bluuebunny/crossref_metadata_2025_split huggingface dataset:
Use of Emulsified Acid System with Corrosion Protection up to 350°F
Authors: Wadekar Sushant , Pandya Nisha 
Published: June 2014

Abstract
Acidizing operations increasingly present challenges in deeper formations. The formation of wormholes and inhibition of corrosion are particularly becoming significant because both are drastically affected in deeper wells with higher temperatures. In emulsified acid fluids, the direct contact between the acid and formation is reduced, thus enhancing the formation of wormholes at high temperatures. Emulsions also reduce the direct contact between acid and metal, thus improving the inhibition of corrosion. This makes emulsified acids one of the most promising fluids for high-temperature acidizing operations; however, the primary challenge is stabilizing the emulsion system at increased temperatures and in the presence of corrosion inhibitors. Using the existing emulsifiers, it is often difficult to formulate a stable emulsified acid that can pass corrosion testing above 300°F.
This paper discusses the study of a new emulsifier with a high molecular weight and branched nature. Because of these structural aspects, the new emulsifier retained its emulsifying power at high temperatures and in the presence of corrosion inhibitors. This helped enable the use of appropriate quantities of corrosion inhibitors within the system. The emulsified acid system was further optimized to pass static high-pressure/high-temperature (HP/HT) corrosion testing at 350°F with 20% hydrochloric acid (HCl) strength. The same fluid also passed corrosion testing with 28% HCl strength at 325°F. Per the data, the use of this new emulsifier helped improve both emulsion stability and corrosion inhibition because of better separation between the acid and metal surface. The new emulsifier system also has a lower chemistry scoring index (CSI) than existing emulsifiers.
The acidizing operation of carbonate reservoirs with bottomhole static temperatures (BHSTs) up to 350°F become attainable using the new emulsified acid system. Guidelines for designing acidizing fluids with this higher temperature limit are presented.
Performance Evaluation and Challenges Using Open Hole Multistage Fracturing Completion to Develop Tight Gas Reservoirs in Saudi Arabia
Authors: Al-Dawood Mahdi , Abdul Aziz Azly , Al-Omair Ahmed , Rahim Zillur 
Published: June 2014

Abstract
A low permeability gas condensate carbonate reservoir in the Khuff formation is one of the main producing reservoirs in Field-A in Saudi Arabia. This early Triassic carbonate reservoir, first discovered in 1980, holds significant gas-in-place but is a blend of conventional and tight intervals. Vertical completions, horizontal wells with maximum reservoir contacts, and acid stimulation (matrix and fracturing) are some of the current practices to effectively develop the reserves from the tighter intervals.
In late 2009, the open hole horizontal multistage fracturing (OHMSF) completion assemblies were deployed in several horizontal wells in the tight gas area with the goal of achieving multiple independent hydraulic fractures, greater acid stimulation efficiency, and thereby enhancing well productivity. The OHMSF systems enable the open hole section to be divided into segments based on the reservoir's petrophysical and flow properties by the use of mechanical open hole isolation packers and customizing the stimulation treatment for each segment via fracturing ports that are installed in between the packer assemblies.
Since the inception of OHMFS, many wells were treated and varying results were obtained. The results are dependent not only on reservoir quality and development, but also on the placement of the fracturing ports, number of fracture stages conducted, and fracturing strategy.
This paper provides insight into the planning, challenges encountered, sensitivity analysis and performance analysis of the OHMSF wells in comparison with non-OHMSF wells. It also details several case histories and highlights the results as well as lessons learned that can be applied in the future to improve the recovery.
CT Extended Reach Acid Stimulation in Openhole Wells, Offshore Saudi Arabia: A 23-Well Case Study
Authors: Arukhe James , Hanbzazah Shadi , Ahmari Abdulrahman , Adesegha Rotimi , Perez Joan , Noguera Jose , Krishnan Gopi , Nakhwa Amit 
Published: June 2014

Abstract
A new generation of ultradeep wells has significantly increased in Saudi Arabia in green and brown field developments. One ongoing complex field development is the Manifa field, which is located in northeast Saudi Arabia. Manifa is probably the largest extended reach hydrocarbon producer project globally, with more than two-thirds of its 350 wells being extended or mega reach wells. The offshore portion of the field contains 83 developed wells in 13 platforms with openhole sections within the range of 3,000 to 9,000 ft, where acid stimulation intervention is necessary to remove reservoir damage and to help improve well performance after drilling operations. Although the openhole completions provide superior deliverability, a primary challenge remains with respect to rigless intervention.
The offshore platforms have limited deck load capacity and available deck space necessary for performing coiled tubing (CT) stimulation operations. To overcome these constraints, applicable CT operations from a jackup barge combined with a support pumping vessel were introduced and subsequently developed to allow well interventions using large treatment fluid volumes.
This paper describes CT stimulation campaigns performed on extended reach horizontal wells in the Manifa field. A summary of the steps involved during an improved CT intervention technique successfully implemented within this field to access some of the longest openhole horizontal wells is presented. The importance of a combined application of jackup and stimulation vessel units to help ensure safe project execution on offshore platforms is reviewed.
Environmentally Acceptable Swell Packer Fluid for Unconventional Reservoirs with High-Temperature Applications
Authors: Pandya Nisha , Kalgaonkar Rajendra , Allison Dave 
Published: June 2014

Abstract
In unconventional reservoirs, such as shale reservoirs, the use of sliding-sleeve completions along with chemical swelling external casing packers can lead to increased production rates. This method has been used in unconventional reservoirs (shale) that are drilled horizontally (for maximum reservoir exposure) and hydraulically fracture stimulated in multiple stages. When fracturing a new zone, it is necessary to isolate the various zones that have been previously fractured. By using completion assemblies with sliding sleeves and swell packers activated with chemicals, the various pay zones in a single wellbore can be managed with the option of closing off one or more sliding sleeves at a future date, and isolation is facilitated by using the swell packers.
Swell packers can be activated using water-or hydrocarbon-based fluids. However, these conventional fluids have shown a tendency to damage certain shale formations, thus increasing operator concern when using such fluids in shale reservoirs.
A new environmentally acceptable shale-optimized activation fluid system was developed for use with swell packers. It is an oil-external invert-emulsion consisting largely of an aqueous internal phase incorporated into the hydrocarbon external phase. It is an effective low-leakoff fluid that provides controllable swell profiles for the swell packers while causing minimum physio-chemical damage to shale. Additionally, the system is free of any benzene, ethylbenzene, toluene, and xylenes (BETX) hydrocarbons and incorporates an environmentally acceptable emulsifier. This provides it with an improved environmental profile. Moreover, this emulsion can be stabilized with nanomaterials to promote longevity under high-temperature reservoir conditions up to 225°F. This paper documents the laboratory investigation and development of the novel environmentally acceptable activation fluid system.
The First Successful Multistage Acid Frac of an Oil Producer in Saudi Arabia
Authors: Rafie Majid , Said Rifat , Al-Hajri Muhammad , Almubarak Tariq , Al-Thiyabi Adel , Nugraha Ikhsan , Soriano Eduardo , Lucado Jared 
Published: June 2014

Abstract
In Saudi Arabia, conventional oil reservoirs have been treated using conventional stimulation methods. The challenge is that many of the formations now are tighter and require improved stimulation methods. Fracturing is a major topic discussed in the industry as of late and as such, using it in this formation will serve as a trial to shift from conventional stimulation methods to fracturing when facing tighter formations.
This particular acid frac was performed in a tight carbonate formation. The chosen well is a newly drilled trilateral producer completed with a multistage frac completion in the motherbore and will serve as a pilot well for this reservoir in the area. The acid frac was a seven stage completion utilizing hydraulic fracturing. Several methods using pressure and injection were used to determine reservoir fracturing response and petrophysical properties.
This paper will discuss the first multistage acid frac performed in an oil producer in Saudi Arabia. It will examine the entire process of candidate assessment, job preparation, and execution. In addition, the paper will discuss challenges faced, solutions taken, and the post-decision results. The paper will show how an injectivity test performed pre-and post-frac was used as a benchmarking tool to analyze the effectiveness of the frac. Finally, we will discuss the flow back of the well, initial results, lessons learned, and optimization of future jobs.
Density-Driven Flow Simulation in Anisotropic Porous Media: Application to CO2 Geological Sequestration
Authors: Negara Ardiansyah , Salama Amgad , Sun Shuyu 
Published: June 2014

Abstract
Carbon dioxide (CO2) sequestration in saline aquifers is considered as one of the most viable and promising ways to reduce CO2 concentration in the atmosphere. CO2 is injected into deep saline formations at supercritical state where its density is smaller than the hosting brine. This motivates an upward motion and eventually CO2 is trapped beneath the cap rock. The trapped CO2 slowly dissolves into the brine causing the density of the mixture to become larger than the host brine. This causes gravitational instabilities that is propagated and magnified with time. In this kind of density-driven flows, the CO2-rich brines migrate downward while the brines with low CO2 concentration move upward. With respect to the properties of the subsurface aquifers, there are instances where saline formations can possess anisotropy with respect to their hydraulic properties. Such anisotropy can have significant effect on the onset and propagation of flow instabilities. Anisotropy is predicted to be more influential in dictating the direction of the convective flow. To account for permeability anisotropy, the method of multipoint flux approximation (MPFA) in the framework of finite differences schemes is used. The MPFA method requires more point stencil than the traditional two-point flux approximation (TPFA). For example, calculation of one flux component requires 6-point stencil and 18-point stencil in 2-D and 3-D cases, respectively. As consequence, the matrix of coefficient for obtaining the pressure fields will be quite complex. Therefore, we combine the MPFA method with the experimenting pressure field technique in which the problem is reduced to solving multitude of local problems and the global matrix of coefficients is constructed automatically, which significantly reduces the complexity. We present several numerical scenarios of density-driven flow simulation in homogeneous, layered, and heterogeneous anisotropic porous media. The numerical results emphasize the significant effects of anisotropy in driving the migration of dissolved CO2 along the principal direction of anisotropy even if the porous medium is highly heterogeneous. Furthermore, the impacts of the increase of density difference between the brine and the CO2-saturated brine with respect to the onset time of convection, the CO2 flux, and the CO2 total dissolved mass are also discussed in this paper.
Evaluation of Diagenetic Scaling on Flowback Proppants
Authors: Nanda Jajati , Pal Omprakash , Patil Anil 
Published: June 2014

Abstract
Proppants are used to keep hydraulic fractures open and maintain conductivity for hydrocarbons to produce at higher rates. Diagenetic growths or scales formed under in situ well conditions caused by interactions between proppants and formation minerals within the presence of water can reduce conductivity and cause a decline in production revenue. Previous papers have reported the various geochemical reactions that may occur under downhole conditions, which can cause scaling on alumina-based proppants.
This paper describes a study of diagenetic materials received with proppants that have flowed back from a fractured well. The preliminary examination of the samples under a high-resolution microscope revealed the presence of ceramic proppants, formation dust/sand, and polymers. Microscopic examination revealed white-colored deposits/scaling on the surface of the proppants, which can obstruct fracture conductivity. The polymers from the flowback samples were physically separated from the solids before analysis. Formation dust/sand and proppants were also subjected to X-ray diffraction (XRD) study, which revealed the presence of zeolites and carbonates. The original core cuttings from the respective locations were also studied for the availability of zeolites or carbonates.
The study was performed in the following steps: The flowback samples were studied using a microscope for initial assessment.The samples were studied using XRD for the identification and quantification of phases.The original cores from respective locations were studied using XRD to check the presence of zeolites or carbonates.The post-frac flowback water was studied using inductively coupled plasma atomic emission spectroscopy (ICP-AES) and ion chromatograph (IC), respectively, for cations and anions responsible for carbonate scale formation and the water properties supporting scale formation.
This paper provides a systematic method of analyzing flowback samples to help determine the downhole conditions responsible for the occurrence of diagenetic scale.
How Malfunctioning Completion Accessories Affect Well Performance in Offshore Saudi Arabia
Authors: Al-Khanferi Mohammed , Bubshait Ahmed , El-Fattah Mahmoud Abd , Al-Shabibi Hussain , Bawazir Mustafa 
Published: June 2014

Abstract
To overcome horizontal well reservoir and production challenges, inflow control devices are adopted as the optimal completion method in many parts of the world. The main industry drivers for adopting inflow control device completions include balancing inflow along the well, delaying water and gas breakthrough, controlling water and sand production, and providing a cost-effective reservoir completion solution to meet the majority of the reservoir challenges. In offshore Saudi Arabia, inflow control devices have been used successfully in fulfilling these objectives. The downhole completion efficiency is evaluated using multiphase production logging tools.
Many completion accessories can be run with inflow control device completion strings, these include isolation packers, liner hangers, setting tools, end-of-completion string plugs and valves. All of these accessories may affect the well's production performance. New challenges arise when one of these accessories, such as the end-of-completion valve or isolating packers malfunction and develop a leak; thus, affecting the inflow control device completion performance. A major failure can result from such a malfunction, including fluid drainage from the toe section, sand production, early water breakthrough and water coning.
This paper presents two field examples in which multiphase production logging profiles of horizontal wells are used to evaluate the inflow control device completion performance and detect any completion-accessory malfunction. Multiple sensitivity simulation runs — supported by multiphase production logging results — facilitate optimizing the inflow control device completed well performance. This integrated approach is used to recommend solutions or remedial actions to overcome suboptimal well completion performance. Also, the approach provides a comprehensive understanding of the reservoir results that should be considered in planning future completion and workover strategies.
Integrated Formation Evaluation of Tight Gas Delineation Wells: Best Practices and Lessons Learned
Authors: Hammou Nasreddine , Balawi Ali , Eid Mahmoud , Quirein John 
Published: June 2014

Abstract
The formation evaluation of Saudi Arabian tight gas reservoirs presents multiple challenges. The targeted gas resources discussed in this paper include both conventional and unconventional reservoirs. The complexities encountered include varying mineralogy, facies and mechanical properties, wide ranges of porosities and pore types, hydrocarbon viscosity, and variable formation water salinities. Major petrophysical uncertainties exist, including clay structure, variation of grain size distribution, electrical properties, and water salinity, that can be resolved by determining better data interpretation techniques and customizing the workflow for such reservoirs.
This paper presents interpretations from two wells within the same reservoir, based upon combining the geochemical, nuclear magnetic resonance (NMR), and conventional logging measurements. The integration of NMR data acquired with conventional logs is shown to be beneficial for the identification and quantification of hydrocarbon-bearing reservoirs and provide valuable information about porosity, relative permeability, and reservoir quality to be used for a fracturing assessment. The mineralogy and porosity information are obtained from geochemical and nuclear logs. By combining the mechanical properties results with the geochemical and NMR log total porosity interpretation, fracture parameters, such as Poisson's ratio, Young's modulus, and fracture closure pressure, can be obtained and a better fracturing job can be performed.
The case study results from these two wells demonstrate how to use and integrate all the available data, including the mud logs, to understand the reservoir behavior and to generate a workflow for future wells. This process includes optimizing the NMR activation scheme and using laboratory data to define a model for determining the T2 cutoff. Finally, rock mechanics laboratory measurements are required to develop and validate the fracture parameters prediction model.
Characterization of Heavy Oil Properties in a Complex Shallow Miocene Reservoir in Saudi Arabia using NMR and Other Advanced Log Measurements
Authors: Idris Umar , Hursan Gabor , Saldungaray Pablo , Azam Hisham 
Published: June 2014

Abstract
The successful production of heavy oil (typically defined as oil with an API gravity of less than 20) depends on several reservoir properties such as porosity, permeability and reservoir pressure, but it is the in-situ oil viscosity that dictates the oil mobility and production approach required, and ultimately the economic viability of the project. For this reason, the possibility of estimating the hydrocarbon viscosity from logs, thereby providing a continuous record of the fluid properties along the reservoir is of great value.
Fluid viscosity has a strong effect on nuclear magnetic resonance (NMR) logs, including the NMR relaxation rate (T1 and T2 distributions), diffusivity, and signal amplitude (NMR porosity) measurements. These effects can be exploited to derive correlations to viscosity. Depending on the viscosity range, NMR standalone methods can be used, typically for 1 to 100 cp. For higher viscosities, a volumetric approach is required, combining the NMR data with other logs to develop specific correlations for particular reservoirs and oil types. These correlations are not universally applicable, and must be customized before being applied to a different environment.
Several techniques were compared to estimate oil viscosity in a shallow Miocene reservoir. The formation is characterized by very complex mineralogy, high porosity, and slightly freshwater salinity. This complicates the volumetric approach, which requires an accurate total porosity and oil volume estimation. We discuss how elemental spectroscopy and dielectric logs help to reduce the uncertainty in the viscosity estimation. The merits and applicability of NMR-only techniques in this complex environment were also explored. The log-based viscosity correlations were calibrated with in-situ and laboratory fluid sample viscosity measurements. The model will be used to predict viscosities prior to performing well tests in subsequent wells.
Optimizing Spacing of Horizontal Multistage Fractured Wells in Gas Reservoirs
Authors: Alghannam Maryam , Rahim Zillur 
Published: June 2014

Abstract
The growing demand for gas in the Kingdom of Saudi Arabia and the availability of multistage fracturing (MSF) of horizontal well technology have opened up the development of tight gas reservoirs throughout the country. Draining the reservoir efficiently using MSF strongly depends on well spacing, especially for low permeability reservoirs. The majority of the work done by the industry to find the optimum well spacing was based on economic considerations. Saudi Aramco optimizes field development based on sustained rate and ultimate hydrocarbon recovery. Natural gas is treated as one of the most essential commodities supporting the country's infrastructure based on the increased domestic energy demand.
Some of the significant parameters to consider for well spacing optimization are the drilling azimuth and well completion strategy that include a number of induced fractures, fracture conductivity, and fracture half-lengths. In addition, reservoir properties, such as formation thickness, reservoir permeability, and the permeability anisotropy ratio are to be considered. Due to the scarcity of interference test data in gas wells and the inaccuracy of analytical solutions, numeric simulation is the most suitable approach for such a study. To find the optimum well spacing, several simulation runs are carried out for a realistic range of well and reservoir variables. The outcomes are then translated into a 20-year cumulative production as a function of the well spacing, with the results indicating that lower permeability reservoirs require closer well spacing. In the case of a large number of long fractures, wells need to be placed further away from each other to minimize well interference. This paper gives the recommended MSF horizontal well spacing for several development scenarios in Saudi Arabian gas reservoir environments. Although each area must be individually studied and optimized, the results will provide engineers with guidelines to better plan gas field development with the application of MSF technology.