bluuebunny/crossref_metadata_2025_split huggingface dataset:
Case Study of Gravity and Power Assisted Dump Floods Implemented in a Mature Oil Field
Authors: Mahmud Walid Mohamed , Abdussalam Omran Elhamali , Swissi Yousef , Elmabrouk Saber Kh. 
Published: February 2022

Abstract
Dump-flood is a powerful and convenient recovery technique that maintains a reservoir pressure where an aquifer and an oil leg are perforated in the same well. In gravity assisted dump-flood, GADF, water from a shallow waterbed above is injected by its own hydrostatic weight into an underneath oil bearing formation. In a power assisted dump-flood, PADF, the injection pressure from the waterbed maybe enhanced by utilizing electrical submersible pumps, ESP. In this work, both GADF and PADF were implemented in a mature depleted reservoir block for a quick pressure maintenance program. Three injectors were drilled and completed to have both the upper Gir and lower Gir intervals in communication. ESPs were installed in three wells to enhance the water gravity effect. Recovery Factor, RF, increased from 8.92% before the implementation of dump- flooding to 10.68% after the implementation with no signs of plugging or scaling in the reservoir. Reservoir pressure increased by 213 psi due to dump-flood implementation and oil production rate increased in one of the wells by 1629 barrel per day at an optimum choke size of 24/64 in. Dump-flooding is an excellent alternative to conventional water injection as the pilot injectors significantly stopped rapid pressure decline and improved production rates.
Experimental and Numerical Analysis of Thermal EOR Recovery Schemes for Extra-Heavy Oil of the Oykino-Altuninsky Uplift of the Romashkinskoye Oilfield
Authors: Pituganova Anastasia , Nassan Taofik , Amro Mohd , Minkhanov Ilgiz , Varfolomeev Mikhail , Bolotov Alexander 
Published: February 2022

AbstractCrude oil production from conventional oil reservoirs is declining owing to heavy exploitation to meet the global energy market demand which is growing on a yearly basis. Unconventional oil resources, e.g. extra-heavy oil and bitumen, can compensate for this decline if appropriate enhanced oil recovery (EOR) methods are developed to enable economic flow from these resources. The main objective of this study is to set the best practice for the extra-heavy oil production of the Oykino-Altuninsky uplift of the Romashkinskoye oilfield (Tatarstan Republic, Russia). A series of experimental tests are applied on a real unextracted unconsolidated core sample from Romashkinskoye oilfield where the viscosity of the crude oil is above 600,000 cP at reservoir conditions. Different recovery schemes are tested experimentally and sequentially, namely: water flooding, hot water flooding, steam flooding, and finally in-situ combustion (ISC). Furthermore, the complete experimental run is simulated by a standard nonisothermal simulator and the results are compared to the experiments. On contrary to what was expected hot water at 100°C didn’t achieve any recovery from the sample and steam injection recovered only 11,5% of OOIP. ISC-is also known as fire flooding-attained the best recovery which reached 45% after steam flooding. Complete SARA analysis of the original oil and produced oil by steam and ISC is implemented to understand the mechanisms of each process. Numerical modeling is applied to the corresponding laboratory experiments and the results for water, hot water, and steam flooding were in good agreement with the experimental results while the in-situ combustion simulation showed a better recovery factor than experiments. The laboratory and numerical experiments will improve our understanding of the recovery options of Oykino-Altuninsky uplift of the Romashkinskoye oilfield and help the developers to choose the best production sequence for this oilfield particularly. Moreover, the experiments will provide inputs for the field-size numerical model after running more experiments on unconsolidated and consolidated cores.
A Non-Intrusive Production Optimization Technology for Surveillance of Gas Lift Wells
Authors: Tyagi Himanshu , Peacock Larry 
Published: February 2022

Abstract
This paper outlines a strategy to address the complexities involve in well surveillance and production optimization of gas lifted wells which operators around the world face in the quest to maximize production. Recent enhanced software-based analysis, designing and optimization has proved to be an effective tool in enhancing rate of production from an existing gas lifted well.
This technology incorporates introduction of a small volume of CO2 into the injection line and then measuring CO2 concentration via a sensor connected to wellhead tree, flowline or well test separator. Injection pressure and injection rate during the trace integrate with the well and valve modeling to determine the depths of each injection observed.
A pilot project on twenty wells of a major operator in the middle east exhibited a significant improvement in well performance with an incremental gain of 2000 bopd. One of the greatest strengths of this approach is that there is no need to shut-in or run any type of well intervention, resulting in greatly reduced risks, not only to field personnel but also to the well itself. Typical surveillance approach in assessing the health of the gas lifted wells is to deploy flowing gradient survey in tandem with surface well test. However, this historical technology has limitations in investigating prolific wells due to its current well mechanical condition, slugging nature, slim-hole completion design and dual strings design well environment. Application of this technology has broken the barrier in evaluation of these wells. It provides an efficient means of snapshotting the downhole issues beyond the capability of standard pressure and temperature surveys.
This paper considers multiple scenarios that help revive and elevate a potential hydrocarbon source and recommends suitable actions which allow production engineers to analyze performance of an oil well. With the increased complexity of mature fields, each next step to improve recovery comes with increased cost. Therefore, novel horizons of affordable technology will play a pivotal role to maximize economic recovery and meet rising demand in the current business environment.
Increasing ESP Lifetime by Employing Novel Non-Corrosive Acid System for Scales Removal
Authors: Gamal Hany , Elkatatny Salaheldin , Al-Majed Abdulaziz A. , Al-Afnan Saad , Bahgat Mohamed 
Published: February 2022

Abstract
The scales precipitated on the electric submersible pump (ESP) will lead to trapped heat, lower the motor's cooling capacity, decrease the pump lifetime, and finally pump failure. Removal of oil field scales commonly requires low pH acid that can cause corrosion, hydrogen sulfide evolution, ferric and ferrous hydroxide precipitation, iron sulfide as a by-product, and/or sulfur precipitation. Scales typically occur in the near wellbore, tubing, downhole pumps, and surface equipment. A mineral deposition is widespread with a change in pressure, temperature, pH, and incompatible mixing between injected seawater and formation water.
This paper presents a new scale dissolver that is non-corrosive and has a high scale dissolution performance for barium sulfate scales. The study explains a series of comprehensive experimental lab tests such as X-ray diffraction (XRD), X-ray fluorescence (XRF), brine compositional analysis, fluid compatibility and stability, solubility test, precipitation tendency for the dissolved solids, and corrosion test to evaluate and simulate the field application of the new dissolver using two field scale types that mainly contain barium sulfate (BaSo4) scales.
The obtained successful results indicated that the novel dissolver had a great dissolution efficiency for two real barium scale samples as the results showed that the dissolution rate recorded 91.3 and 78.4 % at 90 °C for samples 1 and 2 respectively. The novel dissolver showed a very low precipitation tendency for the scale dissolved solids (1.9 and 3.2 % for samples 1 and 2 respectively). Without any additives of corrosion inhibitors, the corrosion rate was 0.00376 lb/ft2 at 1000 psi and 50 °C for 6 hours.
The obtained successful results will help to dissolve the barium sulfate scales, maintain the ESP performance, increase the lifetime, and save extra cost for the pump operational problems due to scale precipitations.
Rejuvenating First Shale Gas Field of China by Introducing Innovative and Tailored Casing in Casing Cementing Solutions
Authors: Liu Yaowen , Li Yuanzhao , Shen Jincai , Wang Bin , Zhang Chi , Zhao Kun , Ming Yue , Liu Zhongjun 
Published: February 2022

Abstract
China discovered Fuling shale gas field in 2012. The production dropped dramatically for early drilled wells with the time. Refracturing the wells to maintain production is a must to keep the field economically viable. A new method of cementing a smaller inner casing inside legacy production casing and then plug-and-perf fracturing was executed and the production was rejuvenated.
The procedure consists of well kill, wellbore cleanout and reaming, cure losses and then cementing. The wellbore re-construction process will isolate all existing perforations in the wellbore, and it can pass the pressure test for fracturing. The legacy wellbore is 5.5 inch size and a specialized 3.5 inch semi-flush joint casing was selected as new production string. A dependable cement barrier in this extremely tight annulus is required to carry on future re-fracturing operation. 2D hydraulic simulations and computational fluid dynamic was performed to optimize slurry density, rheology, and the method of cement placement. The cement mechanical property is enhanced to withstand the high pressure of fracturing. The top of cement in the annulus will be above the topmost existing perforation. The remaining 3.5 inch casing above the designed depth was disconnected and pulled out.
The wellbore was cleaned, and the losses were treated prior cementing. Tailored ceramic centralizers were installed on the casing surface to achieve optimum stand-off. The centralizer's friction factor is low to casing running to bottom successfully. A low rheology slurry tailored for optimum mechanical properties of fracturing operation was pumped, and the cement returns to designed depth were noted. The casing string disconnected at designed depth and pulled out successfully. After waiting on cement, the wellbore passed pressure test. Cement bond log showed excellent results and the top of cement reached the designed depth. The stage fracturing operation was performed with no issues of wellbore integrity.
A typical procedure of casing-in-casing cementing were recognized. Tailored slurry and centralizers design helped to achieve zonal isolation objective in the low clearance Casing-in-Casing cementing. The critical wellbore re-construction objective achieved and well was re-fractured with substantial increase in production.
Lessons Learned from a Case Study of Downhole Microseismic Mapping in the Southern Sichuan Shale Gas Play
Authors: Yue Wenhan , Wang Xinghao , Chen Juan , Tang Jie , Zheng Guangjie , He Long 
Published: February 2022

Abstract
A real-time downhole microseismic mapping technique was recently used in the southern Sichuan shale gas development. The case study presented illustrates this technique and analyzes the results, from the geological evaluation through the engineering solution, for a typical H24 pad fracturing.
High Salinity Water Flooding in Carbonate and Clastic Rocks: Qualitative and Experimental Analysis
Authors: Al-Ibrahim Hussain , Taq Ali , Alyami Ibrahim , Aldarweesh Sajjad 
Published: February 2022

Abstract
Quality of water used for injection is a very essential factor in preventing/minimizing formation damage potential and thus maintaining required injectivity. Also, injected water should be compatible with both rock and formation fluids minimizing risk of permeability impairment or flow assurance problems during the production phase. Assessing water quality is a prime step to prevent scale precipitation, fine migration and any negative impact resulting from water/rock interactions.
Extensive experimental studies including HT/HP compatibility tests and coreflooding experiments were conducted to evaluate the effect of high (salinity, sulfates and bicarbonates) water samples on clastic and carbonate core plugs. The impact of rock clay content, fine migration and scale deposition on impairment of rock permeability was investigated. Compatibility and coreflooding tests were conducted on different water mixtures to optimize a water mixture having less effect on formation permeability. Experiments were conducted at temperatures up to 200°F and pressure 3,000 psi. Formation damage mechanisms were investigated using XRD and ESEM methods on precipitated scale due to fluid/fluid and rock/fluid interactions.
HT/HP compatibility test results indicated that some of the examined water mixtures precipitated iron compounds when exposed to air. Oxygen scavenger was added to some water mixtures to halt iron precipitation before injection into the carbonate and clastic core plugs. Coreflood experiments showed permeability reduction in some of the core plugs, which was attributed to the precipitation of iron oxide/hydroxide compounds as, indicated from ESEM and XRD analysis. High sulfates and high bicarbonates content of some of the water mixtures precipitated compounds that contain both on the face and deep inside some of the tested plugs leading to reduction in permeability.
This paper presents a qualitative and experimental water flooding analysis study conducted to assess interaction of different water/water mixtures on clastic and carbonate core plugs. It also investigates different formation damage mechanisms associated with water injection. It investigates interaction impact of water mixtures with examined core plug permeabilities.
High Performance Software Computing Enables Accurate Downhole Pressure Predications for Gas Wells
Authors: Al-Hajri Nasser M. , Ureiga Sulaiman , Barghouti Akram 
Published: February 2022

AbstractA reservoir's static bottomhole pressure is an integral component of many reservoir evaluation disciplines. The static bottomhole pressure is normally acquired through gauge measurements; however, this method has disadvantages such as cost and mechanical risk. Accordingly, the ability to accurately estimate the static bottomhole pressure would provide a cost-effective and safe alternative to well intervention. In this work, a new cloud computing method is introduced to predict the static bottomhole pressure of a natural gas well. The method reaps the benefits of available IR 4.0 technologies, namely multi-layered high performance software computing. The utilization of an advanced software codes enabled accurate and timely prediction of gas wells’ bottomhole pressures. This method differs from existing methods by utilizing the apparent molecular weight profiling concept. Based on the inputs of pressure and temperature gradient data, an iterative calculation scheme is applied to produce a well-specific molecular weight profile. This profile is used along with a modified form of the equation of state to perform top node pressure calculations and ultimately predict the static bottomhole pressure for gas wells. The new calculation method was applied on two calculation modes: calibration mode and time lapse mode.In the calibration mode, the static bottomhole pressure is predicted on the same gradient survey used to generate the apparent molecular weight profile. On the other hand, the time lapse calculation mode predicts the static bottomhole pressure after a period of time has elapsed from the gradient survey used to build the molecular weight profile. The top node method was tested rigorously, and the prediction results were found accurate with low error percentages.
Combinational Membrane Technique to Support Low Salinity Water Flooding Lswf
Authors: Sakthivel Manikandan 
Published: February 2022

Abstract
Oil reservoirs comprise layers of sandstone with oil and gas held in the spaces between the grains that make up the rock. Allowing an oil reservoir to produce oil through declining natural pressure results in relatively low recoveries (10 to 30%), therefore most fields inject water (waterflooding sweeps oil towards the producing wells) into the oil-bearing rocks which typically increase the oil recovery by 5 to 10%. This means only 30 to 40 % of the oil in place is extracted and to further increase recovery various enhanced oil recovery (EOR) techniques are required including: gas-lift, polymer flood, steam injection depending on the reservoir and oil characteristics. In some reservoirs membranes are already used for low sulphate seawater injection to minimizes potential scaling or souring issues due to interactions with the formation rocks or water, however, this is for production maintenance rather than EOR.
Waterflooding was first practiced for the purposes of pressure maintenance after primary depletion and displacing oil by taking advantage of viscous forces and has become the most widely adopted improved oil recovery (IOR) technique. Its high availability and simple injection, as well as lower cost and capital investment, are the other key operational and economical features of water flooding.
Historically, little attention has been given to the role of injected water chemistry on the displacement efficiency or its recovery. However, over the past decade, many studies have shown that injecting brine with a salinity in the range of 1000–2000 ppm can affect crude oil/brine/rock (COBR) interactions in a favorable manner to reduce the remaining oil saturation.
Far Field Petrophysics for Saturation Mapping Beyond the Wellbore
Authors: Manuaba Ida Bagus Gede Hermawan , Ghanim Rayan Adil , Bikchandaev Eduard , Taher Ahmed 
Published: February 2022

Abstract
Most conventional logging-while-drilling (LWD) tools acquire real-time measurements from a few inches to a few feet away from the wellbore for lithology, porosity, and saturation evaluation. Deep and ultra-deep resistivity tools were developed primarily for well placement and geomapping applications and can detect resistivity variations further away, in all directions around the wellbore. This article describes integration of deep and ultra-deep resistivity measurements for saturation mapping beyond the wellbore.
Deep and ultra-deep resistivity tools can map multiple formation layers and determine the resistivity of those layers far from the wellbore. Since saturation is dependent on porosity and resistivity, a workflow has been developed to combine real-time shallow measurements with inverted LWD resistivity measurements and logging data from offset wells. The geological model is updated based on deep resistivity measurements, and petrophysical parameters for each layer, combined with inverted resistivity values, are used to derive saturation. Uncertainty is defined based on weighted uncertainty in porosity from offset wells and variation in resistivity across the mapped layers. Azimuthal resistivity measurements were also used to validate the inverted values and reduce uncertainties in cases of boundaries close to the wellbore.
The workflow has been tested on several wells and different reservoirs. Several wells were presented in this study utilizing a combination of shallow and deep azimuthal data along with offset logs. Different layers of different formation characteristics and saturation profiles have been crossed and the data was utilized to validate the mapped saturation values compared to the nearby measurements. The resulting saturation profile provided critical information that enhanced understanding of the reservoir and gave better insight into variation in the far field. Such information is critical for completion-design and well-placement decisions and aligns with the industry's direction toward increased data analytics combining offset wells with real-time data. A continuous improvement of the model is expected as more wells are drilled and the database increases.
Auto-Curve: Downhole Trajectory Automation with Cost Reduction to the Operator by Reducing the Time-to-Target
Authors: Gabriel Shamlan , Brovko Katerina , Ignova Maja , Mantle Katharine , Vie Gilles , Li Ling 
Published: February 2022

Abstract
This paper presents the next level of downhole trajectory automation and control of RSS tools for drilling a consistent curve and placing the well within the given geometrical target. This method transfers the decision-making process to a smart downhole control system that reduces inconsistencies due to human inputs, formation uncertainties and produces an improvement in borehole quality.
Evaluation of Novel Surfactant Based Metal to Metal Friction Reducer
Authors: Farouk Mohammad , Al-Jalal Ziad , Hassan Islam , Marine Hope C. , Al-Hameli Saleem , Al-Abdrabalnabi Ridha 
Published: February 2022

AbstractHorizontal and deviated well architectures are now quite common as they facilitate drainage of reservoir in a cost-effective manner, such architectures introduce a challenging environment for subsequent completions and bottom hole operations performed through Coiled Tubing (CT) mainly due to friction between the coiled tubing string and well casing or reservoir formation rocks.To address this, a variety of techniques have been used over the years to reduce the friction between the metallic surfaces and extend the reach of the coiled tubing string to desired depths.Several Such techniques included-but were not limited to- using a specifically designed CT string (tapered CT strings, Pipe surface smoothing treatments), using mechanical aids (downhole coiled tubing tractors, coiled tubing agitators or vibrators) and increasing lubricity of the annulus fluid through the use of lubricants, there has also been many cases in which multiple techniques have been used at the same time to further extend the CT reach.4The use of lubricants has always been the easiest technique as it does not require investment into equipment which would increase the complexity of the operation in addition to their cost.In this study, we are evaluating the friction reduction performance of an environmentally friendly surfactant-based metal friction reducer which will be called Lubricant A, the chemistry of Lubricant A has been used before in oilfield applications, but the authors believe this is the first time this chemistry is used for lubricity enhancement.We will be assessing Lubricant A performance at room temperature and 170°F to investigate its thermal stability and we will be evaluating its compatibility with common brines used during CT operations, especially at high concentrations of salt.We will also be comparing the performance of Lubricant A to that of a Co-polymer based Lubricant -which will be labeled Lubricanr B- in terms of Coefficient of Friction (CoF) reduction at room temperature and at 170°F.A core flood test has also been performed to investigate the impact of brines containing Lubricant A on reservoir rocks permeability.Based on our lab testing, Lubricant A manages to drop the coefficient of friction (CoF) by 60-70% in most cases and shows relatively high compatibility with different brines at different salt concentrations, outperforming Lubricant B in most cases.Lubricant A has also shown insignificant reduction in permeability during core flood tests, increasing the potential for its use in operations where formation damage might be a concern.