bluuebunny/crossref_metadata_2025 huggingface dataset:
A Workflow to Investigate the Impact of the Spontaneous Imbibition of a Slickwater Fracturing Fluid on the Near Fracture Face Shale Matrix
Authors: Al-Ameri Aymen , Gamadi Talal , Ispas Ion , Watson Marshall
Published: October 2018

The present study used the workflow presented in Al-Ameri et al. (2018a, 2018b) to evaluate the impact of the fracturing fluid imbibition on the near fracture face shale matrix. Al-Ameri et al. (2018b) used carbonate-rich outcrop shale core samples that had very low and no clay content. However, in this workflow, core samples from the Barnett reservoir that had an abundant amount of quartz and clay were used. The primary aspect of the current study is to investigate the mutual effect of the shale rock petrophysical properties and the polymer adsorption; moreover, the effect of the shale mineralogical composition on the rock prone to adsorb polymer. The effect of the non-ionic surfactant on the imbibition rates, and also the anisotropy on the rock ability for polymer adsorption were also investigated. The results of this workflow were compared to the Marcellus samples results presented in Al-Ameri et al. (2018b).

The workflow incorporates conducting three systematic imbibition experiments for a same shale core sample using brine, slickwater, and brine again. The sample brine permeability was measured before and after the imbibition experiments using a constant rate steady-state permeability setup.

The results showed that the polymer adsorption reduces the brine spontaneous imbibition volumes. Moreover, the shale petrophysical properties could dominate the polymer adsorption more than the mineralogical composition.

Adding a non-ionic surfactant to the slickwater enhanced the imbibition rate considerably into both of the Barnett and Marcellus shale samples, and that improves the fluid flowback in these shales.

The bedding planes and their orientation are among the factors that control the effect of the polymer adsorption on the fluid imbibition rate. The more obvious are the bedding planes, the higher impact of the polymer adsorption on the fluid imbibition rate. However, the petrophysical properties have more effect on the shale prone to adsorb the polymer than the bedding plane orientation.

The effect of the polymer adsorption slightly increased the capillary pressure curve. However, as the porosity and permeability increase, the effect of the polymer adsorption on the capillary pressure increases. In comparison to the Eagle Ford shale, the Barnett and Marcellus shales had lower capillary pressure, and that could be one of the reasons of their higher fluid flowback. The impact of the polymer adsorption on the water relative permeability was less for the Barnett sample in comparison to the Marcellus sample because of its lower porosity and permeability.
Application of Multi-Functionalized Surfactant to Enhance Hydrocarbon Production in Tight Oil & Gas Formations Yields Successful Results
Authors: Quintero Harvey , Hawkes Robert , Mattucci Mike , Sessarego Sebastian , O'Neil Bill , Zhang Kewei
Published: October 2018

Oil and gas shale hydraulic fracturing designs for new wells drilled typically call for water volumes as high as 50,000 m3 (314,000 bbls). The cleanup of these massive water volumes during flowback must be efficient and minimize fluid invasion into the matrix. Once the saturation of the invaded water zone is reduced to the lowest possible level during flowback (cleanup operations), hydrocarbons can flow freely into the wellbore. However, the flowback behavior in unconventional reservoirs is quite different than in conventional reservoirs where soakback and slowback techniques are implemented. It is not uncommon for these wells to be shut in or for weeks or even months following the hydraulic fracturing treatment. Chemical and surfactant flowback enhancers such as microemulsions and nano-surfactants are additives typically used in hydraulic fracturing to assist in flowback design and improve load fluid recovery as they minimize fracture face damage due to water blockage.

In this paper, we describe the successful field application of a multi-functionalized surfactant (MFS) that significantly outperformed common surfactant chemistry when applied to mixed-wettability shale core samples in laboratory Amott cell tests. The results from the laboratory testing were reflected in field trials: the relative permeability to hydrocarbon was increased and production was enhanced.
Integrating Microgel-Low Salinity Waterflooding to Improve Production Profile in Non-Crossflow Heterogeneous Reservoir
Authors: Alhuraishawy Ali K. , Bai Baojun , Wei Mingzhen , Almansour Abdullah , Alsaba Mortadha , Elsharafi Mahmoud
Published: October 2018

The oil recovery from fractured reservoirs is usually low and the early water breakthrough is one result of the fractured reservoir. Two enhanced oil recovery (EOR) methods, low salinity water flooding (LSWF) and micro-gel, have recently drawn great interest from the oil industry. We integrated both methods into one process. The objective of this study was to test how the combining method could reduce production rates from the fractured layer and improve the production rate from the non-fractured layer through laboratory experiments.

The parallel non-crossflow models, which were made of sandstone cores and two core holders, were built. The gel strength, water salinity, gel particle size, and sandstone permeability effects on oil recovery, production rate, and gel penetrations were studied. Sodium chloride (NaCl) was used for brine flooding and preparing swollen PPG. Two brine concentrations (1.0, and 0.01 wt. % NaCl) were used for the experiments. A light mineral oil was used. A flow rate of 0.5 ml/min. was used to inject the brine into the parallel non-crossflow models before and after the gel was placed into the fracture. The gel was injected into Outlet 1 to fill out the fracture at a flow rate of 2.0 ml/min until the gel injection pressure reached 500 psi. The optimum water salinity for the application of the coupled method was determined through laboratory experiments to be 0.01 wt. % NaCl because this gave the highest gel penetration into the partially fractured layer. However, the best water shut-off was obtained when the water salinity was 1.0 wt. % NaCl. The incremental oil recovery was almost the same in both 1.0 and 0.01 wt. % NaCl water salinity. When the gel particle size decreased, the water shut-off from the partially- closed fracture layer and the incremental oil recovery from the matrix were increased. This application had no significant effect when the core permeability was low because there was not much of an effect on the production rate ratio after gel treatment. From the laboratory experiments, we concluded that the PPG application might be more successful it is swelled in a low brine concentration.
Acid Fracturing of Low Permeability Carbonate Formation Lessons Learned
Authors: Rafie M. , AlOtaibi F. M. , Al-Dahlan M. N. , Suwadi S. H.
Published: October 2018

This paper provides information on the journey and lessons learned from one well’s acid MSF from the required lab design, through on-site fluids’ QA/QC findings, to the 4 days of flow back sample analyses indication. Several pre-job lab assessments were conducted to: Optimize the diversion fluids rheology, assure sufficient acid corrosion inhibition, and eliminate the incompatibility issue between all pumped fluids and the reservoir acid sensitive crude oil. Additionally, on-site QA/QC critical findings for each stage fluid resulted in taken corrective actions for assured acceptable concentration and stability of mixed acid recipes and the adequacy of fracturing fluid viscosity. The 4 days of flow back samples analyses revealed the need for a longer cleanup time.

In addition, ion composition of flowback samples were used to identify areas of improvement and enhancement in fracturing fluid design. The successful massive multistage acid fracturing was achieved with over a two-fold increase in production rate. A major part of the success is attributed to a scheme of the fluid’s optimization, quality control, on-site QA/QC and cleanup monitoring progress. In addition, on-site fracture treatment evaluation for each stage individually has a major impact on operational success utilizing pressure sensors response and fracturing simulation software.

Finally, a comprehensive analysis for an acid fracture job and the lessons learned from this operation will be shared. The journey of lessons learned started from the lab to the field, and back to the lab, with strong guidelines for all future acid fracturing jobs in similar oil fields
Probabilistic Production Forecasting and Reserves Estimation in Waterflooded Oil Reservoirs
Authors: Nazarenko Maksim
Published: October 2018

The importance of uncertainty quantification and risks assessment in the petroleum industry cannot be overstated. Uncertainty will always be present in production forecasts and reserves estimates. Underestimation of uncertainty when estimating reserves and profitability of projects can lead to poor decision making and disappointment.

Water Displacement Curve (WDC) models are alternative to Decline Curve Analysis (DCS) models in waterflooded oil fields. These curves allow engineers to estimate reserves and forecast production performance in waterflooded oil reservoirs taking into account either liquid or water production. Compared with DCA, WDC models are expected to perform better in forecasting oil production in waterflooded oil fields.

In this study I applied WDC models probabilistically using Bayesian methodology and Markov Chain Monte Carlo (MCMC) stochastic simulation. I also developed a Multimodel approach based on eleven WDC models to quantify uncertainty in production forecasts by assessing differences in matches and forecasts provided by each model.

Both Multimodel and MCMC with WDC models were calibrated and compared to MCMC with DCA method which was recently developed and introduced by Gong et al. (2011). Reliability of the developed methods was assessed using production history of 100 wells from actual waterflooded oil fields. I performed hindcast studies in which I assumed that some fraction of the actual historical production data is known (6, 12, 24 and 36 months) and the rest of the actual production is unknown (5 - 7 years). I then matched the assumed known production fraction of the history and forecasted production to the end of the actual historical period. The cumulative production at the end of the hindcast is compared to the actual cumulative production at this time to test the probabilistic reliability of the methodology when production history is limited. The study showed that both developed methods are well-calibrated probabilistic methods. Also, computer software was developed during this research to make the process of calculations more convenient.
Coupling Low Salinity Water Flooding and Steam Flooding for Sandstone Reservoirs; Low Salinity-Alternating-Steam Flooding (LSASF)
Authors: Al-Saedi Hasan N. , Flori Ralph E. , Alkhamis Mohammed , Brady Patrick V.
Published: October 2018

Low salinity water flooding and steam flooding are two novel combination flooding methods that were combined due to the important role of both methods in increasing oil recovery (especially heavy oil). Low salinity flooding was examined by many laboratory and field works and showed an interesting result. Steam flooding was tested on heavy oil fields and the heavy oil recovery increased by reducing oil viscosity. Although the steam showed an improvement in heavy oil recovery, the density difference between steam and heavy oil raised a problems with steam gravity override, channeling, and early breakthrough. For that reason, we developed the low salinity alternating steam flood (LSASF) in order to gather the benefits of low salinity, reduce oil viscosity by steam, and prevent the steam problems mentioned earlier. The laboratory experiments showed that the optimum scenario was Scenario (3). The shorter the injected cycles, the more oil recovery.

This combination of echnology can solve the steam flooding problems and support the steam by LS water, which has the ability to increase oil recovery.
Determining Effective Mixture Viscosities in Oil-Water Flows for Downhole Oilfield Operations
Authors: Ejim C. E. , Xiao J. J.
Published: October 2018

In downhole oilfield operations that involve pumping oil and water, information on mixture viscosity is important to further understand the performance of the downhole production equipment. This study presents a method for determining the effective absolute viscosity of oil-water mixtures by applying fluid mechanics first principles to data representative of downhole production measurements. Knowledge of effective absolute viscosity in upstream and downstream oilfield operations is essential to extend equipment life and optimize production operations.

A 7-inch, 26 lb/ft pipe and a 3.5-in, 9.20 lb/ft pipe, typically used as casing and tubing, respectively, in field operations were installed in an oil-water flow loop. The volume flow rates during the tests varied from 2000 barrels per day (bpd) to 12,000 bpd, representative of target field production rates. The tests were performed at different inclinations to represent varying well deviation angles. For each oil and water flow rate, the corresponding pressure drop measurements across a fully developed section of the flow were measured. Using fundamental hydraulic relationships, the effective absolute viscosities of the oil-water mixtures were determined.

The results showed that as water cut varied, the effective mixture absolute viscosity also changed, and in some cases substantially. The highest effective absolute viscosity of 500 cP occurred at the mixture flow rate corresponding to 2000 bpd and 40% water cut. In general, mixture flow rates of 2000 bpd and water cuts between 40 and 60% consistently showed the highest effective absolute mixture viscosities, which varied between 160 cP to 500 cP. For water cuts outside the 40% to 60% range, the effective absolute viscosities were about 120 cP and less. The above results indicate that the effective mixture viscosity is about two and close to three orders of magnitude of pure oil and pure water viscosities, respectively. The results also suggest that certain flow rates and water cuts significantly affect the viscosity of oil-water flows. Other results showed that for a given mixture flow rate the effective viscosities were about the same order of magnitude for the different inclinations. This indicates that well deviation angle has minimal or negligible influence on the effective mixture absolute viscosity. From the combined results the technique used in this study provides additional insight to ascertain the effective viscosity of oil-water mixtures during field operations.This study highlights the importance of having the capability to determine the effective absolute viscosity of oil-water mixtures during oilfield production operations. The methodology is simple and has the advantage of easy integration into a flow measurement system. Such systems are beneficial tools for reservoir engineers, production engineers and field operators in general for making appropriate production modifications during operations, to increase asset life and maximize hydrocarbon recovery.
Data Analysis of Lost Circulation Events in the Hartha Formation, Rumaila Field, Iraq
Authors: Al-Hameedi Abo Taleb , Alkinani Husam H. , Dunn-Norman Shari , Flori Ralph E. , Hilgedick Steven A. , Alkhamis Mohammed M. , Alsaba Mortadha T.
Published: October 2018

Lost circulation is a complicated problem to be prevented or combatted during drilling through the Hartha formation. Hence, Mud losses remedies are determined to stop or mitigate losses using remedial methods or to prevent mud losses using proactive measures. Lost circulation events are analyzed in more than 300 wells drilled in the Rumaila field to determine the best ranges for the key drilling parameters, which have the greatest chance of minimizing or prohibiting lost circulation issues.

Key drilling parameters (e.g. MW, ECD, Yp, RPM, SPM, ROP) at the time of each event are extracted along with the lost circulation remedies attempted, and the outcome of those remedies. Practical field information from the Rumaila field and range of sources are reviewed and summarized to develop an integrated methodology and flowchart for handling lost circulation events in this formation. This paper will be an extended work along with previous comprehensive statistical study and sensitivity analysis models about the Hartha formation. In addition, economic evaluation is conducted for partial, severe, and complete losses to obtain the best field procedures.

Proactive approaches are made prior entering the Hartha formation to prevent or mitigate the occurrence of the lost circulation. A broad statistical work, typical drilling fluid properties, and recommended operational drilling parameters are estimated to use during drilling through this formation. Moreover, corrective actions are determined for each type of the mud losses to provide effective remedies, minimize non-productive time, and reduce cost. The best lost circulation strategy to the Hartha formation is concluded and summarized depending on a comprehensive statistical work, the most important courses of the international oil companies, technical papers, textbooks, and economic analysis evaluation to determine the successful remedies for each type of the losses. In addition, engineered solutions and practical techniques have been developed, which will contribute to give a clear image and a coherent understanding in regard this complicated and costly problem in the Hartha formation.

This study will present a typical compilation of information regarding traditional and the latest approaches to the lost circulation control. This work attempts to provide useful guidelines and effective solutions for all situations in terms preventive measures, remedial methods, and analytical economic study. In addition, due to the lack of published studies about the Hartha formation, this work can serve as a substantial resource for drilling through this zone.
Maximizing Oil Production by Using your Available Limited Resources, Case Study from Amal Field
Authors: El-Galil Yehia S. , El-Moniem Mohamed A. , El-Sherif Mamdouh , Khalifa Tarek , El-Fattah Fayad Abd , Ramadan Nasr
Published: October 2018

Production Optimization is often attributed to new technologies, sophisticated algorithms and application of market leading expertise. In Amal, after years of production, our learning is production optimization is more about doing simple things well and getting better at it every day through practice and planning.

In this paper, we will present an example for the capability of using limited resources in offshore fields to maximize oil production for wells suffering from high water production.

The challenge was in one of oil wells, which has been ceased to flow due to high water cut and consequently we deferred around 400 BOPD. To illustrate this point, we will focus on how we can retain the oil production from this well while the ongoing gas lift project is not ready yet. We thought about the integrity between the wells in the same platform by using one of gas wells from gas reservoir as injector to lift the ceased to flow oil well and how we could obtain the gas quantities to be injected into the oil well however the rest will be produced normally from the gas well.

We will share how a loaded well with high water cut was revived through this idea of gas lifting with a higher pressure well, many runs were performed using commercial software of wells modeling and reservoir simulation. We determined the proper rate and WHFP from the gas well to be injected in the oil well to recover that oil and we could improve the well productivity.

As a result, the well has produced over the last ten months and we could maximize the oil production with our limited resources and without any huge gas lift project. Again, this idea helped maintain safe and continuous production from ceased to flow well and we recovered around 110,000 barrels of oil until now and the well still produce.
Rate of Penetration Prediction Using Self-Adaptive Differential Evolution-Artificial Neural Network
Authors: Elkatatny Salaheldin
Published: October 2018

The rate of penetration (ROP) should be optimized during the drilling operation to avoid many problems such as cutting accumulation, pipe sticking, twist off, and to reduce the nonproductive time (NPT). ROP depends on many variables such as; drilling parameters, fluid properties, and formation strength. Previous models of ROP did not include the effect of the change in rock mechanics on the ROP prediction. Several models were developed based on a regression that is limited to the rock type and drilling conditions.

The objective of this paper is to apply the self-adaptive differential evolution technique (SaDE) to optimize the artificial neural network (ANN) variable parameters such as; training function, a number of hidden layers, transferring function and number of neurons in each layer. The optimized SaDE-ANN model will be used to predict the ROP as a function of torque (T), weight on bit (WOB), stand pipe pressure (P), flow rate (Q), the drilling fluid density (D), uniaxial compressive strength (UCS), plastic viscosity (PV), and RPM

The obtained results showed that ROP has a strong function of the drilling parameters; RPM, WOB, T, and horse power (HP). While ROP is a moderate function of UCS. The optimized ANN structure based on SaDE is 5-30-1; where the input layer consists of 5 neurons representing the input parameters; RPM, WOB/D, T/UCS, D/PV, and HP. The hidden layer consists of 30 neurons and the output layer contains one neuron representing the output predicted ROP. The ratio of the training and testing data was 0.6 and 0.4, respectively. The best training function was Bayesian Regularization backpropagation (trainbr) and the best transforming function was Logarithmic sigmoid (logsig). The high accuracy of the developed model confirmed the importance of compiling the drilling fluid properties with the drilling parameters.
A New Approach to Determine the Rheology Parameters for Water-Based Drilling Fluid Using Artificial Neural Network
Authors: Elkatatny Salaheldin , Mousa Tamer , Mahmoud Mohamed
Published: October 2018

Rheological properties play key roles in hydraulic calculations and hole cleaning. Determination of the rheological properties in real time is very important to control the drilling operation and save time. Losing the rheological properties can lead to severe problems such as; pipe sticking, kick and blowout, increase in torque and drag, and hole cleaning issue. Rheological properties can be determine using the rheometer, which required time for measurement and also for cleaning the equipment after use. In the well site, rheological properties are measured twice a day.

The objective of this paper is to develop a new technique to determine the rheological properties (plastic viscosity (PV), apparent viscosity (AV), yield point (YP), and flow behavior index (n)) of KCl water-based drilling fluid using the frequent measurements of the caliper parameters (drilling fluid density (D), Marsh funnel viscosity (MFV) and solid percent). D, MFV, and SV are measured frequently every 15-20 minutes in the well site. Artificial neural network (ANN) was used to build different models for PV, YP, AV, and n based on 3000 field data measurements.

ANN was able to predict the rheological properties on a real time with a high accuracy. Four new empirical correlations were developed to predict PV, AV, YP, and n. The accuracy of these correlations are very high (correlation coefficient (CC) greater than 90% and the average absolute percentage error (AAPE) was less than 6%. The novelty of this technique is the prediction of the rheological properties in real time based on the caliper variables, which will help the drilling engineers to perform a safe drilling operation and eliminate the common drilling problems.
A New Approach to Simulate Near-Miscible Water-Alternating-Gas Injection for Mixed-Wet Reservoirs
Authors: Alzayer Hassan , Sohrabi Mehran
Published: October 2018

The oil recovery factor from oil reservoirs must be increased significantly to meet the ever-increasing demand for energy. Majority of oil reserves worldwide (estimated as 60%) are held in carbonate reservoirs. It is believed that most carbonate reservoirs are mixed-wet to oil wet with high variation in wettability within the reservoir rock. Water-Alternating-Gas (WAG) injection is one of the most applicable EOR techniques known to increase oil recovery factor by 8-20% on top of waterflood alone. To maximize recovery from carbonate reservoirs, numerical simulation is the best available tool to aid with such objective. In this paper, we are presenting a new approach to simulate near-miscible water- alternating-gas injection for mixed-wet reservoirs.

The coreflood experiment used in this study was performed on a 65mD mixed-wet sandstone core sample at 38°C (100°F) and 12.69 MPa (1840 psia) where calculated Interfacial tension (IFT) between gas and oil at these conditions is 0.04 mN/m.

As recorded in the literature, the current simulation capabilities to model WAG injection behaviour is questionable. Some authors suggested that Land’s gas trapping parameter [C] should be variable during the WAG injection process. In this study, we investigated the best way to match the results of WAG injection experiments performed on a mixed-wet core. Matching the full experimental results were not possible without varying gas trapping parameter [C]. However, by updating the gas trapping parameter, based on our suggested procedure, the match between the simulation results and experimental data improved significantly.

This paper highlights the shortcomings of the commercial simulators in modelling WAG injection process. The current WAG hysteresis model can be improved based on the information published in this paper for better WAG injection simulation.
Innovative Approach to Optimize Cleanout Trips Inside Casing for Setting and Retrieving Whipstocks and Running Completion
Authors: Al Fakih Abdulqawi , Pessanha Vinicius , Aldape Alberto Gomez , Famiev Robert , Ahmad Bilal , Khan Tauqeer , Obari Wahid
Published: October 2018

It is considered essential to perform cleanout trips before setting or retrieving specific tools inside casing, such as whipstocks and completion packers. Multiple cleanout trips may be required, e.g., when milling a window in a multilateral well, before setting a whipstock, before retrieving a whipstock, etc. This paper explains how the cleanout trips can be combined with setting and retrieving trips to save time and improve efficiency.

Risk and engineering analysis were performed; the need of new and existing technologies such as high- performance string magnets, casing scrapers and a specialized metal catcher was identified. The data from multiple wells is presented to illustrate the reliability of the optimized practices.

This innovative approach has been implemented in over 50 wells, saving a minimum of two days per lateral in each multilateral well, and up to five days per well based on the number of whipstocks and the completion type; moreover, zero failures were recorded to date. The paper also outlines how the process was further improved by adding larger diameter magnets and scrapers above the liner top, to enhance metal recovery, and reach the theoretical metal weight value expected. This new procedure, also contributed to minimize the completion cleanout trips required for smart completion, from 5 runs to 3 runs per well as average. Finally, the paper discusses the HSE incidents exposure reduction due to the reductions of the number of trips, and highlights future improvement opportunities.
Recommended Practices for Evaluation and Development of Shale Gas/Oil Reservoirs Over the Asset Life Cycle: Data-Driven Solutions
Authors: Kennedy Robert , Minhas Haq
Published: October 2018

After drilling and completing over 200,000 shale wells in North America and about 3,000 more wells internationally, the industry still has more to learn in order to totally optimize hydraulic fracturing, and maximize productivity and recovery from these reservoirs. Although some, actual full-field case histories have been documented, one company has developed a set of Data-Driven Solutions (Recommended Practices) to evaluate and develop shale gas/oil (source rock) reservoirs to attain optimum producing rates and ultimate recovery.

Combined industry and company experience including our technologies, techniques, analyses methods and workflows for shale gas/oil plays led to defining these Data-Driven Solutions (Recommended Practices): Twelve Steps to Success for each of the shale gas/oil Asset Life Cycle phases. The Asset Life Cycle approach with the five phases of Exploration, Appraisal, Development, Production and Rejuvenation, was first introduced to the industry in earlier SPE papers. This approach follows three key points: 1. Begin with a complete understanding of the reservoir, 2. Use a multidiscipline and integrated approach across each Life Cycle phase and 3. Effectively use modern technology.

The Twelve Data-Driven Solutions were developed based an integrated approach for employing them across their respective life cycle phases. The solutions begin with 1. Identify and Evaluate Resource Potential and end with 12. Refrac to Improve Ultimate Recovery. Solutions are not linear, nor do they always cover only one life cycle phase. Each Step to Success is discussed by providing an Overview, Challenges, Value and specific Solutions (which include Recommended Practices).

All shales are not the same; geology, mineralogy, geochemistry varies even in the same basin/play. However; evaluation and development techniques involving Data-driven Solutions/Recommended Practices can apply to any shale (source rock) reservoir in the world.
Trialtest of Wireless Devices at Haradh Well #210
Authors: Alsaedi Abdullah
Published: October 2018

Novel distributed signal processing algorithms, energy-efficient medium access control and fault-tolerant routing protocols, self-organizing and self-healing sensor network mechanisms, etc. have contributed immensely to the growth of these technologies. Recent developments like Wireless HART and ISA SP100.11a have provided an exceptional boost to this novel technology. In terms of user’s perspective, significant paradigm shift can be observed from traditional wired technologies to upcoming wireless technologies.

The key market driver for performing this field trial was to reduce the damage to field cabling and well head instrumentation during the removal / reinstallation before and after workover / rig entry. With wireless instrumentation; field cabling will be eliminated, thus making it easy to remove and re-instate field instruments during workover / rig entry activities. Another major benefit for using wireless instrumentation was the turn-around time for re-flowing wells will be much shorter as wireless instrumentation could be re-installed and re-commissioned quicker.

The technology driver identified that would enable the achievement of the above objective was wireless technology.

Other motivations to use wireless instruments in a wellhead environment are as follows:- Reduced Costs. Through the elimination of cables, wireless technology greatly reduces the CAPEX associated with instrumentation.Improved Flexibility. Mobile instruments allow devices to be positioned, both temporarily and spatially, as required.
A New Methodology to Determine the Reasonable Buildup Test Time for Tight Oil Wells: A Case Study From the Ordos Basin
Authors: Chu Hongyang , Liao Xinwei , Wang Shenghua , Yuan Lijia , Yuan Zhou , Zou Jiandong , Mu Lingyu , Chen Haoshu
Published: October 2018

In this paper, a new methodology to determine the reasonable buildup test time is derived. The methodology has the ability to determine the starting time of quasi-radial flow (STQF) with considering wellbore storage coefficient, permeability, skin factor, reservoir thickness, and oil viscosity. The curves of pressure derivative flatten out but don’t really enter into radial flow stage at the STQF. The STQF is determined with the use of the constraint for the slope of the pressure derivative curve. Using sensitivity analysis, we build the relationship between the dimensionless factors and the dimensionless STQF. Then the STQF is identified as a reasonable buildup time. We finally verify the methodology with the field pressure test data of typical tight oil wells from the Ordos Basin.

The results show that our methodology is more practical and allows us to accurately estimate the STQF, without any influence on the interpretation results. The parameters all have a significant impact on the STQF including the wellbore storage coefficient, permeability, skin factor, reservoir thickness, oil viscosity, and the wellbore storage coefficient is what affects the STQF the most. In order to reduce the number of those key factors, we use the approach of non-dimensional treatment and obtain the relationship between the dimensionless factors and the dimensionless STQF. The results show that the relationship between the dimensionless STQF and skin factor is power function. With the increase of the dimensionless wellbore storage coefficient, STQF performs a second order polynomial function. Furthermore, a formula to determine the STQF is obtained and the two coefficients of the equation respectively represent the peak of the pressure derivative curve and the occurrence time of 0.5 straight line referred to pseudo-radial flow. We analyze plenty of pressure test data of typical tight oil wells from the Ordos Basin, and find that the two coefficients are fixed on 75.5071 and 0.2048, respectively. The results are very meaningful to determine the STQF of typical tight oil wells.
Application of Nanoparticles in Improving Rheological Properties of Water Based Drilling Fluids
Authors: Al-saba M. T. , Al Fadhli A. , Marafi A. , Hussain A. , Bander F. , Al Dushaishi M. F.
Published: October 2018

Nanoparticles (NPs) have been recently used for different application in the oil and gas industry. Nanoparticles have proven their effectiveness for different applications including; drilling fluids, wellbore strengthening, and enhanced oil recovery (EOR).

In this paper, different types of nanoparticles including Aluminum Oxide, Copper Oxide, and Magnesium Oxide were evaluated at two different concentrations. The main objective of this research is to investigate the effect of adding nanoparticles on the rheological properties of water-based drilling fluid. A simple 7% bentonite water-based mud was used in this study as a reference point. The rheological properties including plastic viscosity, yield point, and gel strength were evaluated at both; standard test temperature of 120°F and room temperature to understand the effect of nanoparticles on the rheological properties. In addition, the filtration characteristics were investigated using both; the standard API filter press at low-pressure low-temperature (LPLT) as well as the high-pressure-high- temperature (HPHT) filter press at 500 psi and 250°F.

The results showed that plastic viscosity was reduced by 50% when NPs were added compared to the reference point. The yield point was improved by 84%, 121%, and 231% for 0.5%Vol Copper Oxide, Aluminum Oxide, and Magnesium Oxide, respectively. In addition, the 10 seconds gel strength was increased up to 95%. A reduction in the fluid loss up to 30% was observed at LPLT conditions. However, the filtration characteristics were negatively affected at HPHT.

Based on the results, there is a good potential for using the above-mentioned nanoparticles to improve the rheological properties, especially the low-end rheology while maintaining low plastic viscosities, which in turns results in a better hole cleaning and more control over the equivalent circulation density.
An Intelligent Functional Network Approach to Develop Mathematical Model to Predict Sonic Waves Travel Time for Carbonate Rocks
Authors: Tariq Zeeshan
Published: October 2018

Compressional and shear wave travel times are used to determine rock dynamic elastic parameters. Elastic parameters are used in obtaining the in-situ stresses of the rock, calculate safe mud weight, avoid wellbore instability problems and design optimum hydraulic fracture geometry. Often overlooked, weakness in the calculation of elastic parameters studies is a major cause of well-bore problems and unsuccessful well stimulation jobs. In well logging, compressional and shear wave travel time logs are one of the common logs to be recoreded in almost every formation. In cases when the sonic logs are missing, these logs values are estimated using empirical correlations. So far, none of the available models or correlations are universally accepted by log analysts since every model estimates the log values significantly different from the others, which may be suitable for one reservoir and not for other. As a result, inaccurate values can potentially raise major concerns throughout the life of the well. The error in sonic log values affects the elastic parameters, which can result in either underestimation or overestimation of the in-situ stresses.

So, the objective of this paper is to develop robust empirical model for compressional and shear wave travel times using different functional network approach. For this purpose, well logs data, such as; gamma ray, bulk density, and neutron porosity were collected from different wells which are drilled in a carbonate formation. Functional network tool is used to develop mathematical model for compressional and shear wave travel times. This AI model were trained on the data of several well and validated on the remaining wells. Different types of functional network tools were studied, namely; forward selection model FNFSM, backward elimination model FNBEM, forward backward model FNFBM and backward forward model FNBFM. Then based on correlation coefficient R and average absolute percentage error AAPE, a comparison was made and the one which performed better was selected for prediction of sonic wave transit times.

The novelty of this work is that for the first time, the explicit mathematical model is developed from functional network to estimate compressional and shear wave travel time. The mathematical model developed from the functional network is easier to implement. The new model will eliminate the need to use expensive software to run AI model. The new model for sonic transit time significantly reduces the uncertainties in calculating the sonic transit times in carbonate formation.
A New Approach to Characterize CO2 Flooding Utilizing Artificial Intelligence Techniques
Authors: Hassan Amjed , Elkatatny Salaheldin , Mahmoud Mohamed , Abdulraheem Abdulazeez
Published: October 2018

The use of carbon dioxide in miscible flooding has been considered as one of the most effective techniques for enhancing oil production. The flooding efficiency is an extreme function of the minimum miscibility pressure (MMP), therefore, searching for a quick and rigorous method to determine MMP is highly needed. Slim tube experiments are normally used to measure the minimum miscibility pressure. However, such experiments are time-consuming and very costly. Different correlations have been developed to determine the MMP during CO2 injection process. These empirical equations are not widely applicable and might produce severe estimation errors, because they are developed based on limited experimental results.

This paper proposes a new technique to evaluate the CO2 flooding and minimize the uncertainties of using numerical approaches. The objective of this work is developing a reliable model to predict the MMP during CO2 flooding. Actual case studies for flooding heterogeneous and anisotropic reservoir were utilized to generate the MMP model, more than 140 data points were used to construct and evaluate the proposed model. Several artificial intelligence techniques were studied to estimate the CO2−MMP for a wider range of conditions. The developed models investigate the effect of API gravity, fluid composition, and injected gas composition on the performance of CO2 flooding operation.

The CO2−MMP was estimated using different artificial intelligence techniques including; radial basis function network, artificial neural network, generalized neural network and adaptive neuro-fuzzy inference system. The wellbore condition and reservoir parameters were used to provide an accurate and quick prediction for the flooding performance. Sensitivity study was conducted to optimize the model parameters. Then, the optimized artificial neural network model was utilized to extract an empirical equation.

The developed equation was verified using actual field data an acceptable average absolute percentage error (AAPE) of 6.6% was obtained. In addition, the developed CO2−MMP model was compared with different determination approaches. It is found that, the proposed technique outperforms the current CO2−MMP models. This work would afford an effective approach to characterize the CO2−flooding for complex reservoirs, also improve the prediction performance of commercial software, which leads to a better production management in the particular CO2−operations.
Energized Fluids for Upstream Production Enhancement: A Review
Authors: Karadkar Prasad , Bataweel Mohammed , Bulekbay Aslan , Alshaikh Abrar A.
Published: October 2018

Energized fluids are defined as fluids with one or more compressible gas components, such as CO2, N2, or any combination of gases, dispersed in a small volume of liquid. Generally, these fluids offer an attractive alternative to conventional stimulation fluids in many cases such as low reservoir pressure, water-sensitive formations, and/or the need for shorten flowback period. Energized fluids have many challenges such as low stability at high temperature, high friction pressure during pumping, corrosion in the case of using CO2, and the need for specialized surface pumping equipment. The objective of this paper is to describe the typical components of energized fluids and their effect on the fluid performance. Also, lab testing methods used to evaluate energized fluids performance will be discussed in detail.

Foam is a class of energized fluid used for different applications including acidizing, hydraulic fracturing, and fluid diversion. For each application, foam should have a minimum acceptable value of viscosity, stability, and/or fluid compatibility. Those values were reviewed from literature and categorized based on reservoir conditions. Also, different rheological models are analyzed to understand foam flow behavior in both tubing and porous media. Finally, the mechanism of foam transport in porous media is reviewed in this report, which gives insight into foam stability and propagation.

The most common application of nitrogen is in artificial lifting, while supercritical CO2 is proposed for condensate banking removal. Selection of the right surfactant, like alpha olefin sulfonates, which are thermally more stable than alkyl ether sulfates, is crucial while designing foam treatment, as they produce the most persistent foams at high salinity and elevated temperatures in the presence of synthetic and crude oils. Currently available foam-based fracturing fluid systems in the industry have temperature limitations to 300°F. The crosslinked gelled foam has a better temperature range than the viscoelastic foam fluid system, whereas non-crosslinked biopolymer-based foam fluid showed better proppant pack cleanup characteristics. In a recent report, the addition of 0.1% silica nanoparticles along with cationic surfactant was shown to enhance CO2 foam stability by 13 hours. In this review, all these aspects of energized fluids are well reported from literature.

In this paper, we discuss findings from different lab testing and field demonstration of energized fluids. Compositional modelling for hydraulic fracturing with energized fluids is also reviewed to add insight on fracture geometry estimation. This paper provides guidelines and recommendations for selecting the right energized fluids for successful stimulation treatment.
Deep Gas Drilling Optimization in the lateral section in middle east
Authors: Balka Muhammad Sarfraz , Ghazzawi Ayman , Cui Shuai , Fuenmayor Luis
Published: October 2018

Deep gas drilling in middle east is very challenging and this becomes even a bigger challenge when the wells are drilled horizontally and in 5 7/8" hole size. Two types of rocks are drilled across different field. First one is khuff formation in upper Permian and second is Unayzah formation in lower Permian. Both formation have different challenges, this paper is focused on optimization in Khuff reservoir where the service provider is involved. Deep gas drilling optimization was based adding new technical experts and peer reviewing the learning in place and implementing the new best practices. Historically plenty of efforts were made for performance improvement, however still there was and is room for continuous improvement. All the efforts were based on the implementation technologies, pushing the technology to limit, improving the knowledge of drilling environment and continuous changes in the drilling strategies. After reviewing the following changes were recommended and are in place across different fields

Connection practice - reducing the overall time by minimizing the reaming time. BHA stabilization – changing the stabilizer position and maximum OD of the stabilizer. Performance comparison between Standalone and powered RSS and implementation. No Wiper Trip till TD, Trip only required for BHA change or other operational requirement.

After implementation, ratio for number of wells have been drilled in one run is increasing. Drilling parameters implementation has resulted in consistent ROP and BHA optimization has resulted in reduction in LIH year on year.
An innovative Approach Using Micro-Emulsion Treatment Techniques to Remove Sandstone Formation Damage: Lab Testing and Field Application
Authors: Almajid Hussain A. , Shuwaikhat Hisham I. , Abou Zeid Saleh M. , Addagalla Ajay Kumar
Published: October 2018

Matrix stimulation treatments executed with coiled tubing (CT) face various challenges in terms of design, execution, and evaluation. The design phase typically relies on information that is usually poorly known (e.g., extent of damage). Treatment pumping schedules and fluid concentrations are often determined based on previous experience and accepted local practices. In most cases, tools like high pressure differential jetting nozzles are used to provide deeper penetration and lower break-out pressures. The depths at which those tools are operated usually depend on a prior log interpretation. Finally, treatment evaluation is typically limited to the comparison of pre and post-stimulation wellhead pressures and rates.

Over the past decade, numerous sandstone stimulation treatment alternatives have been introduced to the industry to address formation damage related issues. Yet, the same question often remains: has the design been effectively executed and was the intervention successful?

A CT downhole measurement system which consists of downhole gauges providing real-time data of pressure, temperature, gamma ray, and casing collar locator, has proven to be a game-changing technology with respect to treatment execution, improving both intervention efficiency and safety. The downhole measurements, along with the possibility to acquire distributed temperature & pressure (TPD) surveys, have also shown to be the most effective solution for treatment evaluation to date.

This paper will describe a case study of how the system can be used to optimize the acidizing treatment of damaged wells and ensure its effective stimulation. It will also demonstrate how the real-time data analysis during the intervention process can result in high success rate of such intervention jobs.