bluuebunny/crossref_metadata_2025 huggingface dataset:
Upscaling of Microgel Treatment in Fractured Reservoirs: Experimental and Simulation Investigation
Authors: Alhuraishawy Ali K. , Wei Mingzhen , Bai Baojun , Almohsin Ayman
Published: October 2018

Excess water production through fractured reservoirs is one of the most serious problem for sweep efficiency and oil recovery factor. Gel treatment have been widely used to plug the fractures and reduce excess water production to improve macroscopic sweep efficiency. Field studies showed that gel treatment can be successfully applied in mature oilfield and fracture reservoirs to reduce water production and improved oil recovery factor. The objective of this paper is to understand the preformed particle gel (PPG) propagation through fractures by conducting laboratory work and upscaling these data to filed scale to investigate which parameters can be more affected gel treatment.

The semi-transparent fracture model was made of oil-wet carbonate core and acrylic plates with 1.5 mm fracture width. Seawater was used for brine flooding and to prepare the swollen gel. The experimental results showed that the preformed particle gel improved the oil recovery by 12% with 20% water cut reduction. The experimental results were history-matched using UTGEL simulator and an excellent agreement between lab data and simulation data was achieved. The simulation results of the filed scale indicated that the PPG concentration and PPG treatment timing are the main PPG design variables and the conformance control improved when PPG concentration increased and when PPG treatment applied early. Upscaling the laboratory results to filed scale provide a deeper understanding of PPG treatment and can investigate the effect of PPG concentration for PPG application in fractured reservoirs.
Laboratory Screening Tests to Further Characterize Low-Salinity Waterflooding in Low-Permeability Sandstone Reservoir
Authors: Alhuraishawy Ali K. , Almansour Abdullah , Bai Baojun , Wei Mingzhen , Imqam Abdulmohsin , Geng Jiaming
Published: October 2018

The latest oil price decline simply increases the demand for enhanced oil recovery (EOR) and pushes research developers to keep improvements in oil recovery. The goal is always to recover as much oil as possible at the lowest possible cost. Low-salinity water flooding (LSWF) is an EOR method that operates at a lower cost than other EOR methods, which makes it a preferred area of interest for oil industry economists, who continue to call for EOR costs to come down. The objective of this study was to test the ability of low-salinity waterflooding to improve oil recovery from low permeability sandstone reservoirs. Four types of tests were conducted: imbibition, interfacial, core flooding, and zeta potential tests. Three key factors were studied: salinity of the injected water, type of salt, and aging time. Their influence on the amount of oil recovery, stabilized injection pressure, pH, and permeability reduction was determined. Berea sandstone was used in all experiments. Sodium chloride (NaCl) and calcium chloride (CaCl2) were used to prepare the brine. The imbibition test and core flooding results showed that the oil recovery increased as brine concentration decreased for both sodium chloride and calcium chloride. Sodium chloride resulted in higher oil recovery than calcium chloride at a certain salinity in both imbibition and core flooding tests. The oil recovery factor results during the second water flooding cycle (after aging for 24 hrs.) showed more oil recovered during low salinity waterflooding. The stabilized inaction pressure was higher for CaCl2 than NaCl injection at certain flow rate and brine concentrations. Effluent pH values became more basic during low salinity water flooding for both sodium and calcium chloride. The zeta potential results showed that decreasing the salinity of injected water resulted in a decrease of the zeta potential value for both injection cycles, before and after aging for 24 hours. Results also imply Low- salinity water flooding redistributes the flowing paths by releasing sand particles and some fine minerals causing the flow path to narrow. Thus, low salinity water flooding can create a new streamline (fluid flow diversion) and improve both displacement and sweep efficiency.
Effects of Injection Parameters on Foam Rheology in Vertical Wells
Authors: Sinde Seydou
Published: October 2018

Foam underbalanced drilling is the use of the entrapped gas bubbles within the continuous liquid fluid as the drilling medium to overcome one the most challenging drilling problems: lost circulation, regardless of its various reasons. It is also used to improve the reservoir productivity by preventing the formation damage and the skin factor. The complexity of foam composition as a drilling fluid is by the fact that it is affected by both constituent ingredients: liquid and gas as well as the downhole conditions. The combination between compressible gas and incompressible liquid in addition to the intrusion of annular cuttings and influx fluids necessitates better understanding of the mechanism of the hydrodynamic flow of the three-phase. One of the first fundamental steps in achieving that is to intensively conduct the experimental and analytical studies of foam rheology. A hydraulic model, based on the recent experimental and analytical conclusions, was developed not only for better studying foam rheology, but also for analyzing the exhaustive foam drilling operation from the injection lines till the cuttings removal on the surface. In order to simplify the use of the complex mathematical equations and iterative procedures, the programming language VISUAL BASIC has been used and implemented for the modeling. For the rheological study, results concluded the dependence of foam hydraulics, primarily, on rheology. The results also revealed the influence of the rheological properties by drilling parameters such as injection pressure, liquid and gas rates, rate of penetration (ROP), and surface back-pressure. If the increase of injection pressure acts to decrease the flow power index (n) and Reynolds number (NRe), it, in contrast, increases the flow consistency index (k) and friction factor (FF). Gas injection opposes the effects of the injection pressure, whereas liquid injection has variable effects depending on the nature and amount of the addition.
A Comprehensive Review of Differential Sticking, Spotting Fluids, and the Current Testing and Evaluation Methods
Authors: Alshaikh Abrar A. , Amanullah Md.
Published: October 2018

Differential-pressure pipe sticking is one of the biggest problems encountered during drilling and also one of the leading causes of high nonproductive time. It usually occurs in permeable or depleted formations due to the cession of drillstring movement to connect a new pipe, make a trip, overcome a drilling problem, etc. As the drillstring becomes stationary, it gets embedded into the filter cake because of the pressure difference between the formation and the wellbore, and also due to the high filtration in the presence of a high permeable zone. The sticking bonds created in the pipe/filter-cake interface due to the combined action of adhesive and cohesive forces acting in the vicinity of the sticking zone prevent any movement of the drillstring in the wellbore. Therefore, the driller is unable to rotate or reciprocate it without releasing it by mechanical or chemo-mechanical actions.

The industry uses various spotting fluids to recover a differentially stuck pipe as soon as possible as any delay may lead to an increasingly complicated rescue operation with the possibility of abandoning the well in extreme conditions. Therefore, the selection of a suitable spotting fluid that is compatible with a particular mud composition is very important to improve the success rate of a rescue operation. Use of an incompatible spotting fluid, instead of helping in recovering a stuck pipe, may lead to disastrous conditions. There are other factors that can aggravate the recovery of a stuck pipe significantly. Therefore, understanding the root causes of this problem, the conditions that lead to this problem, and the working mechanism of various spotting fluids along with their application domains, are very important for prevention, remediation, and improving the ease of recovery of stuck pipe.

This paper provides a comprehensive review of pipe sticking problems with emphasis on differential pipe sticking encountered while drilling and the various spotting fluids used to recover a stuck pipe. The paper further discusses the current testing and evaluation methods used for screening, testing, and evaluating spotting fluids to select the superior and reject the inferior along with their advantages and disadvantages. Finally, a recommendation is made to improve the testing and evaluation method and overcome the limitations of conventional methods and apparatus.
Induction Versus Permanent Magnet Motors for ESP Applications
Authors: Xiao J. J. , Lastra Rafael
Published: October 2018

This paper provides an overview comparing Induction Motors (IM) and Permanent Magnet Motors (PMM) for Electric Submersible Pump (ESP) applications. What are the design differences and how the performances of the two types of motors are stacked against each other? What are the advantage and unique applications of PMMs? Why and how are PMMs controlled differently from IMs? Are there safety aspects that field engineers need to be aware of with PMMs? These questions will be addressed in the paper.

The information presented includes literature review and latest R&D results. It covers operating principles of IM and PMM, selection of permanent magnet materials, operating frequency, stator windings and magnetic poles.

PMMs offer better efficiency, higher power factor performance and compactness. Ideal applications include slim well applications, through-tubing rigless deployment, Y-tool completion and Electric Submersible Progressive cavity Pump (ESPCP). The paper will also shed some light on why conventional IMs cannot be used to drive ESPCPs directly without speed reduction gearboxes.

It is very likely that the use of PMM will increase for ESP applications in the near future and this will require engineers to acquire a basic understanding of this technology. A high level comparison between IM and PMM is missing in the ESP industry and this paper fills the gap. PMMs need to be operated with a different type of control for Variable Speed Drive (VSD) and require matching transformers for high frequency applications. The paper also intends to highlight the safety aspects of PMMs in shop and field handling.
Evaluation of EOR LS Water Flooding in Sandstone: Eliminate the Role of Clay
Authors: Al-Saedi Hasan N. , Almansour Abdullah , Flori Ralph E. , Brady Patrick V.
Published: October 2018

Recently, we proposed a chemical mechanism for the role of clay in sandstone during low salinity water (LS water) flooding using acetate to simulate the oil-bound carboxylic acids with the reservoir (Al-Saedi and Brady 2018). In this study, we propose to quantify the control of mineral composition and water chemistry on water/rock interactions by using oil during low salinity waterflooding of spatially heterogeneous sandstone porous media. A sandstone core and free-clay sand core were prepared in chromatography columns and were water flooded sequentially with high-low salinity water at the reservoir temperature of 90ºC. Brine with high salinity (100,000) ppm was injected to simulate formation water. Then, Inflow LS water (1100) ppm. One of the columns only contains quartz, to investigate the role of the clay in the mechanism of LS water enhanced oil recovery (EOR). The other columns contained quartz and different quantities of clays. The results showed that during flooding, the free-clay column with LS water the oil recovery from the quartz column was as great as that of the clay-containing cores. On the other hand, our previous investigation showed a noteworthy desorption of Ca2+ from the free-clay core surface. That indicates further RCOO- detachment in the absence of clay. The pH also increased significantly during LS water flooding for the free-clay column.
Predictive Data Mining Techniques for Mud Losses Mitigation
Authors: Al-Hameedi Abo Taleb , Alkinani Husam H. , Dunn-Norman Shari , Flori Ralph E. , Hilgedick Steven A. , Alkhamis Mohammed M. , Alshawi Yousif Q. , Al-Maliki Madhi A. , Alsaba Mortadha T.
Published: October 2018

Wells drilled in the Rumaila field are highly susceptible to lost circulation problems when drilling through the Hartha formation. This paper presents a comprehensive statistical work and sensitivity analysis models of the lost circulation events for more than 300 wells. Moreover, this study will demonstrate an integrated analysis regarding the most significant drilling parameters, which have a pivotal impact on the lost circulation to provide the greatest chance of mitigating or avoiding lost circulation in the Hartha formation.

Lost circulation events are extracted from daily drilling reports, final reports, and technical reports. Key drilling parameters are analyzed using statistical software to understand the relationship between the mud losses and various drilling parameters such as MW, ECD, Yp, ROP, SPM, RPM, WOB, flow rate, and bit nozzles. The sensitivity analysis is conducted to examine the impact of each parameter in all models. In addition, variance inflation factor (VIF) method is used to test for the multicollinearity phenomena in each model to maximize the accuracy and to obtain a solid mathematical model.

The volume loss model is conducted to predict lost circulation in the Hartha formation. As a proactive action, this model can be used to estimate the volume loss prior drilling the Hartha formation. Observations that have been made from the volume loss model are MW, ECD, and Yp have a significant impact on lost circulation respectively; however, SPM, RPM, and ROP have a minor effect on the volume loss model. Equivalent circulation density (ECD) model is obtained to estimate ECD in the Hartha formation, and from this model can be deduced that MW, ROP, and Q have a significant impact on ECD respectively; nevertheless, RPM and Yp have a minor impact on the ECD. The rate of penetration model is made to estimate ROP in the Hatha formation. It is concluded that WOB, SPM, and RPM have a significant impact on the ROP respectively, but MW, ECD, and Yp have a minor influence on the ROP. In addition, engineering solutions are developed to give a clear image regarding lost circulation, and it will provide a unique statistical study and coherent sensitivity analysis of all factors which have an essential or a small impact on this issue.

Due to the lack of published studies for this formation, this study will provide a unique understanding for lost circulation events, drilling fluid properties, and operational drilling parameters, which have a prominent or a minor impact on the mud losses issue. Lost circulation will be illustrated in terms of causes, consequences, recommendations, and guidelines to reduce or avoid unwanted losses. In addition, this work can serve as a practical resource for drilling through the Hartha formation.
Introduction of a Thermal Model to Analyze Pressure-Falloff Data Leads to an Accurate Pressure-Transient Analysis and a Detailed Thermal Profile of the Water Bank in an Oil Reservoir
Authors: Akresh Saud A. , Alodah Meshari D. , Guerrero Rodolfo J. , Rahman N. M.
Published: October 2018

Water injection into oil reservoirs is widely used practice to support oil production by maintaining the reservoir pressure within a desirable range to avoid a decline in reservoir pressure. Frequent monitoring of the water injectivity in the injection wells are very crucial to ensure meeting injection targets for an optimum level of reservoir management. Therefore, transient tests on water injection wells are an essential component in the data acquisition program of oil fields as these reveal important dynamic information about the wellbore condition and the reservoir characteristics. Usually, surface water is used for injection where the contrast in temperatures between the injected water (relatively colder) and the oil reservoir which is deep in the ground (hotter) creates a progressive colder-water bank inside the reservoir. Such a colder bank would have an effect on the injectivity of the well. Using traditional models without considering the thermal effect might result in underestimating or overestimating both reservoir flow capacity and skin damage.

In this research, we will use a thermal model to study the pressure behavior during injection and falloff periods and observe the development of a colder-water front in which its size inside the reservoir will be investigated varying different parameters, such as duration of injection history, injection rate, and reservoir permeability. In addition, we will demonstrate the impact of the cold-water front on the injectivity.
Study of OBM Invasion on NMR Logging - Mechanisms and Applications
Authors: Hursan Gabor , Ma Shouxiang Mark , Valori Andrea , Sauerer Bastian
Published: October 2018

Due to the shallow depth of investigation of logging tools such as Nuclear Magnetic Resonance (NMR), the signal interpretation of the flushed zone must be performed carefully. Understanding invasion effects on the logs is an important prerequisite for any petrophysical evaluation. While it is relatively easier to evaluate and correct for the effect of filtrate invasion in basic logs, such as triple combo, special care must be taken for advanced logging techniques such as NMR. For example, it is generally assumed that the volume of remaining wetting fluid in the flushed zone equals to the volume of micropores that do not contribute to flow when the well is produced. The amount of these immobile fluids is estimated using the NMR bound fluid log, a key input for the prediction of rock quality and well performance, especially in complex clastic and carbonate pore systems. In certain formations, NMR bound fluid logs exhibit some differences between adjacent wells drilled with oil-based (OBM) and water-based muds (WBM). This paper summarizes the lessons learnt from a laboratory NMR study of oil-based mud filtrate (OBMF) invasion as a function of rock mineralogy and microstructure, mud chemistry and displacement/flow pressure.

In this work, we studied the effect of a commercial surfactant usually added in OBM formulations. We investigated the effect of different surfactant concentrations on the fluid-fluid interfacial tension (IFT) properties and on the fluid-solid interaction properties, using contact angle measurements on both sandstone and carbonate model surfaces. Furthermore, we investigated the effect of the additive on the capillary pressure properties and remaining water saturations on sandstone and carbonate rocks. To maximize the generality of the results we used two very different driving mechanisms for the fluid displacement: centrifuge and flow-through.

The data showed that carbonate and clastic rocks behaved differently over a wide range of flow mechanisms and water saturations, proving that mineralogy plays a crucial role in the fluid displacement. Under the measurement uncertainties, the irreducible water saturation, however, remained constant regardless of the OBMF composition or driving mechanism.

We showed how sandstone and carbonate rocks behave in respect to wettability alteration due to a surfactant used in OBM formulations. The systematic difference, whatever the driving mechanism is, strongly suggests that the differences in NMR responses between sandstone and carbonate originate from chemical composition and surface properties rather than microstructural differences between sandstone and carbonate rocks.
BTKr_cor Methodology Provides an Improved Approach for Numerical Simulation of Vertical Water Segregation in Grids with Large Aspect Ratios
Authors: Kayode Babatope O. , Lyngra Stig
Published: October 2018

Vertical segregation of water is defined as the tendency of water to slump downwards in a vertical sense while undergoing a lateral/areal displacement. In reality, this phenomenon is driven by the density difference between reservoir fluids (oil, water) as well as the reservoir’s vertical permeability heterogeneity. If water is injected at one end of a hypothetical thick and homogeneous sand, the injected water would advance laterally and slump vertically as described by the 1-D Buckley-Leverette (BL) mathematical model. Aspect ratio is defined as the ratio of a grid’s lateral size to its thickness (Dx/Dz). There is the usual constraint to keep Dz as small as possible to allow the description of fine vertical heterogeneities that may be important for flow modeling, there is also the constraint to make Dx large enough to ensure a manageable total number of grids that available computational resources can handle. These constraints lead towards an increasing simulation grid aspect ratio. The purpose of this paper is to demonstrate the impact of increasing aspect ratio on the simulation of vertical segregation of water and present an improved methodology based on BTKr_cor (Kayode et.al 2017) for modelling of vertical oil- water segregation in numerical reservoir simulation. Simulation results from synthetic reservoir model cases are used.

The base-case scenario contains a hypothetical 5-spot injection pattern with 1200 feet injector-producer distance. The wells are placed in a fine-scale grid with block dimensions of 5ft x 5ft x 1ft. After one year of water injection, the simulated saturation-depth profile around the water injector was found to compare favorably with the analytical BL profile. The study included sensitivities varying (i) vertical (kv) / horizontal (kh) permeability ratio, (ii) grid-size (iii) introduction of permeability heterogeneities and (iv) the application of BTKr_cor relative permeability scaling (Kayode et.al 2017). The impact these parameters have on the simulated vertical water segregation are presented.

Simulation results demonstrate that with increasing aspect ratio, the vertical water segregation becomes more pronounced than shown by the fine-scale base case results. The use of low kv/kh values to reduce vertical segregation in large simulation grids resulted in a mismatch of up to 10 units of remaining oil saturation around the injectors. It was however found that regardless of grid size and permeability heterogeneity, the use of the BTkr_cor approach shows the best match with fine grid simulation results.

The methodology described in this publication allows improved numerical simulation of vertical segregation while respecting observed kv/kh ratio from sources like pressure transient analysis (PTA), core data, and vertical interference tests (VIT).
New Formulations for the Control of Iron Sulfide Deposits in Oil Production Facilities
Authors: Jawish M. W , Suleiman R. , Wang Q. , Chen T. , Shen S. W.
Published: October 2018

Tetrakis(hydroxymethyl)phosphonium Sulfate (THPS), an environmental friendly biocide, is gaining more interest as a dissolver to control iron sulfide (FeS) precipitation in oilfield production systems. In previous works, combinations of THPS and different additives, such as ammonium chloride, chelating agents or organic phosphonates, were examined for the synergistic effects of FeS scale dissolution under room and high temperatures. It was found that THPS and ammonium ion can create a purple-colored complex which can significantly improve the FeS dissolution. Studies also indicated that the synergistic effect of ammonium chloride was largely attributed to pH decrease. As a result, the corrosivity of THPS solution to metallurgy was increased. In this work, new formulations based on THPS is introduced. Chloride ions were substituted with different organic compounds. The dissolution rate of analytical grade FeS solid and carbon steel corrosion were investigated at different temperatures. The chemical composition of the undissolved FeS solid and the THPS-Amine-Iron complex structure were analyzed for the most effective dissolver formulations. The efficiency of new formulations was further evaluated using field scale samples collected from water injection pipeline and a sour gas well, and the structures of the FeS scale before and after dissolver treatment were studied to reveal the mechanism of dissolution.
A Novel Superfine Fibrous Lost Circulation Material derived from Date Tree for Seepage Loss control
Authors: Ramasamy Jothibasu , Amanullah Md
Published: October 2018

Lost circulation is one of the major challenges faced by oil and gas industries around the globe causing significant amount of drilling non-productive time. Loss of drilling fluid could lead to additional drilling problems such as stuck pipe, borehole instability or a potential well control event. There are different types of materials such as fibrous, flake type, particulate, etc. are available in the industry to combat loss of circulation. Superfine fibrous type of materials are used to mitigate seepage losses. These fibrous materials are derived from wood fibers. The objective of this paper is to develop an eco-friendly, biodegradable superfine fibrous lost circulation materials from date tree fibers for addressing seepage type losses. We have developed a novel fibrous lost circulation material (Arc Fiber SF) using date tree waste available locally as the raw material. Small scale crushing and grinding process were used for lab scale sample preparation. A suitable particle size distribution of the superfine materials required for seepage loss control have been achieved by sieving process. In order to demonstrate the seepage loss control ability of the superfine materials, low sold non-dispersive KCl-polymer samples have been formulated incorporating superfine fibrous materials and for comparison, a mud formulated using commercially available seepage loss control material. HPHT filtration control experiments carried out at 212 °F and 500 psi also proved the ability of these materials in reducing the amount of filtrate. This observation suggests that the date tree fiber based LCM is a suitable alternative to commercial fibrous LCMs used in the industry. The in-house product Arc Fiber SF has been developed by simple grinding and sieving process of date tree waste and has the potential to replace the commercial equivalents.
Cement Failure Modeling for High Pressure High Temperature Wells: Case Studies
Authors: Sanuade Oluseun A. , Elkatatny Salaheldin
Published: October 2018

Well cementing is an important operation during drilling and completion of oil wells. The cement sheath must maintain well integrity behind the casing and provide long-term zonal isolation to ensure safety and prevent environmental problems. Some of the uses of cement sheath include providing support for casing, sealing off of annulus and protection of the casing from any corrosive formation fluids that may be in the casing well. Perforation and fracturing operations could damage the integrity of the system of casing–cement–formation during production which could eventually lead to failure. The problems of well cementing still persists despite advancements in technological development of cement and concrete materials. Moreover, changes in temperature and pressure during the life cycle of the well can give rise to several mechanisms of failure that could pose threat to the set cement sealing integrity. Therefore, crucial models are important to understand the behavior of cements at different conditions and hazardous outcomes of cementing failure. The objective of this paper is to review the available failure models for cement and illustrate the main causes of cement failure for actual field cases. This review provides an overview of the five cement failure models including analytical, finite element, probability, thermo-poro- elasto-plastic and buoyancy-driven models. The theory and applications of these models are discussed. Probable solutions to cement failure were also reviewed. This review will help to have proper understanding of the vulnerability of mechanisms of cement sheath failure to changes in important properties of a casing-cement-formation well section when subjected to different well operation conditions. The novelty of this work is the deep investigation of the failure mechanics of different cement slurries in addition to supporting the main conclusion of this work by actual case studies.
Estimating Zonal Gas Contribution Using DST Gas Composition Parameters
Authors: Aijaz M. Jahanzaib , Hameed Khalid , Ahsan Omer
Published: October 2018

Individual contribution from each zone is of vital importance in wells producing from different zones from a single tubing string. Zonal production volumes are important for reserves evaluation as well as future projection with respect to processing facility. Gas analysis obtained during production phase when compared to those obtained during Drill Stem Tests can give valuable information regarding zonal contribution.

Monitoring of production parameters can allow to develop a method based on thorough analysis of DST results to predict specific contribution from each zone. Bifurcation of commingled flow was based on the gradual change in key gas composition parameters. Both zones were initially tested separately and gas samples were collected and analyzed at surface. During testing, CO2 mole percentages from Reservoir 3 and Reservoir 2 were measured as 8 mol% and 5 mol% respectively. When well started commingled commercial production, initial CO2 concentration was recorded as 7.67 mol%. Factors were selected which when multiplied with initial CO2 concentrations gives the recorded CO2 concentration. The factors are the fractional gas contribution from each zone. Gradual decline in CO2 concentration suggested that the contribution from Reservoir 2 has increased over time. Results obtained by distributing the compositions received from production data according to the results obtained during well test analysis were matched by using iterative methods. Based on individual compositional contribution, volumetric contributions were attributed to each zone. Results predicted from this method were in close agreement with the results obtained from down hole logging survey performed later. Method used is general and can be applied to any well with similar characteristics. It can also be extended for three zones producing from same tubing string and reliable data from well testing is available. This can eliminate the costly requirement of down hole logging survey, production loss and risks related to well interventions.

A simple yet holistic method was developed for estimating zonal contribution if reliable well test gas composition data is available. The data was compared with production data and based on the gas composition mix, zonal contribution was attributed which was also verified by down hole logging survey.
High Resolution Analysis of Sand-Based Composition for Hydraulic Fracturing Application
Authors: Al-Hulail Ibrahim , BinGhanim Ahmed , Abdulrazzaq Waseem , El-Hajj Hicham , Abdullatif Osman
Published: October 2018

The application of liquid resin in hydraulic fracturing helps to increase hydrocarbon production by improving conductivity, controlling proppant flowback, inhibiting fines migration, and reducing sand production. This study compares natural sand and proppant in terms of the grain-to-grain relationship (texture) of coated and uncoated samples and describes how microfractures, micropores, and grains are filled and encapsulated by liquid resin.

During proppant placement, the concentration of the resin can delay the curing time, which induces consolidation of the proppant pack in the fractures. By extending the curing period, there is more time for the proppant to develop grain-to-grain contact in the fracture as well as for capillary action to pull the liquid-resin coating to the contact points of the proppant grains, thereby providing a highly cohesive consolidated proppant pack. The resin concentration used falls within the oilfield industry’s applicable practices. Several evaluation techniques were used to understand the crystallinity and morphology of coated and uncoated sand/proppant. These techniques included thin section petrography, scanning electron microscopy (SEM), and geomechanical tests.

Photomicrographs analysis and SEM images have shown the presence of a very large amount of monocrystalline quartz in the uncoated sand samples, which also displayed reduced mechanical strength as a result of microimperfections in the uncoated sand. A comparative study showed that after resin coating the angular and microfractured sand, mechanical properties of the angular and microfractured sand improve as a result of enhanced interlocking effects of this type of sand.

This paper provides a qualitative description of the variation in coated and non-coated sand/proppant in terms of grain-to-grain contact. Moreover, the study also hypothesizes how resin-coated sand can help to fill in micropores and microfractures.
Application of Integrated Reservoir Geomechanics for Well Planning of High-Angled Wells in a Mature Oil Field
Authors: Abbas Ahmed K. , Flori Ralph E. , Al-Asadi Yousif M. , Alsaba Mortadha , Al-hamad Nasser A.
Published: October 2018

Zubair oil reservoir has a significant potential to contribute to the petroleum supply in Iraq. Drilling highly-deviated wells is a commonly used approach to enhance the production in mature fields. Drilling these wells in the Zubair Formation has been a challenge due to severe wellbore instability issues. This study presents how integrated reservoir geomechanics was used for efficient well planning and safe drilling of nearly horizontal wells (75° Inclination) through Zubair depleted sandstone oil reservoir.

In this study, an integrated workflow was implemented mainly to build a geomechanical model using offset well data. The in-situ principal stresses and their orientations were obtained from wireline logging measurements and mini-frac tests. The repeat formation test (RFT) was used to constrain pore pressure. Rock mechanical properties were calculated using empirical correlations that have been derived from laboratory tests on core samples. Mogi-Coulomb failure criteria was used to address safe mud weight for drilling highly-deviated wells successfully. The model was verified with wellbore failure and also with wellbore instability events while drilling operations.

The results obtained from the geomechanical model shows that Zubair sections of planned wells would have narrow mud weight windows. The analyses also emphasized that the shale interbeds in the Zubair section require a mud weight of 1.5g/cc to limit wellbore breakouts. The presented study highlights that the geomechanical model can be applied as cost-effective tools to assess and address existing wellbore instability problems and to guide future well plans for better drilling efficiency with a reduced non-productive time (NPT) by using proper mud weight with respect to the inclination angle and the azimuthal direction.
Developing an Efficient Drilling System by Coupling Torque Modelling with Mechanical Specific Energy
Authors: Hassan Amjed , Al-Majed Abdulaziz , Elkatatny Salaheldin , Mahmoud Mohamed , Abdulraheem Abdulazeez , Nader Mahmoud , Abughaban Mahmoud , Khamis Mohammed
Published: October 2018

Understanding the formation behavior and the drilling operation is essential to optimize the performance of drilling systems. Several studies were conducted to improve the drilling operation in real time basis utilizing different approaches. Numerous mathematical models (analytical or empirical) were developed to relate the drilling parameters with the rate of penetrations and to predict the drilling efficiency. However, these models are arrived at by ignoring some parameters or employing simplifying assumption(s), which may lead to over or under optimistic drilling performance.

The main objective of this research is to investigate the analytical and numerical approaches to calculate the torque and drag in drilling operations and produce a simple and robust model using artificial intelligent techniques. More than 22,000 data point from several wells for depth up to 18,000 ft. was used to develop and validate the model reliability. The full profiles of torque and rate of penetrations was determined, also the required energy for drilling each section has been estimated. The developed model could be utilized to define the optimum range for torque, which leads consequently to generate an efficient drilling system and reduce the drilling cost.

In this study, rate of penetration (ROP) was determined using the torque profile and mechanical specific energy (MSE) based on real time and rig-site data. Statistical analysis was conducted to understand the importance of drilling parameters on the variations of torque and rate of penetration. Drilling parameters such as weight on bit (WOB), revolution per minute (RPM), fluid circulation rate (Q), and bit hydraulic horse power (HPb) has been studied. Thereafter, artificial neural network (ANN) model was developed to predict the torque and ROP profiles. The suggested models enable the drilling engineers to optimize the drilling parameters in a real-time manner, by changing the surface and controllable parameters in such a way that maintains the drilling operations within the optimum conditions. This research will assist in improving the operations efficiency through optimizing the drilling parameters. A strong robust model was developed which yields high accuracy results when compared with actual field measurements, average absolute percentage error of less than 6.5% was achieved.
The Impact of Near-Wellbore Refinement on Modelling Advanced and Smart Well Completions in Reservoir Simulation
Authors: Awid Abdurrezagh , Geiger Sebastian , Mackay Eric
Published: October 2018

Advanced or smart completion wells are different from conventional wells by being equipped with downhole flow control devices such as Interval Control Valves (ICV) and Inflow Control Devices (ICD) to offer improved reservoir management and control and thus maximise hydrocarbon production and recovery. In order to justify their implementation and increase their economic return, a high degree of robustness in modelling, prediction and optimisation of their performance is required.

To improve the robustness of forecasting production from advanced or smart wells using reservoir simulation, high-level details in rock and fluid flow properties are needed in the near-wellbore region to accurately capture the flow dynamics. The paper presents an improved approach that enables us to robustly predict the performance of advanced or smart wells in reservoir simulation and highlights the importance of representing the near-wellbore region when optimizing smart well completions.

Performances of advanced or smart well completions are very dependent on changes in flow rate, pressure, and saturations, which mainly occur in areas around the wells. The paper demonstrates the use of local grid refinement (LGR) in the near-wellbore region to enhance the accuracy level of simulation predictions. In the study, an objective function based ICV optimization strategy was used to identify the optimum settings for every time step during the simulation run. We also demonstrate how to correlate ICV settings to Passive Inflow Control Device (PICD) or Autonomous Inflow Control Device (AICD) strengths if a requirement arises to impose the use of ICVs.

Using a well-established synthetic reservoir model, we demonstrate how the representation of the near-wellbore region impacts reservoir performance predictions and influences the way ICVs and ICDs are optimized. We observe that by applying this approach, the predicted NPV and recovery factor change by 6.6% and 6.1%, respectively. In addition, this study also quantifies the impact of near-wellbore representation on four completion types; Openhole, ICV, PICD and AICD completions.

The novelty of this paper is that it presents an approach to improve production forecasts that supports decision making during field development planning to maximize profit and minimize risk.
Real Time Determination of Rheological Properties of Spud Drilling Fluids Using a Hybrid Artificial Intelligence Technique
Authors: Abdelgawad Khaled , Elkatatny Salaheldin , Mousa Tamer , Mahmoud Mohamed , Patil Shirish
Published: October 2018

Measuring the rheological properties during the drilling operation is time-consuming and usually, these properties are measured twice a day. The rheological properties play a key factor in controlling the drilling operation. The knowledge of these properties are very important for hydraulic calculations which are required for hole cleaning optimization, surge and swab pressure calculations and others. Wrong estimation of these properties may lead to big disaster during the drilling operation such as pipe sticking, loss of circulation, and/or well control issues. The aforementioned problems will increase the non-productive time and hence the overall cost of the drilling operations. Artificial intelligence techniques, once they are optimized, can be used to predict the rheological properties in a real time.

The main idea of this paper is to use the frequent measurements of the mud density, Marsh funnel viscosity and solid percent, which are measured every 15-20 minutes and build new artificial intelligent models for plastic viscosity, yield point, apparent viscosity, and flow behavior index. Different AI techniques were evaluated such as; artificial neural network, support vector machine (SVM) and adaptive-network-based fuzzy inference system (ANFIS). The model which yielded the highest accuracy (lower average absolute error (AAPE) and highest correlation coefficient (R)) was used to develop new empirical correlations for each rheological properties. For the first time, the artificial intelligence techniques were combined with the self-adaptive differential evolution algorithm to optimize the best combination of the AI parameters.

The results obtained showed that ANN is the best AI technique to predict the rheological properties from the mud density, Marsh funnel viscosity, and solid percent. It is very important to combine the self-adaptive differential evolution with the artificial neural network to predict the rheological properties with high accuracy (AAPE less than 5% and R greater than 95%). The ANN black box was converted to a white box by extracting the weights and biases of the optimized SaDe-ANN model for each rheological parameter and a new empirical correlation was developed. The developed technique will help the drilling engineer to predict the rheological properties every 15 to 20 minutes and this will help in hole cleaning optimization and avoid most of the drilling problems such as pipe sticking and loss of circulation. The developed correlation can be used without the need for the ANN model and can apply using any software. No additional equipment or especial software is required for applying the new method.
Detecting Natural Fracture properties using Rate Transient Analysis
Authors: Assiri Wisam J , Ozkan Erdal
Published: October 2018

Most unconventional reservoirs are characterized by an ultra-tight matrix and commercial production requires existence of a pervasive fracture network or conductive laminations within a shale play intersecting hydraulic fractures of horizontal wells. This paper shows that the early time flow for hydraulically fractured horizontal wells can be analyzed to quantify the properties of the hydraulic fracture and the feeding natural fractures. The linear or bilinear flow of early time can provide important information about the existence of natural fractures and their properties. A suite of tools is presented to analyze early time flow periods.

The solution is based on the trilinear model with a stimulated reservoir volume (SRV) represented by the transient, dual-porosity, slab model. This model is suitable to define flow from laminated unconventional reservoirs with tight matrix. Asymptotic solutions are derived for linear and bilinear flow regimes and conditions for their existence are provided. The start and end time of each flow regime can reduce uncertainty in the analysis. Flow restriction due to choking effect is considered. This analysis can help to forecast production from fractured horizontal wells in ultra-tight, fractured unconventional reservoirs.

Simulated examples demonstrate how hydraulic fracture conductivity can be estimated as well as the properties of natural fractures. Application of the analysis is also demonstrated on flowback data.

The importance of the recognition and analysis of the flowback data is in the potential to estimate the size of the SRV before productivity decline. Moreover, this paper explains the procedure to correctly use the start and end time of each flow regime and the conditions to bilinear flow to prevail. Application examples and results of misinterpretation of linear flow behavior are demonstrated.
Experimental Investigation of Radial and Linear Acid Injection into Carbonates for Well Stimulation Operations
Authors: Qiu Xiangdong , Edelman Eric , Aidagulov Gallyam , Ghommem Mehdi , Brady Dominic , Abbad Mustapha
Published: October 2018

Linear core flooding experiments have been extensively conducted to develop a fundamental understanding of the interactions between the acid and rock and provide guidance to control and optimize matrix acidizing operations. These experimental studies are mostly performed at lower than true reservoir operating conditions (pressure and temperature) using cylindrical cores of few inches length. Well treatment design software based on upscaling linear core flood data to design well treatment schedules including the selection of pump volumes, rates and fluids may fail to predict wormhole penetration depth and identify the optimum injection rate as the field acidizing operations are dictated by radial flow configuration. Given its associated complexity, only few radial acidizing experiments have been reported in the literature.

A sophisticated experimental set-up capable of treating large-scale rock blocks is used to conduct radial acidizing experiments at high pressure levels mimicking real reservoir conditions. A series of linear core flow experiments are also conducted for various injection rates at similar operating conditions in terms of applied pressure and temperature. Acidizing efficiency curves showing the variations of the pore volume to breakthrough (PVBT) as function of acid injection rate, along with the optimum injection rate are obtained and compared. The experimental results show that the acidizing efficiency curve of radial acid injection is drastically different from that of linear core acid injection. Higher PVBT values are for the linear acidizing case. The 3D wormhole networks resulting from acidizing such as wormhole depth, branching, initiation and death are influenced by a transfer to radial acid injection, leading to a significant change of the resultant fluid conductivity compared to that predicted from linear studies.

Acidizing efficiency curves constitute a critical component of most carbonate-matrix-stimulation models used in the oil & gas industry. Most of the existing models are based on the linear core acid injection experimental data while radial acidizing is more representative of real acidizing operations. The present experimental study is expected to redefine state-of-the-art of PVBT and optimum injection used in matrix acidizing applications.