bluuebunny/crossref_metadata_2025 huggingface dataset:
Novel Characterization of Thin Film at Reservoir Fluids Interfaces in Carbonates
Authors: Alotaibi M. B. , Cha D. K. , AlSaleh S. H. , Yousef A. A.
Published: March 2019

The salinity and ionic strength of injection water can make favorable impacts on wettability and oil recovery in different carbonate and sandstone reservoirs. The interaction mechanism between dissolved ions in injection water and reservoir fluids is a key ongoing research area. Most of these interactions occur at the thin film interfaces and so are considered one of the challenges in identifying and understanding the mechanisms. Conventional macro and microscopic laboratory techniques are commonly applied to determine contact angles, surface charges, and coreflooding to measure any incremental increase in oil recovery.

In this paper, advanced sum frequency generation (SFG) spectroscopy is utilized, for the first time, to characterize the chemical structures of molecules at the brine/crude oil interfaces. The change in the chemical structure is perceived with time at a broad wavenumber range from 1000 to 3900 cm−1. Distinct spectral signatures of oil components and water ions are detected for high salinity water (HSW), modified ionic strength water (MIW), and ions-free solutions.

The SFG data is also compared with the previous macroscopic wettability results to predict the components that are highly affected during waterflooding/enhanced oil recovery (EOR) processes. This study brings new insights about understanding the chemical structures at brine/crude oil monolayers and aqueous interfaces. The measured spectra at the interfaces along with the observed signal intensity trends are discussed in terms of composition and structure of organic and inorganic components. For example, SFG results from MIW oil interfaces and has higher spectral intensity at 2860 and 1700 cm−1 wavenumbers when compared with other brines used. These results exactly correlate with the C-H and C=O stretching bonds, which consider the key oil components at the interfaces.

The novelty of this interfacial study can give more ability to understand the reaction mechanisms as altering the ionic strength and salinity of the injection water. Such understanding is also crucial in optimizing the chemistry of injection water and its interaction with oil components and carbonate rock to ultimately alter wettability toward water-wet.
New Model for the Elastic Modulus for Saturated Porous Carbonate Rocks
Authors: Ismail Marwah AL , Morgan Frank Dale
Published: March 2019

The wave velocity is defined theoretically by the Newton-Laplace equation, which relates the wave velocity, V, to the square root of the ratio of the elastic modulus, M, and density, ρ. Therefore, the equation indicates that the velocity is inversely proportional to density. However, the in-situ field measurements and laboratory experiments of compressional wave velocity through different rocks show otherwise, where the velocity is directly proportional to approximately the 4th power of density as stated by Gardner's numerical approximation. To clarify the apparent contrast between theory and observations, a new expression for the elastic modulus, M, is derived using Wyllie's time average equation and the Newton-Laplace equation. The new derived expression of the elastic modulus, M, provides dependence of M on density to approximately the 9th power, which subsequently results with the observed dependence of velocity on the 4th power of density. In addition, Gardner's equation is modified to accurately obtain the velocity over range of densities (from 1 g/cm3 to around 3 g/cm3). The findings are tested on real velocity and density well-log data. The results validate the derived expression of the elastic modulus as well as the generalized form of Gardner's equation.
Computational Fluid Dynamics CFD Evaluation of Laminar Flow of Bitumen-in-Water Emulsion Stabilized by Poly Vinyl Alcohol PVA: Effects of Salinity and Water Cut
Authors: Alade Olalekan , Al Shehri Dhafer , Mahmoud Mohamed , Sasaki Kyuro , Sugai Yuichi
Published: March 2019

Applications of oil-in-water emulsion (O/W) emulsification technology in enhanced recovery and pipeline transportation of heavy oil can be limited by several factors including salinity of the reservoir or process water, process temperature, and water cut. In this investigation, laminar flow of O/W was simulated in a pipeline to investigate the effect of salinity of aqueous phase (NaCl) and water cut on flow characteristics of the fluid. The case was simplified by considering the O/W as a stable, pseudo-homogeneous, single-phase fluid within the conditions operated. Pertinent to the objective of the study, at flow reference temperature, Tref = 30oC, the pressure drop at 30% water cut was 931Pa compared to 84.6 Pa at water cut of 50% (reference working fluid without NaCl). In contrast, the pressure drop was 239Pa, 142Pa, 124Pa, and 82.9Pa at 70000ppm, 40000ppm, 20000ppm, and 10000ppm salinity in the aqueous phase, respectively. In addition, the maximum dynamic viscosity imposed by the fluid, was ≈81000cP at 30% water cut compared to ≈14000cP from the reference fluid. The dynamic viscosity obtained from 70000ppm salinity content was ≈34000cP. Moreover, the results confirm facile application of emulsification technology for pipeline transportation of bitumen from large reduction in pressure drop (99%) regardless of the water cut and salinity.
Metal 3D Printing Applications in the Oil & Gas Industry
Authors: Burns Madison , Wangenheim Christoph
Published: March 2019

Additive Manufacturing (AM) is a set of technologies that has historically found fertile applications in the aerospace and healthcare industries, while adoption in the oil and gas (O&G) sector has progressed slowly. Nonetheless, AM is reaching maturity in this industry as well, allowing for significant innovation. This paper describes how AM has been integrated within the value chain of a major oilfield supplier, highlighting specific peculiarities for each of its business segments. "Fullstream" activities of the oilfield supplier cover the entire O&G value chain, from the exploration of reservoirs and production (upstream) to the transportation and storage of hydrocarbons (midstream), as well as refining and industrial power processing (downstream). AM technologies in this company were originally deployed for rapid prototyping, but they have matured as strategic manufacturing pillars to address the maintenance of equipment of all industry segments within the company. Several manufacturing methods within the AM landscape can be deployed, depending on the technical requirements of the components and the environment in which they operate. O&G equipment end users face several challenges when dealing with spare parts management, such as performance, total cost of ownership, procurement time, inventory levels and obsolescence. From an OEM standpoint, serving a wide fleet with a variety of products and their different versions (with an unpredictable and unstable demand) is challenging. AM is the tool that enables a new way to serve such an installed fleet. The company has already experimented with several applications regarding obsolete spare parts re-introduction through AM, gaining strong benefits (50% +) in terms of cost and procurement time reduction. Consequently, it is important to continue adopting AM to deliver faster outcomes for the customer at first. This, in turn, fosters the development of sound knowledge and references that can then be used to develop further solutions and value propositions for the customers.
Overview of Carbonate Rock Types in the Middle East
Authors: Dernaika Moustafa , Mansour Bashar , Al-Jallad Osama , Koronfol Safouh
Published: March 2019

The complexity and diversity of carbonate reservoirs necessitate having a consistent approach in defining rock types. Core data on a rock-type basis are required as input for modelling reservoir performance. The objectives of this paper are to provide detailed understanding of the controlling factors in rock typing and to develop a unique rock-typing approach that can apply to carbonate reservoirs in the Middle East region.

More than 1,000 core plugs were studied from seven different carbonate reservoirs. The plugs were carefully selected from 15 wells to represent the primary property variations along the cored intervals. The data set available included laboratory-measured helium porosity, gas permeability, thin-sections, and high-pressure mercury injection capillary pressure (MICP). Plug-scale X-ray computed tomography (CT) imaging was acquired to help ensure the samples were free of induced fractures and other anomalies that can affect the permeability measurements. Rock textures were analyzed in the thin-section photomicrographs and were classified based on their content as grainy, muddy, and mixed. Special attention was given to the diagenesis effects, mainly compaction, cementation, and dissolution. Porosity was defined as interparticle, intercrystalline, moldic, intraparticle, or vuggy.

The texture information was plotted in the porosity-permeability (poro-perm) domain and was determined to produce three distinct poro-perm relationships. Each texture provided an unique poro-perm trend. Rock types were defined on the poro-perm trends and showed a strong link to diagenesis and capillary pressure (Pc). For each poro-perm trend, the rock types were distinguished by detailed Dunham textures and different degrees of diagenesis. The detailed textures and diagenesis were correlated reasonably well with the poro-perm data and MICP, hence providing robust rock types.

A new rock-typing approach was successfully applied in different carbonate reservoirs. The poro-perm cloud from the different reservoirs was resolved into trends and ranges based on textures and diagenesis. Common controlling factors were observed, which can help produce data analogues along more reservoirs in the region. The texture-diagenesis-based rock types provided more insight into the effects of geology on fluid flow and saturation. Geological textures were derived along the cored intervals and provided upscaling options for permeability and rock types in the reservoirs.
The Evolution of Light Oil Thermal Pilots in Mauddud Reservoir from Lab, Simulation to Pilot Scale
Authors: AL-Muftah Ali , Mansoor Mohamed , AlOwainati Ebrahim
Published: March 2019

The Light Oil Steam Flood (LOSF) is proposed to increase the recovery from Mauddud reservoir in Bahrain Field. Mauddud has been on gas injection since 1938, yet residual oil saturation is still high in the gas cap due to its oil wettability. Several core lab studies were conducted confirming the high oil saturation in the gas cap. Steam flood core lab experiments were conducted recently and confirmed the residual oil saturation could reach to less than 10%. The thermal pilot project in Mauddud has gone through the following stages: The first pilot started in 2013 and operated for 2.5 years: It has one horizontal well in the gas cap, one vertical producer, four vertical injectors with three Temperature Observation Wells (TOWs) clustered around one of the injectors.First pilot performance was assessed and confirmed in reducing the residual oil in the gas cap by distillation and wettability alteration.Second pilot was designed and initiated in 2016 to assess the economic viability for full field expansion.

Throughout these stages, production monitoring, logging, core studies and simulation studies have been carried to understand the LOSF mechanisms to increase Mauddud recovery from the gas cap.

This paper presents the evolution of pilot design concepts and simulation of the thermal recovery in Mauddud. It also study and assess the well configurations and pilot operating strategies designed for the thermal pilots. A sector model was constructed and calibrated, then used to select a well concept for the LOSF pilots. Seventeen different pilot concepts were considered during the selection process. The well configuration and operating strategies were driven to observe a quicker steam response in the first pilot. A number of sensitivities were conducted to develop a better understanding of the effects of the various reservoir factors.

A comprehensive study was then carried out to recommend a phase development approach for full-scale field development and establish a methodology for a full-field LOSF forecast. Full Field compositional model was built in thermal reservoir simulator and was then successfully history matched with seven components equations of state (EOS). A phased development approach was then proposed for full-scale field development. The initial development will focus on the mid-dip areas with higher remaining oil saturations and a thicker oil column. After establishing production in the mid-dip flanks, development could proceed to the crestal areas, which have lower oil saturations and would likely result in higher steam/oil ratios (SORs).
Well Success – An Interdisciplinary Evaluation Parameter
Authors: Gamperl Florian
Published: March 2019

The paper presents an approach that integrates various success criteria that the different disciplines involved in planning a well have in mind during the planning phase. Apart from purely economic factors, the "value of information" is considered in this approach, which requires a "proxy". An approach has been developed based on a 26 well drilling campaign, which integrates various aspects under which a well can generate value for a company, into a single "well success indicator". This key performance indicator (KPI) flexibly weighs various factors representing the different disciplines involved in planning a well; the weight factors can easily be adjusted to the needs and requirements of companies or projects. The paper will discuss the approach taken to develop the system and the prerequisites for applying the system to any well.

While in some wells, the evaluation based purely on economic criteria like additional recoverable oil or increased production rates, yields the same "success" as with the more detailed approach. However, for most wells, significant differences can be observed. A factor is that the usual approach does not consider information in the same way – although that can reduce the risk for future wells, and as such save money. Even if this information is not translated into monetary value, it can be appreciated as a part of goals set by each discipline. If such goals are well-defined, they can be used to evaluate the well success – which is more than just the project economics. It can also be seen that poorly chosen weighting factors, can distort the view on a project significantly.
The Impact of Automated Fault Detection and Extraction Technology on Seismic Interpretation
Authors: Al-Maskeen AbdulMohsin A. , Ali Sadaqat S. , Khan Muhammad
Published: March 2019

3D wide azimuth seismic data plays a vital role in fault interpretation, which has significant importance during exploration and development stages. Interpreting faults in 3D seismic data is one of the most time consuming and challenging process especially when dealing with poor quality seismic data. This paper provides a complete workflow and example of its application from seismic pre-conditioning to fault detection and extraction automatically based on published concepts by Dave Hale. With recent advancement in computer technology, multi-threaded algorithms and data driven methodologies, geoscientists can automatically detect and interpret virtually all discontinuities in seismic data in an efficient manner.

This workflow involves random and coherent noise suppression, seismic likelihood attributes generation to enhance the discontinuities, detect faults and extract them from thinned fault likelihood volume. Unlike other fault tracking methods that use local seismic continuity attributes, such as coherency, this automated method incorporates aspects of Hale's fault-oriented semblance algorithm, which highlights fault planes with unprecedented clarity.

This methodology has been successfully applied on complex faulted reservoirs. It contributes to the extraction of detailed discontinuity information (minor and major) from 3D seismic data. The traditional manual interpretation step that follows the detection of faults was time consuming and error prone. Automated fault interpretation improves the fault tracking accuracy, consistency and significantly reduces fault interpretation time in prospect generation. This workflow will optimize and reduce uncertainty associated with the seismic fault interpretation process.
Modeling and Simulation to Produce Thin Layers of Remaining Oil Using Downhole Water Sink Technique for Improved Oil Recovery. A Case Study in Greater Burgan Field.
Authors: Al-Fadhli Wuroud , Kurma Ravi , Kovyazin Dmitry , Muhammad Yaser
Published: March 2019

The case study describes a modeling and simulation study of an inverted ESP completion to address three fundamental objectives. A) Increasing the ultimate oil recovery in the massive sands of Cretaceous age in Greater Burgan field by managing water production B) Mitigating the rapid water coning conditions in this high permeable water drive reservoir and C) Designing an optimal operating strategy with Downhole Water Sink (DWS) to control water production and manage well performance. A 2×2km sector was carved out from the full field geological model with 12 wells including the study well. The study well was producing at high water cut at the time of the study. All static properties were updated, and the model was history matched for production, pressure and saturation. Several sensitivity runs were performed, and prediction scenarios were run for 5 years to observe well production behavior in time. The well model was setup with an inverted ESP between straddle packers to produce water from below OWC and inject into bottom reservoir with a production string above to produce from the oil zone. This setting ensured a reverse oil cone being generated from below OWC in the reservoir under production. The aquifer model was finite in size enabling bottom water influx. Simulation results showed that implementation of DWS technology made the water production reduced by 18% during five years with an increase in oil production of nearly 25% in the study well. To maintain continuous well offtake rate, a range of water rates to be produced and injected to bottom reservoir have been studied. Several iterative runs were made to investigate the best completion interval and injection & production rates. The profiles of oil water interface near well bore indicated good reduction in the cone height as compared to normal completion. The results also showed significant improvement in oil recovery within the drainage radius of the well from the simulations. Simulation results provided good understanding of the saturation change near well bore area under different production rates. Prediction runs were made for sustainable oil production under natural flowing condition and the conditions to switch over to production under artificial lift. Production of thin layers of remaining oil from within high permeable massive Burgan middle sands has been a high concern due to very high water cuts because of coning. The study results have provided encouraging option with DWS technique to improve recovery from the reservoir.
Laboratory Evaluation of Weighting Materials for Ultra-High Density Oil-Based Drilling Fluids in Ultra-HPHT Wellbore Applications
Authors: Li Qinghui , Zhu Jinzhi , Li Shaoxuan , Zhang Shaojun , Hisham Nasr-El-Din , Ren Lingling , Li Jiaxue , Al-Mujalhem Manayer
Published: March 2019

Global energy demand has driven the petroleum industry to develop hydrocarbon resources from extremely harsh formations which contain ultra-high pressure and temperature (HPHT) reservoirs. Ultra-high density drilling fluids are critical to successful drilling and completion practices in all of these wells. In this paper, potential weighting materials were systematically evaluated and screened to accomplish an ultra-high density oil-based drilling fluid system (19.62 to 22.12lb/gal) aimed to utilize in ultra HPHT conditions (>30000psi and >410°F).

Several potential high-density weighting materials were evaluated in the laboratory conditions. Basic properties (pure density, particle size/distribution, surface area etc.) were evaluated and compared. Special treatments were conducted to optimize the properties of weighting materials. HPHT filtration tests under static and dynamic conditions were conducted at higher than 410°F and 300 psi. Real cores with an average porosity of 19% and an average permeability of 50 mD were used in the filtration tests. Rheological properties, sag tendency, the volume of filtrate, and the filtrate cake characterization of oil-based drilling fluids were measured before and after heating at 410°F for 16 hours.

Results revealed that ultra-micro manganese and ilmenite complex after suitable surface treatment could act as an ideal weighting material than ultra-pure barite or other materials, which could fail in rheology and sag controlling measurement with such high temperature and density. The viscosity and filtration analysis confirmed the stability and reliability of this novel ultra-high density oil-based drilling fluid.

This study developed a challenged drilling fluid system under critical testing states, as well as established a systematical laboratory evaluation and screening procedure of weighting materials for ultra-deep wells and contributed recommendations on how to utilize it in the fields.
Effective Waterflood Management of a Giant Clastic Upper Burgan Reservoir Leads to Tripling of Production, Raudhatain Field, North Kuwait
Authors: Al-Hajeri Nasser , Chellappan Suresh , Al-Mufarrej Mishal
Published: March 2019

In the current and future scenario of increasing demand for hydrocarbons, Multi-Disciplinary Integrated Reservoir Management team is the key to achieve maximum production rates and ultimate recovery. In Raudhatain Upper Burgan reservoir production started in 1959 with initial reservoir pressure of 3850 psi. Decline in reservoir pressure with sustained rate of production indicated weak aquifer support and initiated water injection during the year 2001 with three flank injectors. Production rate was sustained at 30 to 35 MBOPD for long time and it was decided that to go the next level of production and to meet KOC's strategic production target.

Various alternative pressures – production plans were scrutinized by the multi-disciplinary team consists of Geologists, Reservoir Engineers, Petrophysicists and Petroleum Engineers and identified bottlenecks, constraints and action plan to address the problems and to accelerate the production. Some of the bottlenecks to accelerate the production were decreasing pressure, unavailability of required volume of water for injection, delay in commissioning of effluent water injection facility and low productivity of flank wells with viscous oil. The integrated Reservoir management team initiated number of projects to increase the productivity like Paradigm shift in drilling practice by way of drilling Horizontal, Multilateral wells and completing with ICD's for better production and injection sweep efficiency. Liquidated the sick wells with no potential in any other Reservoirs (Multiple Reservoirs) are identified for Horizontal Sidetracking to sweet spot areas. Decreasing Reservoir pressure and Voidage Replacement Ratio has been addressed by changing the water injection strategy and aligning the injectors in right areas.

The results were rewarding as the production rate doubled from a sustained level of 35 MBOPD to more than 70 MBOPD in a span of 3 to 4 years. The initiatives taken to convert the producers to injectors resulted in increased water injection volume and doubled the Voidage Replacement Ratio.

This paper presents the details of Integrated Reservoir Management team efforts and what are the initiatives and strategic actions taken by overcoming the current constraints to double its production. It discusses the effective Reservoir Management of a mature oil field to enhance and accelerate production.
Characterization of Iron Interaction with Viscoelastic Surfactant VES-Based Stimulation Fluid
Authors: Afra Salar , Samouei Hamidreza , Nasr-El-Din Hisham A.
Published: March 2019

Viscoelastic surfactant (VES) have been successfully applied as acid-diversion fluids. However, high temperature, interaction of VES and Fe(III), addition of alcohol-based additives, and chelating agents all interfere with the apparent viscosity of the VES-based acid and reduce its efficiency. In the present study, the interactions of Fe(III) with a new type of VES-based acid system, which can be applied effectively for diversion at high temperatures, were characterized.

Viscosity measurements were conducted on the VES-based acid in the presence of different concentrations of Fe(III) to characterize the rheological properties of the VES-based acid. The results showed that addition of Fe(III) in the concentration range of 2000 to 10000 ppm, lead to increase in the viscosity of the VES-based acid even at room temperature. Higher concentration of Fe(III) (more than 40000 ppm) lead to phase separation of VES out of the acid and formation of a brown gel-like material, which is considered as the main cause of formation damage by VES-based diversion fluids. IR spectroscopy was employed to understand the nature of the VES interactions with Fe(III) in live acid conditions. Also, UV-vis spectroscopy was conducted to determine stoichiometry of the reaction as well. The results show that interaction of amide part of the VES with Fe(III) that results in screening the repulsion forces between surfactant head groups and formation of wormlike micelles is the primary reason for increase in the viscosity.

To the best of authors' knowledge, although Formation damage caused by VES-based system due to iron contamination were reported previously both in the laboratory studies and field applications, the present paper is the first mechanistic attempt to characterize and understand the nature of a VES-based system interaction with Fe(III) as the driving force for the occurrence of reported formation damage. The findings of the present study can be utilized to further investigation of the effects of additives on the performance of VES-based systems.
Case Study Demonstrating the Estimation of Depth-Continuous Formation Anisotropy with Application to Geomechanics and Seismic Velocity Model Calibration
Authors: Hornby Brian , Wang Ruijia , Collins Mark , Kim JoonShik , Confer Rachel
Published: March 2019

This paper presents a case study in which new methods that use full-waveform sonic data are applied in an unconventional well setting to determine depth-dependent elastic anisotropy of formations penetrated by the well and estimate parameters of interest. The study objectives include the following: Estimate Thomsen's shear anisotropy parameter γ in an unconventional well that penetrates fast formationsUse rock physics and other approximations to further estimate a complete vertical transverse isotropic (VTI) elastic tensor at each depthCompare results with ground truth in terms of dynamic and static core measurementsUse these results to derive anisotropic geomechanical parameters for well completion and fracture treatment design and to compute upscaled seismic-equivalent elastic anisotropy for the calibration of anisotropic seismic velocity models

Formation speeds in this well were extremely fast, typical for unconventional shale reservoirs, which created a challenging environment for estimating VTI Thomsen's parameter γ because of the extreme sensitivity of the inversion to the accuracy of the borehole fluid slowness estimate. The key to the study's success was development and application of methods to invert for a depth-dependent mud slowness curve. This allowed for much more accurate inversion of the VTI parameter γ than the conventional method that uses a constant mud slowness value. In addition to enabling a more accurate inversion, it is observed that the mud slowness curve not only varied with depth [likely because of pressure/temperature (P/T) changes and possible settling] but also reflected quite different properties across a drilling fluid pill that was placed around the reservoir formations. This analysis provides an additional benefit for drilling engineers because the mud slowness curve tracks mud property changes in the well and can determine the actual location of the drilling fluid pill after placement and stabilization.

Additional work estimated the depth-continuous elastic tensor and geomechanics (anisotropic Poisson's ratios and Young's moduli necessary for computing horizontal stresses) for well completion and fracture treatment design. Seismic-scale properties were estimated using anisotropic Backus averaging for the calibration of the anisotropic seismic velocity model for prestack depth migration.
The Effect of Elevated H2S on Corrosion Behaviour of API 5L X65 Carbon Steel in High Partial Pressure CO2 Environments
Authors: Abas Ahmad Zaki , Mohammed Nor Azmi , Suhor Muhammad Firdaus , Ahmad Rusli Ahmad Mustaza
Published: March 2019

The corrosion behaviour of API 5L X65 carbon steel was investigated under high pressure carbon dioxide environments, containing elevated hydrogen sulfide, to simulate the condition of high carbon dioxide-containing natural gas subsea pipelines. It was systematically studied under high pressure carbon dioxide (120 bars) with a variation in other key parameters (hydrogen sulfide concentration and temperature). The corrosion rates were tested using High Pressure and High Temperature (HPHT) autoclave and measured using the techniques such as linear polarisation resistance (LPR), potentiodynamic sweep measurements, iron count, weight loss (WL) and electrochemical impedance spectroscopy (EIS). The surface morphology and the composition of the corrosion product layers were analysed using Infinite Focus Microscope (IFM), X-ray diffraction (XRD), Scanning Electron Microscopy (SEM) and Energy Dispersive X-ray Spectroscopy (EDS). The results showed that in the CO2- saturated water phase, the addition of 2000 ppm hydrogen sulfide (H2S) instantaneously decreased the corrosion rate of carbon steel API 5L X65 at both 25°C and 80°C. The surface morphology and the composition of the corrosion product layers reveal the formation of mackinawite. The inhibitive effect of hydrogen sulfide at elevated concentration was observed and contributed to the significant reduction in corrosion. The effect on corrosion was despite the fact that water chemistry equilibrium was unchanged with the presence of elevated hydrogen sulfide.
DrillCAM Seismic System to Aid Geosteering and Drilling Optimization
Authors: Hemyari Emad , Bakulin Andrey , Silvestrov Ilya , Liu Yujin
Published: March 2019

As the number of new exploration and development wells continues to increase, guiding the bit while drilling in real time is becoming one of the most requested technologies. Seismic-while-drilling may enable accurate prediction of high-pressure zones, fractures and cavities, coring points, target depths, and geosteering in high-quality reservoir zones to optimize drilling decisions and reduce costs. A fully integrated real-time system to map and predict ahead of the bit and geosteer in high-quality reservoir zones is presented, showing application of seismic while drilling (SWD). We call this technology DrillCAM.

Recent enabling technological advances were made in wireless high-channel recording, signal enhancement and imaging algorithms, as well as high-performance computational resources that are easily deployable to the field. Such technological advances open a completely new set of possibilities for real-time drill bit guidance and navigation. One key enabler for DrillCAM is the use of wireless seismic receiver stations. Compared to conventional cabled geophones and cableless nodal systems, wireless receivers can provide real-time recording and transmission without the need for extra equipment for data retrieval, flexible receiver spacing and areal coverage. This, in turn, results in a flexible lightweight system for easy mobilization and ultralow power consumption for extended battery life.

We show a carefully designed field data acquisition experiment using the drill bit as a downhole seismic source and a large number of seismic receivers at the surface. The wireless receivers are arranged in flexible geometries that adapt to target bit depths. Using dedicated sensors, the bit signature (pilot signal) is recorded using high-frequency surface and downhole accelerometers. The system integrates surface seismic recordings and surface noise recordings with pilot signal recordings. The initial field experiment is conducted on a nearly vertical onshore well. This experiment demonstrates the feasibility of an integrated DrillCAM SWD system.

The paper presents the motivation, objectives, numerical studies, and first field test of a novel integrated real-time SWD system. Not only does such a system detect bit signals while drilling, it also validates these signals against other measured data and drilling activities.
Cost-Effective Sour Management in Mixed Production Systems
Authors: Chakraborty Soma , Lehrer Scott , Jani Jagrut , Ramachandran Sunder
Published: March 2019

Sour production from offshore and land-based wells causes hydrogen sulfide (H2S) release during downhole and topsides operations. Improper handling of H2S can lead to serious environmental and safety concerns as well as numerous corrosion and compliance issues. Consequently, H2S can add significantly to the total cost of well operations. The application of efficient H2S management technologies can reduce environmental and safety concerns, enable the use of lower-cost materials, and comply with H2S specifications. To remove H2S from mixed production applications, several chemistries are commonly used. The most common are triazines, glyoxal, and metal-based chemistries. Although each can be effective to a certain extent, these technologies have issues with efficiency or they can create serious side issues. The reaction of triazines with H2S in mixed production is highly inefficient and it creates scaling. Glyoxals suffer from poor efficiency, thermal instability, and corrosivity. The metal-based chemistries are the most efficient in mixed production, but in certain application regimes they can create serious solids and emulsion issues. These challenges can increase CAPEX and OPEX as well as lead to significant downtime and lost production. To overcome issues with currently used chemistries in mixed sour production, extensive research was conducted to identify chemistry that would efficiently remove H2S while minimizing negative side effects.

Systematic evaluation was performed for a series of chemistries to compare the scavenging efficiency, with a special emphasis on mixed production systems. Focus was also given on studying the associated side effects like emulsification tendency, scaling tendency, etc. to ensure the chemistry had no/minimal side effects seen by the more conventional chemistries. A high-throughput lab technique is presented that was designed to mimic scavenging tendency in sour mixed production environment. A continuous gas flow testing technique that helped study the reaction kinetics is also described.

Laboratory and pre-field results proved the efficacy of the new non-MEA, non-triazine chemistry in mitigating H2S in upstream, midstream and downstream applications while being especially efficient in mixed production systems. Laboratory testing proved the chemistry to be highly efficient compared to triazine in mixed production systems. Results also indicated the chemistry is non-emulsion forming and has very little scaling tendency. Testing conducted in the field demonstrated that the new chemistry cost-effectively removes H2S and meets the operator specifications.

The novel, non-triazine scavenger technology has significantly better performance than triazine, no emulsion concerns, acceptable HSE, non-corrosive effects, and less downstream concern than MEA triazine or metal-based scavengers. The new and differentiated chemistry reduces CAPEX and OPEX, drives productivity, improves reliability and reduces non-productive time.
Acoustic Characterisation of Phase Inversion in a Water-Oil System
Authors: Ahmed Yusuf , Arsalan Muhammad , Ahmed Talha , Noui-Mehidi Mohamed Nabil
Published: March 2019

The present paper is concerned with an experimental study of the acoustic signature of phase inversion in an oil-water mixture system. The system studied was used to correlate the process of phase inversion with the acoustic field generated during the two fluid mixing. The experimental results revealed that the relation between the acoustic fields produced by a water continuous dispersion and the phase inversion has a clear and different signature from an oil-continuous system using a batch mixing system. This dynamical characteristic of the phase inversion phenomenon could be of use in practical systems to detect phase inversion when it occurs based on the acoustic field measured in the subject process.
Deep Learning Method for Latent Space Analysis
Authors: Wallet Bradley , Ha Thang
Published: March 2019

Seismic attributes are a well-established method for highlighting subtle features buried in seismic data in order to improve interpretability and suitability for quantitative analysis. Seismic attributes are a critical enabling technology in such areas thin bed analysis, 3D geobody extraction, and seismic geomorphology. When it comes to seismic attributes, we often suffer from an "abundance of riches" as the high dimensionality of seismic attributes may cause great difficulty in accomplishing even simple tasks. Spectral decomposition, for instance, typically produces 10's and sometimes 100's of attributes. However, when it comes to visualization, for instance, we are limited to visualizing three or at most four attributes simultaneously.

My co-authors and I first proposed the use of latent space analysis to reduce the dimensionality of seismic attributes in 2009. At the time, we focused upon the use of non-linear methods such as self-organizing maps (SOM) and generative topological maps (GTM). Since then, many other researchers have significantly expanded the list of unsupervised methods as well as supervised learning. Additionally, latent space methods have been adopted in a number of commercial interpretation and visualization software packages.

In this paper, we introduce a novel deep learning-based approach to latent space analysis. This method is superior in that it is able to remove redundant information and focus upon capturing essential information rather than just focusing upon probability density functions or clusters in a high dimensional space. Furthermore, our method provides a quantitative way to assess the fit of the latent space to the original data.

We apply our method to a seismic data set from the Canterbury Basin, New Zealand. We examine the goodness of fit of our model by comparing the input data to what can be reproduced from the reduced dimensional data. We provide an interpretation based upon our method.
Streamlining and Automating Geological Requirements for Development Wells
Authors: Abouhenidi Malak , Fadul Reham , Tadamarry Faizuddin , Rahdi Yassir
Published: March 2019

Development wells are drilled for different purposes that varies based on the business needs. Some scenarios can be for flowing production, power water injector, gas, or to monitor the performance of a well. Coupled with the technology in wellbore drilling activity and the artifacts that are required for the workflow approval. Through evolving technology, the system captures every step of wellbore activity to address the business needs and streamline the approval process. Data fuels Industry Revolution (IR) 4.0 and effective data analytics is the prerequisite for successful implementation of digital enterprise applications.

Well approval is an in-house developed system embedded in Petrel application for reservoir characterization geologists. It standardizes well approval documents across the organization. The geologists may generate multiple well approval documents in case a change in the plan has occurred. Different scenarios require geologists to replace the plan that reflects the well approval document. Planning is the main pillar in the process of Well Approval, and automating the planning part simplifies the well approval process. The system automates the generation of three critical documents. First, Integrated Requirements (IRs), which consists of logging and threshold values for each hole section generates the reservoir amplitude impedance and porosity maps, and finally allows the geologist to capture seismic maps from 3D geological models. Second, Prognosis geological horizons details. Third, Location Evaluation. The backbone of this system is that it is integrated with different back-end systems such as corporate database, Petrel, Openwork and Geolog. In addition, geologists are not required to select the offset wells. The offset wells algorithm designates the wells for geologies based on specific criteria that is built in the system such as reservoir type and dynamic log selection. The system tackles both environments 2D and 3D based on the giving parameters such as facie. The system is able to detect the environment and prepare the documents accordingly.

Since the system is aligned with the business pattern for well approval process, it significantly improves the time required to create these documents from two to three (2-3) days to less than 1 hour (90%) and the data will be readily available through Real-Time Operations Center Knowledge System (also known as ROCKS) for further analysis and reporting.
First Successful Massive Hydraulic Fracturing Treatment Unlocks Reservoir Potential 4 Fold: Case Study from Tight Gas HPHT Field in Southern India
Authors: Sharma Vinit , Negi Anil
Published: March 2019

Hydrocarbon production from high-pressure/high-temperature (HPHT) unconventional and tight gas reservoirs is challenging the industry with its increasing complexities, changing geological and reservoir dynamics with deeper depth and temperature, stimulation techniques and the strategic cost investment. The southern basins of India offers a complete set of such variability, uncertainties and challenges that demand a more synergic approach and effort to produce. Field X is a deep HPHT tight gas field in the Krishna Godavri Basin with a permeability of < 0.1 mD and a porosity of 10-12%.

Prior attempts of hydraulic fracturing were carried out in the field with limited success. Small volume jobs were pumped, yielding low-permeability coverage, with just an initial production gain and no sustainability on the gas production increase. Frac fluid recovery was an additional concern because of the tight nature of the reservoir.

This paper discusses the integration of log data, lab/fluid testing, production modelling, and fracture diagnostics that were used to design and optimize the massive hydraulic fracturing treatment. The technical methodology implemented during design, execution and evaluation phases for fracturing an HPHT tight gas well is discussed, including how the various risks were mitigated and the technical challenges were overcome. Finally, this paper elaborates the successful execution of the hydraulic fracturing treatment wherein ~332,000 lb of proppant were pumped–the largest in this field in a single stage. Initial production was enhanced by four times after the hydraulic fracturing. With the success of the hydraulic fracturing treatment execution strategy, fracturing operations were planned for the future field development wells to realize the true potential of the reservoir for increased and sustainable production.
The Revelation of Minor Reservoir Opportunity: Realizing Low Resistivity Contrast Reservoir Play Type in Baram Delta Basin East Malaysia, Thru REM Log Enhancement and Comprehensive Water Salinity Analysis
Authors: M Shah Jamari , Md Dahlan Nur Athirah , Kamarulzaman M Naquib , C A Razak M Amin , Jamaluddin Junirda
Published: March 2019

Low Resistivity low contrast (LRLC) reservoirs were normally disregarded due to high water saturation and classified as tight sand. LRLC reservoir defined as Pay that has low resistivity contrast between sand and adjacent shale due to presence of conductive mineral or fresh water. Hence, this paper will transform the standpoint by demonstrating values and potential reserve addition underneath LRLC reservoir which proves that it could contribute equally as the conventional reservoir and realizing potential reserve growth.

HY field located in Baram Delta Basin East Malaysia has been producing for more than 40 years and classified as lower coastal plain to coastal environment. The reservoir is loosely consolidated, fine to very fine sandstone and interbedded with shale. Z reservoir (Low Resistivity contrast reservoir) initially identified as gas-bearing reservoir with fresh water salinity of 2k-4kppm. Plus, difference in resistivity values between sand and adjacent shale only separated by ~3ohmm .Due to these claims, there is no Oil interpreted below the gas level and been neglected for years.

A robust water salinity investigation supported with the geological point of view and water sample taken at the wellhead, Project Team proposed the water salinity should be 10k-15k ppm which is more saline than previously assumed. Revision in water salinity value has led to pinpoint Z reservoir as Oil bearing reservoir and recover estimated ~200 ft Pay of Oil column in Z reservoir.

An appraisal well was drilled for data gathering and exploring potential in the deeper sections, hence serve as a platform for further petrophysical evaluation in the Z reservoir. As a result, Project team managed to take Oil sample and Oil gradient for Z reservoir. In addition, PVT lab result showed the oil sample taken having similar fluid property as the produced oil in the major reservoir. Based from the existing static model, potential additional of recoverable reserves was calculated around 20 MMstb for the Z reservoir. This has been an eye opener for the team to give an extra attention and emphasis on the true potential beneath the LRLC reservoir.