted the pressure derivative curve down. However, increasing the fracture stages while keeping the number of lateral constant affected only the early region.

Well testing techniques can be extended to study the complex geometry of multilateral well especially when hydraulic fractures are induced. It will be a great benefit to the industry to test their work with a quick method without the need to use downhole monitors.
Management of the Change of Operation Classification Coding System for the Next Leap
Authors: Amer M. M. , Contreras W. B. , Canlas J. P. , AlShehri I. H.
Published: October 2018

National Oil Companies have always invested in and been dependent on information; gathering, managing, and utilizing data has now, more than ever, become more central to operational success. While the Drilling & Workover (D&WO) business is faced with retaining its capacity to do core operations, it is challenged to increase the rate of learning for drilling personnel.

Achieving these goals should be through a continuous process, which is data dependent. Data is only as valuable as the ability of engineers to extract meaning from it; meaning cannot be extracted without organizing, standardizing, and analyzing data effectively. Drilling data analysis is routinely performed in performance analyses/optimization; having a standard, consistent, yet flexible/scalable classification system is a must for this process.

Although drilling data has been available from the daily drilling reports and being utilized for performance analysis for long time, the process of performance analysis to extract knowledge and identify potential improvements has been hindered as a result of the limited variety and quality of the operation coding system previously in place. This paper is suggesting to move to a new coding system and will share how that change was managed successfully. The new system will be used to classify drilling operations more consistently, objectively, and comprehensively; and so a separate detailed lost time coding system was introduced. The normal operation codes were reviewed and cleansed, and comprehensive built-in quality control rules were developed and embedded in the system to allow guided operation classification and to make it easier for the end user.

A true challenge here was the management of this change, which impacted not only a huge volume of legacy data, about 10,000 wells, but also hundreds of end users with different business interests. Getting buy-in from different, and perhaps conflicted, stakeholders; migrating legacy data from the old structure to the new one; and training a massive number of end users were true challenges that had to be managed to make the change happen. In this paper, the authors would like to share their experience of managing this major change and how these different challenges were tackled.
Integrating Peng Robinson EOS with Association Term for Better Minimum Miscibility Pressure Estimation
Authors: Al-Kadem M. S. , Al-Mashhad A. S. , Al-Dabbous M. S. , Sultan A. S.
Published: October 2018

Minimum miscibility pressure (MMP) is a very critical parameter to design any enhanced oil recovery affiliated with carbon dioxide (CO2) gas injection methodology. MMP can be computationally estimated using the Peng Robinson Cubic Equation of State (PR-EOS). In this paper, an association term was incorporated into the equation to account for covalent bonds between oxygen and carbon atoms in a CO2 compound for accurate MMP estimation.

During the CO2 gas injection process, interactions between the oil multicomponent system and injected CO2 are in place where strong electrostatic force is exhibited between oxygen and carbon atoms. This attractive force cannot be neglected. Nevertheless, a Cubic Equation of State, such as Peng Robinson, accounts only for physical forces such as repulsion and attraction forces only. For this, an association term is introduced to account for electrostatic forces. Cubic plus Association EOS (CPA-EOS) was assimilated with Ahmed Tarek's methodology to estimate MMP rigorously in consideration of oil system and CO2 compositions.

MMP was estimated using both PR-EOS and CPA-EOS, and compared against the experimental value with a very minimal absolute error. Therefore, the results showed a close agreement between calculated and experimental MMP. The uncertainty was immensely reduced when utilizing CPA-EOS proposed by Ahmed Tarek for MMP estimation. Three correlations were applied to estimate MMP with a slightly high deviation from the experimental MMP values. This high error is due to the ignorance of the intermolecular forces exhibited between molecules among these correlations. It is worth mentioning that this proposed method is highly appreciating the intermolecular bonding exhibited in CO2 and hydrocarbon multicomponent mixture, which results in a very reliable and accurate estimation of MMP. In other words, integrating conventional EOS with the association term provides accurate estimation of MMP to ensure effective modeling of an enhanced oil recovery (EOR) design with CO2 injection.
Chemical Sealant Loss Circulation Materials for Fractured Formations: Right-Angle Viscosity Development with High Plugging Efficiency
Authors: Abdulrazzaq Waseem , AlBuraikan Reem , Savari Sharath , Whitfill Donald L.
Published: October 2018

Numerous lost circulation materials (LCMs) are sold in the global market to cure losses in highly fractured formations, but the success rate remains minimal. Lost circulation (LC) is a common challenge of global operators and service companies during either drilling or the oilwell construction phase of development and exploration. A new chemical-sealant-based LCM (CS-LCM) was developed to cure severe-to-total losses in highly fractured formations. The new CS-LCM is dispersed in a nonaqueous carrier fluid (NAF) and quickly forms a highly malleable viscous mass upon exposure to an aqueous reactant fluid and then sets harder under a wide range of temperatures.

Comprehensive and systematic tests were conducted on the new CS-LCM to determine the speed of the reaction at an optimized interval of time upon interaction with the reactant. Testing performed on the new CS-LCM included evaluating its flowability before and after the reaction and estimating the compressive strength. Additionally, the developed strength robustness of the CS-LCM was evaluated by its ability to withstand large differential pressures across extra-large holes (31 mm) in test media (simulating vugs in a formation).

The reaction rate of the CS-LCM showed measurable right-angle viscosity (RAV) development once the CS-LCM was preconditioned at a bottomhole circulation temperature (BHCT) and allowed to mix with preconditioned (at BHCT) reactant. A significant amount of compressive strength (>500 psi) buildup was observed in less than 1 hour of reaction time, which sustained more than 1,000 psi differential pressure on large vugs. The fast increase in viscosity (i.e., RAV) and quick strength development are the result of fast-reacting chemical additives present in the mixture. Additionally, the resultant set CS-LCM was determined to be soluble in 15% hydrochloric (HCl) acid at ambient temperature; hence, it is a viable solution for a reservoir section.

The new CS-LCM was developed to mitigate severe-to-total losses in highly fractured formations by means of RAV development followed by rapid strength buildup in a short interval of time, thus helping prevent overdisplacement away from the wellbore, hence minimizing nonproductive time (NPT) and drilling mud losses.
Integrated Approach to Prevent and Mitigate Stuck Pipe in Interbedded Depleted and High Pressure Gas Reservoirs
Authors: Atriby Kamal
Published: October 2018

Stuck pipe is one of the main challenges in any drilling operation especially drilling horizontal or deviated wells through deep reservoirs. Stuck pipe occurs while drilling, logging, running casing and running lower completion especially the Multi-Stage Fracturing (MSF) completion string. This causes long non-productive time, limits the drilling performance and increases the well cost. An integrated approach is necessary to eliminate and reduce the stuck pipe occurrence and improve operation efficiency.

This integrated approach starts with the planning phase by evaluating the formations characteristics, pressure and stresses across the planned well, and creating the predrill Mechanical Earth Model (MEM) using offset wells information to calibrate it. This allows to anticipate the drilling conditions and the severity of the risk in each well. The drilling fluid and bridging materials are designed based on the formations characteristics, lithology, pore pressure and anticipated pore throat sizes using specific software packages to identify the optimum bridging plan. The drilling, logging, and the completion strings are designed based on the risk type and severity. The operational practices and operating envelope are set based on the downhole anticipated conditions, risk severity and type, hydraulics and hole cleaning simulations. Actual downhole conditions and a reviewed risk level are continuously monitored and fed back in the process: the operational practices, the drilling fluid properties, the bridging materials design and operating envelope are revised and optimized based on the actual wellbore conditions during execution to improve operational efficiency and reduce the stuck pipe risk. The post job evaluation is a crucial part of the process to analyze the efficiency of the implemented actions, to capture lessons learned, and revise and update the integrated approach for continuous improvement.

This paper describes the whole integrated approach process together with the results of the implementation carried out in several wells with different profiles and subsurface conditions. It also highlights the successes achieved in stuck pipe prevention and improved operational efficiency.
Newly Engineered Tapered Drillstring in Deep and Complex Gas Wells Saves Rig Time and Reduces Operational Risks
Authors: Atriby Kamal
Published: October 2018

Drilling deep reservoir sections requires long drillstring and, consequently, long tripping and handling times. The long and heavy drillstring generates high side forces across the casing especially in S-shape and J-type wells that could affect its integrity. The operating envelope is affected and results in limited operational efficiency. A fit for purpose tapered drillstring was designed with the objectives of enhancing the operating envelope, minimizing the forces and stresses applied to both the drillstring and the casing, reducing the handling time to improve operational efficiency.

This newly engineered tapered string consist of 4" and 5-1/2" drill pipes, optimum number and size of heavy weight drill pipes and drill collars, and fit for purpose driving and steering mechanism to be utilized in both the 8-3/8" and 5-7/8" hole sections. The design is based on torque and drag simulations, drillstring dynamics and hydraulic analysis together with the driving mechanism and drill bit designs, paramount to reduce shock and vibration.

This novel approach was implemented successfully in various well types saving an average of 1.5 days per well. It also reduced both the downhole circulating pressure fluctuations and the Equivalent Circulation Density (ECD) by providing bigger annular clearance thus having a positive impact on differential sticking risks, side forces, and torque and drag.

This paper describes the engineering design and modeling undertook and the successful implementation of the tapered drillstring in deep and complex gas wells.
ThruBit Logging Saves Time and Reduces Stuck Pipe Risk in Very Challenging Downhole Conditions
Authors: Atriby Kamal
Published: October 2018

Generally, highly deviated and horizontal wells, with challenging borehole conditions, are logged using the Tough Logging Conditions (TLC) technique, which allows the logging tools to be run pipe-conveyed utilizing the drill pipes. This method however, takes considerable time up to two days per run and has many inherent operational risks such as stuck pipe, long open hole exposure time and potentially, wellbore deterioration. Also, in case of an obstruction in the open hole or in the presence of a logging tools failure, the TLC logging assembly must be pulled out of hole and a conditioning trip may be required before continuing with the logging operations. The ThruBit logging technique eliminates and mitigates most of the TLC operational risks saving rig time.

At section Total Depth (TD) and before running casing or an open-hole lower completions such as a Multi-Stage Fracturing (MSF) string, the ThruBit logging is performed through a combined reaming or dummy Bottom Hole Assembly (BHA) and consist of special ThruBit tools such as a portal bit, an hang off sub, and a flapper float valve. The ThruBit logging tools are run on wireline, pumped outside the portal bit, and hanged on a hang-off sub; the cable is then unlatched and retrieved after powering up thus confirming that the ThruBit logging tools are functioning. The logging data is finally recorded in the ThruBit logging tools memory while pulling out of hole.

The ThruBit logging technique was performed successfully across interbedded formations: a detailed operating procedure was developed to minimize stationary time to account for the differential sticking risk. It allowed to save three days of rig time and it shorten the time between drilling the section and running the lower completion, thus reducing the risks related to open hole exposure time. ThruBit logging is a true game changer in acquiring the formation evaluation logs in challenging downhole conditions, reducing stuck pipe risks and saving time.
Continuous Flow Synthesis of Petroleum Sulfonates from Crude Oil and Formulation into Nano-Surfactants for Cost Efficient Oil Mobilization
Authors: Alzobaidi Shehab , Gizzatov Ayrat , Abdel-Fattah Amr I. , Mashat Afnan
Published: October 2018

The oil mobilization in tertiary mode using chemicals has been shown to be a promising approach. In such technique, surfactants with or without polymers, designed for specific reservoir conditions, are added into water during water flooding to further drive remaining oil out of the porous structure of the reservoir rock into production wells. The success of the method depends on the cost of the chemicals used and the amount of the additional incremental oil mobilization achieved beyond water flooding. Thus, utilizing reservoir-compatible and inexpensive surfactants is a key. Petroleum sulfonates are some of the most abundant and inexpensive surfactants that can be made available at the scale required for efficient oil mobilization operations. However, petroleum sulfonates lack solubility in harsh reservoir conditions which makes them rather inapplicable for reservoirs with high salt content (e.g. > 50,000 ppm) and high temperature (e.g. 100 °C). We have successfully developed a simple, one-step nano-encapsulation technique to transform petroleum sulfonates into nano-sized multi-emulsion droplets in high salinity injection water featuring long-term stability at high temperatures. To further improve the economics and sustainability of such NanoSurfactants (NS), we developed a continuous and cost-effective synthesis process of petroleum sulfonates, directly from crude oil. The in-house-produced sulfonates were then formulated into a NS solution in high salinity injection water utilizing our encapsulation method. Results showed that petroleum sulfonates were successfully synthesized as seen from NMR analysis. The formulated NS was persistently stable at reservoir conditions, altered the wettability of the oil-wet rock as verified by contact angle measurements, and triggered crude oil release from the rock by spontaneous imbibition. This work provides a solution to produce petroleum sulfonates and formulate NS on-site for use in cost-efficient oil mobilization operations in high salinity and high temperature reservoirs.
Utilizing Artificial Intelligence Techniques for Predicting Rock Failure Parameters
Authors: Negara Ardiansyah , Ali Syed , AlDhamen Ali , Kesserwan Hasan , Nair Asok , Aleid Zahra
Published: October 2018

Maintaining a stable borehole is one of the major tasks during drilling operations. During the drilling, borehole breakout and drilling induced fractures are the two main instability problems which may lead to stuck pipe, sidetracking, and loss of circulation. To evaluate the stability of a wellbore, a constitutive model is required to estimate the stresses around the wellbore coupled with a failure criterion to predict the ultimate strength of reservoir rocks. The Mohr-Coulomb failure criterion is one of the commonly accepted criteria for rock strength estimation at a given state of stress. This failure criterion is mainly contributed from the cohesion and coefficient of internal friction parameters, which are determined by laboratory measurements. The laboratory measurements, although more reliable, are expensive and time-consuming. This paper discusses artificial intelligence models particularly multilayer perceptron (MLP) and support-vector regression (SVR) for predicting cohesion and coefficient of internal friction from elemental spectroscopy and petrophysical properties.

Elemental spectroscopy, density, porosity, cohesion, and coefficient of internal friction data presented in this paper are based on various geological formations. Cohesion and coefficient of internal friction are determined through a rock mechanical test in the laboratory, while elemental spectroscopy data were obtained from X-ray fluorescence (XRF) analysis. We divide the data set into training and testing data. Training data is used to train MLP and SVR then establishes the cohesion prediction models. Similarly, training data is used to train and construct the MLP and SVR-based coefficient of internal friction models. Both models are then examined using the testing data.

Cohesion and coefficient of internal friction predicted from MLP and SVR match well with the laboratory measurements. Two quantitative measures for estimation accuracy are used including coefficient of determination and mean absolute percentage error. Cross-correlation plots of predicted cohesion and coefficient of internal friction and the experimental results show very good coefficient of determination and relatively small error. The results demonstrate that amongst the MLP and SVR models, the models whose inputs are grain density, porosity, and elemental spectroscopy are the best models. From a practical point of view, the application of artificial intelligence techniques as a new method for indirect estimation of rock failure parameters are beneficial especially when the amount of core samples are relatively few.
Predicting Formation Tops while Drilling Using Artificial Intelligence
Authors: Al-AbdulJabbar Ahmad , Elkatatny Salaheldin , Mahmoud Mohamed , Abdulraheem Abdulazeez
Published: October 2018

Formation tops is one of the important information that is gathered during the exploration and delineation phase. This valuable information aids in setting the casing properly during the development phase and ensure proper zonal isolation between different zones. Every time a new well is drilled, actual formation tops are picked using various methods such as rate of penetration (ROP) charts, gamma ray (GR), formation cuttings and mud logging. These data are used in updating the geological model and in ensuring a proper zonal isolation in critical sections. Each of these methods has its own advantages and limitations such as cost, accuracy, and man power. Most of these methods suffer from a lag in time or depth which prevents the formation tops from being picked instantaneously.

The goal of this paper is to introduce a better method for picking formation tops. It can be a potential alternative to replace other more expensive techniques. The new technique involves the use of drilling mechanical parameters along with the rate of penetration to increase the accuracy of prediction. This will help to detect a true increase or decrease in ROP even if the drilling parameters are fluctuating. Field data were gathered from two wells with the same bit size and the same formation type. The data were screened and cleaned from any outliers or noise using six different algorithms while retaining the data quality and representation. Using six inputs and four outputs, 30 different sensitivity analyses were conducted including using artificial neural network (ANN) to achieve the best results and prediction accuracy. Well-A was used to train and test the data with 70/30 ratio, while well-B was totally unseen data.

The results obtained showed that ANN can predict formation tops with great accuracy. The best result was found using ANN with 20 neurons and one layer in which correlation of coefficient (R) was 0.94 and 0.98 for both wells. With this new technique, detecting formation changes will be faster compared to other methods since no logs have to be processed and nor any wait is required for cuttings to reach the surface. The formations can therefore be picked in real-time with good accuracy at almost no extra costs because it uses the real-time data which is already available.
Achieving Higher Retardation of Emulsified Acid by Additive Optimization
Authors: Sidaoui Ziad , Aly Moustafa Taha , Al-Murisi Mohammed Abdullah , Qiu Xiangdong
Published: October 2018

Emulsified acid has proven to be very effective in both matrix acidizing and fracturing treatments. It has become the preferred stimulation acid system due to the significant reduction in tubing corrosion compared to straight acids and due to the reaction retardation, which allows it to penetrate deep into the formation before it breaks down and the reaction starts. The goal in the treatment is for the fluid to reach the formation while the acid phase is still encapsulated in the diesel one. Therefore, determining the optimal formulation of the emulsified acid system is essential for efficient well stimulation.

The objective of this work is to make the emulsified acid a fit-for-purpose system. This is achieved by investigating the effect of iron control and chelating agents on the stability and reaction with dolomite. Extensive testing is conducted to determine and select the effective concentration of the iron control and chelating agents to meet the needed stability to stimulate oil and gas wells.

This work includes the measurement of the stability of emulsified acid and the reaction weight loss as a function of the concentration of these agents at different periods of heating time. The tests are conducted at 135°C with a concentration of 28 wt% HCl and an acid-to-oil ratio of 70:30. For each agent, the concentration is reduced by one-third, starting from an initial concentration. The results show that the most-stable emulsified acid is achieved with no iron control agent and with an initial concentration of chelating agent. Furthermore, different concentrations of iron control agent result in a notable change, especially after 2 hours of heating. As for the chelating agent, its optimal amount is the original concentration; further increases in concentration do not show a specific trend. Moreover, increasing or decreasing the amount to four-thirds or two-thirds of the initial concentration has the same effect on the reaction weight loss.

The added value this work brings is the fit-for-purpose application of the emulsified acid system in which optimal concentrations of the ingredients result in an emulsified acid system that is better suited for a particular reservoir.
Optimization of Chelating Agent EOR Solutions for Carbonate Reservoirs
Authors: Hassan Amjed M. , Al-Hashim Hasan S.
Published: October 2018

This paper presents a novel approach for optimizing the chemical concentrations for EOR applications in carbonate reservoirs characterized by high salinity and high temperature. The chelating agent fluid systems used in this study were prepared using undiluted seawater. The approach is found to be a cost effective and resulted in very significant incremental oil recovery when applied after the conventional seawater-flooding, and could be used as an alternative to the conventional and low salinity waterflooding. The used chemicals are environmental friendly, stable at high salinity and high temperature and do not required additional chemical additives.

A comparison of two chelating agent EOR solutions having concentrations ranging from 3 to 10 wt.% prepared using undiluted Arabian Gulf seawater and used in sequential coreflooding tests to identify the best chelating agent solution and its optimum concentration for getting the highest incremental oil recovery after conventional seawater flooding with a minimum impact on rock integrity. The impact of fluid concentrations and pH on oil recovery and permeability improvements was analyzed, and the productivity index of each solution at the end of each injection sequence has been evaluated. Finally, a chemical cost evaluation study was conducted to identify the optimum chemical concentration that minimize the usage of chelating agents and maximize the oil recovery.
Laboratory Study of CO2 Foam for Enhanced Oil Recovery: Advanced Screening, Optimization, and Evaluation
Authors: Ahmed Shehzad , Elraies Khaled Abdalla , Hashmet Muhammad Rehan , Hanamartani Alvinda Sri , Bt Mohd Shafian Siti Rohaida
Published: October 2018

CO2 foam has been proposed as mobility control agent to overcome various limitation of CO2 injection such as viscous fingering, gravitational override and reservoir heterogeneities which lead to poor sweep efficiency. In this study, CO2 foam formulation was screened and optimized under HPHT conditions to achieve strong foam which results in high oil recovery. For this purpose, different surfactant formulations were prepared in brine with fixed salinity. The stability of bulk foam was measured using FoamScan (Teclis) in the presence of Malaysian crude oil. Whereas, a HPHT foam rheometer was used to perform advanced level screening and optimization at different foam qualities and shear rates. The best foam formulation obtained was then evaluated in core flooding experiment using Berea sandstone (250mD) by co-injection mode under HPHT condition. Among various formulated surfactant mixtures, the combination of alpha olefin sulfonate (AOS) and betaine with specific composition was able to generate strong supercritical CO2 foam at different shear rates under reservoir conditions. Foam rheology results showed that 80% foam quality as the optimum condition for having a high apparent viscosity. Results from co-injection experiments in porous media show that the designed CO2 foam has successfully improved the cumulative oil recovery from 57.58% to 74.08%.
Using Managed Pressure Drilling to Reduce Stuck Pipe Problem
Authors: Alkamil Ethar H. , Abbood Husam R. , Flori Ralph E. , Medley George , Nauduri Sagar , Alsaba Mortadha
Published: October 2018

Differences between mud pressure in a wellbore and pore pressure in high permeability rocks can lead to differential sticking, particularly when drilling deviated wells and encountering mud losses. Several solutions, all challenging, can be used to address this problem, where the conventional mitigation method of managing the mud weight (MW) is often used. However, managed pressure drilling (MPD) offers a promising solution with a positive risk-adjusted cost and other benefits.

Wells in the E oilfield in southern Iraq are typically drilled overbalanced and therefore often experience a high percentage of non-productive time (NPT) due to differential sticking. This study evaluates the feasibility of using MPD to optimize the drilling process by decreasing the mud weight while applying the required surface pressure to achieve the target bottom hole pressure (BHP). A simulation software, which uses different mud weights to determine the required choke surface backpressure (SBP) to achieve the targeted equivalent circulation density (ECD).

Historically, differential sticking has not been a primary driver to justify MPD. However, MPD offers more dynamic and rapid wellbore pressure control by adjusting SBP applied to the annulus for a given MW, and can actually decrease the risk of differential sticking. Instead of shifting MW or changing other drilling parameters, MPD adjusts the required ECD and/or equivalent static density (ESD) based on the formation pore pressure gradient. Additionally, MPD directly lowers SBP in the event of mud losses due to high ECD/ESD to decrease the BHP without the need to reduce MW.

This paper discusses the application of using a hydraulic simulation software to model the drilling development plan. The software optimizes MW and SBP while drilling, making pipe connections, and completing the well. Furthermore, it discusses the sensitivity effects of each parameter on wellbore pressure and provides guidelines for managing pressure by adjusting these variables.
IIncreasing ANN Accuracy, by Improving the Training Dataset Criteria. Case Study: Identify the Formation Density from The Drilling Surface Parameters in Real-Time
Authors: Al Gharbi Salem , Liao Qinzhuo , Elkatatny Salaheldin , Abdulraheem Abdulazeez
Published: October 2018

Objective

The objective of this paper is to introduce a new methodology to increase the accuracy of the Artificial Neural Network (ANN) by improving the selection criteria of training dataset. Such approach will result in faster and better prediction models.

Methods and Procedures

The strength of ANN is its capability to find a correlation between input and output. This correlation consists of several connections called neurons that represent coefficients and weight factors. Developing such neurons requires a large number of internal iterations and data processing, which include a lot of randomness, starting from identifying the training and testing dataset. This paper introduces a methodology that ensures the training dataset in ANN has a wide range and a small size, which improves the training dataset criteria and leads to results that are more accurate.

Results and Conclusions

A case study is conducted to identify the formation density from the drilling surface parameters. Several ANN models, including the proposed method, are constructed on the same dataset. Results show that the new methodology can be 85% faster and 18% more accurate than the traditional ANN on average. It is as accurate as the best traditional ANN, while the former is 90% faster than the latter.

Novel and Additive Information

The novelty in this approach is its methodology which results in much faster ANN development with higher accuracy. It is worth mentioning that the new methodology is based on 50% training dataset, which reduces the training dataset size up to 25% compared to the traditional methods.
Effect of the Type of Fracturing Fluid on the Breakdown Pressure of Tight Sandstone Rocks
Authors: Muqtadir Arqam , Elkatatny Salaheldin , Mahmoud Mohammed , Abdulraheem Abdulazeez , Gomaa Ahmed
Published: October 2018

Hydraulic fracturing is performed to enhance production in reservoirs with low permeability. It's an effective technique but there are still several uncertainties associated in its implementation. One of the uncertainties is the dependence of breakdown pressure on the type of fracturing fluid used. The objective of this paper is to perform an experimental study to determine the role of fracturing fluid on the breakdown pressure of tight sandstone rocks.

The dimensions of the samples are 2 in. (diameter) by 2 in. (length). A hole of 0.25-in. in diameter and 0.75-in. length is drilled on one face of each core through which the fracturing fluid is pumped. A strong power relation between the viscosity of the fracturing fluid and breakdown pressure was seen. As the viscosity increased, the breakdown pressure increased significantly. Computed Tomography (CT) scan showed that the direction of fracture is along the bedding plane. As the viscosity increased, the fracture width and height increased. For most tests, the fractures created were bi-wing fractures. Some single wing fractures were created due to deformities in the borehole.
A Hybrid Integrated Compositional Reservoir Simulator Coupling Machine Learning and Hard Computing Protocols
Authors: Putcha Venkataramana B. , Ertekin Turgay
Published: October 2018

The compositional representation of a petroleum system offers a greater detail in the phase equilibria calculations when compared to the black-oil approach. However, the slow and iterative nature of the numerical EOS based flash calculation is the primary drawback of compositional modeling. In this work we propose a hybrid model coupling machine learning and hard computing algorithms to accelerate the coupled wellbore hydraulic and numerical reservoir simulation processes. In this work, a robust compositional articificial neural network (ANN) based wellbore hydraulics tool is successfully coupled with a numerical compositional reservoir simulation model. The proposed hybrid simulation protocol is validated by comparing the results generated from the coupled ANN-numerical model against the fully numerical model, and a commercial compositional numerical simulation software package using a single-phase liquid, a single-phase gas and a two-phase liquid/gas case. Also, a comprehensive gas lift case study is discussed to compare the results and computational efficacy between the coupled ANN- numerical model and the full numerical model. It is observed that the mean deviation in the total oil production of the hybrid simulation protocol when compared to the full numerical model under the entire range of gas lift injection rates is approximately 5%, while the computational time taken by the coupled ANN-numerical model is 160 times less than the corresponding full numerical model. The proposed model can be employed as a practical gas lift optimization tool. More importantly, it gives the opportunity for simultaneously exploiting the strengths of both hard-computing and soft-computing algorithms.
Chemical Enhanced Oil Recovery with Water Soluble Poly Ionic Liquids in Carbonate Reservoirs
Authors: Alhussinan Saud N. , Alyami Hamdan Q. , Alqahtani Naif B. , AlQuraishi Abdulrahman A.
Published: October 2018

Recovering oil from carbonate reservoirs by waterflooding is often ineffective due to the combination of ineffective sweep and the originally oil-wet nature of that rocks. Ionic liquid monomers and polymers have recently attracted attention as chemical agents for enhanced oil recovery. 2-acrylamido-2- methylpropane sulfonic acid copolymer with methacrylic acid (AMPSA/MAA) diluted in sea water at 3000 ppm was previously screened among other polyionic liquids (PILs) at different concentrations (Abdullah et. al, 2017) and proved to be the most effective enhanced oil recovery chemical. The PIL AMPSA/MAA was tested with sandstone and proved efficient on enhancing oil recovery. In this study, we extend the work to explore the efficiency of such PIL on carbonates.

A post-secondary water flooding was conducted and an incremental tertiary recovery of 6% original oil in place (OOIP) corresponding to 12% residual oil in place (ROIP) was obtained indicating the efficiency of the AMPSA/MAA PIL. This carbonate recovery compares to 10% OOIP in sandstone as reported in previous study (Abdullah et. al, 2017). This difference can be attributed to the low permeability characterizing the carbonate sample used in this work in comparison to the sandstone tested earlier. Seawater-crude oil Interfacial tension and contact angle measurements on carbonate substrate were performed at elevated temperature and pressure to investigate the possible recovery mechanisms. Interfacial tension (IFT) resulted in insignificant IFT drop. On the other hand, contact angle measurements confirmed wettability alteration towards more water wet state indicating it as the main recovery mechanism in carbonates.
Key Factors in Managed Pressure Cementing for Deep Water
Authors: De La Cruz Sasso Alejandro , Paredes Jose Luis , Puerto Gustavo , Bedoya Jorge
Published: October 2018

Both minimizing risks and providing adequate barriers are targets during cementing operations. This paper discusses key factors to consider during the design and execution of managed pressure cementing (MPC) operations in deep water. These factors are the result of important best practices identified for dependable results. The key learnings from different applications can provide more reliable MPC applications while minimizing associated risks.

Accurate data collection is necessary to understand cementing simulation results. The process discussed used pressure while drilling (PWD) to collect data, such as equivalent circulating density (ECD) and equivalent static density (ESD). This data, in combination with data generated at the surface from the annulus, and a fit-for-purpose temperature profile were then used in a state-of-the-art software to help replicate actual drilling wellbore conditions and enable model calibration for the cement operation. Using a calibrated model, MPC analysis performed during the planning stage was updated to help predict different MPC scenarios.

Cementing simulation results should provide the pumping schedule [e.g., volume in, volume out, planned surface backpressure (SBP), contingency SBP, and critical events along the schedule]. During the planning phase, the simulation results helped address misconceptions regarding MPC operations (e.g., rate out equal to rate in) and the SBP interpretation by accounting for surface equipment setup. The design accuracy was confirmed during the MPC application. Two cement operations were completed, with minor deviations that were addressed properly as a result of the analysis and risk assessment previously performed. Variable sensitivity (temperature, mud compressibility properties, fluids rheology, geometries downhole and at surface, MPD choke limitations) was important to maintaining SBP within the operational window to avoid influxes or losses. This paper discusses recommendations to provide guidelines for deepwater MPC design and execution.

MPC operations in deepwater environments have a few applications within the oil and gas industry. This paper provides important information that can help improve this method and provide optimal design modeling and analysis. Additionally presented are key factors for zonal isolation in deep water engineering and operative considerations for improvement of this unconventional method.
Polyoxyethylene Ether Sulfate Surfactant for SP Flooding in High Temperature, High Salinity Reservoirs
Authors: Hongyan Cai , Qun Zhang , Youyi Zhu , Zhaohui Zhou , Hongzhuang Wang , Jianfeng Sun
Published: October 2018

Chemical combination flooding technique (CCF) meets great technical challenges in High temperature, High salinity (HTHS) reservoir. The requirements on thermal stability, salt tolerance, solubility and interfacial activity of surfactant greatly narrow the selection scope of chemical agent. Conventional anionic surfactant heavy alkyl benzyl sulfonate (HABS), petroleum sulfonate (PS) or nonionic surfactant Ninol are not suitable due to drawbacks of solubility and stability.

A novel extended surfactant alkyl polyoxyethylene Ether Sulfate (AES) was developed for CCF in HTHS reservoir. Compatibility with reservoir conditions and other surfactants of prepared AES surfactant were tested. Interfacial activity and phase behavior of related formulations were studied. In addition, the wettability alteration capability of AES was also investigated.

The experimental results demonstrate surfactant AES has very strong salt tolerance capability, showing a clear solution at salinity as high as 200,000 mg/L. As a comparison, conventional surfactants HABS and PS have poor solubility under high salinity environment. The addition of AES in surfactant solution greatly improves solubility of anionic surfactants HABS and PS. At the same time, interfacial tension (IFT) of these combined formulations is also remarkably decreased to ultralow magnitude (10−3 mN/m or lower). Electrolyte screening in oil/water phase behavior test demonstrates gradual transfer of phase type from Winsor I, Winsor III to Winsor II with the increase of salt concentration from 0 to 200,000 mg/L. Contact angle of 0.20% AES solution on modified silicon film decreases with the increase of electrolyte content.

The developed extended sulfate surfactant shows unique advantages under HTHS reservoir. The combined AES and HABS formulation makes it possible for the application of conventional anionic surfactant in HTHS conditions.