bluuebunny/crossref_metadata_2025_split huggingface dataset:
Generating Electricity Using Co-Produced Brine from Oil & Gas Wells Evaluating Prospect in Mehsana Asset North Cambay Basin Gujarat
Authors: Vajpayee Mudit , Martolia Ramchandra Singh , Chanchlani Kuldeep , Mehta Mohit , Chauhan Arjun , Sodani Anurag 
Published: November 2016

Abstract
Historically, the co-softhyphen;produced hot water has been an inconvenience and a disposal issue for oilfield operators. This paper focuses on brine or coproduced fluids (hot aqueous fluids produced during oil and gas production) as a potential source for electricity generation, which could be produced from the thermal energy available in the produced fluid. Oil and Gas (O&G) industry today is in possession of thousands of established wells with known temperatures and flows which can be used for producing emissions-free and cost-competitive electricity using binary cycle units.
Power generation from coproduced fluids using a binary-cycle power plant is underway at the Rocky Mountain Oilfield Testing Center in Wyoming and being considered in locations in Texas, Louisiana, Florida, and Arkansas. Although currently there is no electricity generated from coproduced fluids in India, various studies, suggest that the oil and gas fields in the Cambay Basin basin have a promising geothermal gradient of 35-40 °C/km, while (Chakravorty et.al, 2008) reports around 88% water cut for production from Jhalora Oilfield in Mehsana Asset, North Cambay Basin. This combination of favorable geothermal gradient and large volume of water produced is promising for electricity generation from these coproduced fluids.
In this paper, we studied and collated data of Jhalora Field in Mehsana asset of Cambay Basin for coproduction electricity generation and attempt to provide an estimate of the coproduced-water-electricity-generation potential of that field using two different approaches.
The most significant parameters to economic viability for such a project include reservoir temperature as well as total fluid production rate. The reservoir temperature of Jhalora Field is 90-100°C and with produced water flow rate of 5096m3/day, it is a suitable candidate for application of this technology.
Central Java Hydrocarbon Potential: North Serayu Petroleum System from Source to Trap Based on Geology, Geochemistry, and Geophysics Analysis
Authors: Saerina Anisa N. , Romario Imam F. , Nugroho Hadi 
Published: November 2016

Abstract
North Serayu basin is Java Tertiary sedimentary basins that is formed due to back arc basin and the sedimentary fills was begun in Eocene. The sediments ranged from terrestrial environment until the deep marine controlled by gliding tectonic. Oil seepages are found in some areas such as Karangkobar, Majalengka, Suruh, Klantung, Sodjomerto, and etc. This research was conducted with the aim of revealing the existence of hydrocarbons in North Srayu basin and its petroleum systems.
This study focused on surface manifestation, stratigraphic cross-section measurement, and analysis of the geological structures to determine subsurface. In addition, petrographic and geochemical analysis of rock and oil samples to determine chemical and physical properties. Measuring stratigraphy at several places in Kali Tulis, Kali Worawari and Kali Desel which located in Banjarnegara, Indonesia. Geochemical analysis of rock samples of Totogan and Worawari Formation, oil seepage samples in Klantung and Karangkobar to provide the value of carbon content, and correlating the characteristic of oil and rocks. AMT measurements in Cipluk Field with to determine the subsurface condition and petroleum system hypothesis.
Based on the measuring stratigraphy at several places in Kali Tulis, Kali Worawari which located in Banjarnegara composed by Worowari Formation which deposited on shallow marine environment and Kali Desel composed by Rambatan Formation which deposited on the slope of deep marine environment with turbidity system. Geochemical analysis of rock samples of Totogan and Worawari Formation has a TOC value of 1,42% with Tmax 405 °C and Rambatan Formation TOC value is 0.99%, Tmax 449 ° C, classified as Type III kerogen. Oil seepage samples TOC value is 1.3%, type III kerogen and considered quitely mature. AMT measurements in Cipluk Field showed two characters of resistivity, resistivity &gt;1000 ohm meter indicate homogeneous folds, interpreted as Merawu and Penyatan Formation, resistivity &lt;1000 ohm meter interpreted as Banyak, Cipluk and Kalibiuk Formation (Handayani, 2010). Oil to rock correlation represent the similarity of organic facies, indicated the Worowari and Rambatan formation potential as a source rock. Merawu dan Banyak Formation was interpreted as a potential reservoir, Cipluk and Banyak Formation as the cap of the petroleum system. Migration and trapping system through the toe thrust faulting patterns controlled by the gliding tectonic.
This research objective was to provide the new information about the North-Srayu Basin petroleum system enigma. Previous publication explained the abundant oil seepages in North-Srayu area, the potential source rock, and the potential petroleum system, but none of them explained about the geochemical analysis and conducted it with structural geology. This Paper collect all of the interpretation before and provide the best possibility of North-Srayu Basin petroleum system.
The Application of ANN Artificial Neural Network to Pipeline TOLC Metal Loss Database
Authors: Silakorn Passaworn , Puncreobutr Taneth , Rakthanmanon Thanawin , Punpruk Suchada , Chanvanichskul Chatawut 
Published: November 2016

Abstract
The major corrosion problem of pipelines in the Gulf of Thailand is TOLC (Top of Line Corrosion). To accurately predict TOLC is very challenging and a current TOLC simulation program cannot generate accurate prediction. ANN (Artificial Neural Network), which was reported to successfully predict TOLC, has been being applied to intra-field pipelines in the Gulf of Thailand of the company with the objective to determine specific TOLC modelling to get more accurate metal loss prediction.
ANN process basically consists of data preparation, network design (architecture), weighted modification (iteration of learning and validation) and result analysis. Parameters for corrosion rate calculation are used as the input of the architecture. RMSE (Root Mean Square Error) calculation is used to measure the accuracy of the model, compared to the real metal loss. The prediction model is finally verified by predicting other pipelines whose data have not been used in the process.
With the application of ANN on 3 pipelines in the first phase, ANN could generate a model that accurately predict TOLC for all of them. Results indicated that RMSEs resulted from ANN were better than those from the simulation program from 2.8 to 6.5 times. The model could also predict quite accurately (visually) the other 2 pipelines which have not been used in the process. Subsequent phase of the project (phase 2) has let ANN learn and develop TOLC prediction model based on 19 data samples of 12 pipelines. With more data, ANN now can generate more accurate TOLC prediction model for company. Also, extended input parameter envelopes expand the limitation of ANN prediction. These would finally allow ANN to accurately predict metal loss for both existing and new pipelines within the same asset.
Finally, the ultimate goal is to reduce pipeline cost. With accurate TOLC prediction and with more confidence in TOLC characteristics, cost of materials can be lessened by the reduction of corrosion allowance of the pipelines.
Thermo-Mechanistic EOR Process Modelling in Deploying Low Salinity Hot Water Injection Under Carbonate Reservoirs
Authors: Lee J. H. , Jeong M. S. , Lee K. S. 
Published: November 2016

Abstract
The potential of emerging low salinity water injection (LSWI) on heavy oil carbonate reservoirs has been reported with experimental studies. Wettability modification phenomenon by LSWI has been believed to be enhanced oil recovery. Temperature-dependent geochemical reactions including aqueous reactions, ion-exchange, and mineral dissolution contribute to the phenomenon. While LSWI has potential to recover residual oil, substantial oil has still been remained in reservoir due to high viscosity. Hot water injection is the economic enhanced oil recovery (EOR) method to produce heavy oil and has practical potential to deploy with LSWI. However, the temperature-dependent characteristics of geochemical reactions in LSWI mechanism requires to further evaluation of thermal energy effect when hybrid LSWI with hot water injection or hot LSWI, deploys.
In LSWI, kinetics of mineral dissolution has been accelerated by thermal energy to produce HCO3− and exchangeable Ca2+ into brine. Increased HCO3− reacts with H+ and produces CO2 (aq). The CO2 (aq) has transported into oil at thermodynamic equilibrium. Though this geochemical phenomenon has resulted in increased CO2 concentration in oil, the effect of viscosity reduction is negligible due to relatively low dissolved mineral concentration. The oil viscosity reduction obtained in hot LSWI is attributed to mainly temperature-dependent viscosity reduction, not geochemical contribution. However, another geochemical contribution is observed in terms of the produced Ca2+ from mineral dissolution. While the increased Ca2+ has been consumed to produce CaCO3, CaHCO3+, and CaSO4, it has contributed to enhancing ion-exchange in high temperature condition. This geochemical contribution has induced additional wettability modification over that from non-hot LSWI. Consequently, the enhanced ion-exchange and oil viscosity reduction by thermal energy significantly improve oil recovery in hot LSWI up to 7.8 % over LSWI.
Effect of Water Saturation on Relative Permeability and Porosity in Hydrate Bearing Sand
Authors: Jasamai Mazuin , Idress Mazlin , Saaid Ismail M , Sabil Khalik M 
Published: November 2016

Abstract
Large amounts of natural gas, predominantly methane are stored in gas hydrates in sediments below the seafloor and the permafrost. Gas hydrates are ice-like crystalline solids formed from mixtures of water and light natural gases at high pressure and low temperature condition. Vast quantities of methane hydrates have been discovered worldwide in sediments and sedimentary rock. During dissociation, 1 m3 of methane hydrates at reservoir condition could release 164 m3 of methane gas at standard conditions. Therefore, methane hydrate can be an affordable energy, alternative for fossils fuels. Production of natural gas from hydrate bearing sediments significantly influenced by geological conditions and petrophysical properties. The most valuable information needed to reliably predict are permeability and porosity reduction in the presence of gas hydrate as this parameters will influence the flow in the sediments for production. This present research examines the effect of water saturation on the permeability and porosity in unconsolidated quartz sand. Methane hydrate was formed in quartz sand in Hydrate Tubular Cell using deionized water at 276 K and 8 MPa. The system was pressurized and stabilized at 8 MPa after absolute permeability measurement. After stabilization, the system was cooled to 276 K to form methane hydrate. Relative permeability to gas was measured after methane hydrate formation. Water saturation varies from 10%, 35 %, 50 %, 75% and 100% in the sand pack with porosity of 40%. Absolute permeability was calculated using Darcy equation for permeability measurement using gas before hydrate formation at each water saturation. Average absolute permeability is 108.7 mD. Values of hydrate saturation was calculated at different water saturations. The results indicated that, variation of water saturation affect the relative permeability and porosity after hydrate formation. Relative permeability to gas decreased from 0.75 to 0.49 as water saturation decreased. This study found that porosity of the sample reduced drastically as the sample saturated with 35% of water. Porosity reduced from 40% to 37.4% due to increment of hydrate saturation. Water saturation affect formation of hydrate in pores, thus it affects the relative permeability and porosity of the sand pack. These data are essential for modelling and the development of commercial gas production technology for methane production for various field operating scenario.
Structural Modelling of Complex Fault Relationships: A Volume Based Modelling Approach
Authors: Pal Arindam , Nazhri Ahmad , Phinney Eric , Sunder V. , Goodlad Stephen , Dwivedi Nikhilesh 
Published: November 2016

Abstract
Complicated structural relationships within gravity collapse, growth fault and thrust regimes have always been challenging while modelling with conventional Pillar Based Structural Modelling methods. The complex fault-fault and fault-horizon relationships are more accurately modelled with Volume Based Modelling (VBM) technique that results in robust structural grids. In terms of orthogonality, the quality of structural grid cells is superior compared to the corner point grids. Nearly all complex fault relationships can be modelled using this technique.
In the extensional Barmer Basin, north-western India, the Barmer Hill Formation of Paleocene-Eocene age is affected by syn-sedimentary faulting events. Gravity collapse structures developed synthetically along a down-to-the-west major boundary fault are expressed as a series of cuspate, low angle listric faults. Seismically mapped, depth converted conjugate faults and horizons are sequentially modelled as geological events using a pillarless structural framework algorithm within the volume of interest. The gravity collapse structure bound by main boundary fault and several λ and Y-shaped listric faults are accurately modelled using the fault framework modelling process. The conformable Barmer Hill horizon inputs are well tied, converted to point datasets, filtered with suitable fault cut-backs and modelled using horizon modelling process. The algorithm uses an interpolation technique that creates triangulated meshes for modelled surfaces ensuring high degree of data consistency, retaining complex truncation relationships in the model. Residual calculation of the structural framework shows excellent coherence with input dataset.
Structural framework modelling is followed by structural gridding performed at an optimum resolution to capture the reservoir heterogeneities. Depending on the end usage and fault complexity required in the model, multiple realizations of geological and simulation grids are created. The layering scheme is optimized with an integrated approach, honoring reservoir heterogeneity and simulation constraints. The structural grid is quality checked with parameters like negative volumes, distorted - isolated cells and cell width. By virtue of grid orthogonality, significant improvement is observed in simulation run time.
Volume Based Modelling is a workflow operated, automated, repeatable and geologically consistent technique compared to conventional pillar based structural modelling methods. The structural grid generated from a volume based model provides an excellent platform for dynamic simulation. With examples from Barmer Hill structural model, this paper showcases volume based modelling as a robust alternative technique for modelling complex fault relationships.
Quest Commercial Scale CCS – The First Year
Authors: Tucker Owain , Gray Lilian , Maas Wilfried , O'Brien Simon 
Published: November 2016

Abstract
Quest is a commercial scale, fully integrated carbon capture and storage project and the first connected to the oil sands. Located in Alberta, Canada, Quest is designed to capture and safely store more than one million tonnes of CO2 each year – equal to the emissions from about 250,000 cars. This represents one-third of the emissions from the Scotford Upgrader, which transforms bitumen into crude for refining into fuel and other products.
CO2 injection began on the 23rd of August 2015 and the project has successfully captured and stored over 1 million tonnes of CO2 in its first year of operation. Startup was successful and followed a staged approach. First, the three capture units were commissioned with a period of run-in, then the compression and conditioning, followed by displacement of the nitrogen from the pipeline, before finally moving to injecting around 3000 tonnes per day into the Basal Cambrian Sandstone saline aquifer; using two of three available wells. The injectivity and pressure dissipation has been exceptionally good allowing the third well to be reserved for interference testing.
During the start of injection, the production technology team worked in the Scotford control room and ran real time transient flow simulations of the CO2 expansion across the well head chokes and into the wells. This allowed the operators to pro-actively manage the ramp up. To our knowledge this is the first time that this has been done.
The onshore storage is deploying cutting edge monitoring technology – fibre optic vertical seismic profiles and line of sight surface CO2 detection; along with microsesimic and extensive pressure monitoring.
This paper outlines the experience with starting up the facilities and wells and will present the results of the first year of operation. It will present the experience from stakeholder engagement, the capture plant, the compression system, pipeline, wells and monitoring.
Increase Stimulated Reservoir Volume SRV for Old Oil Wells in Changqing Oilfield
Authors: Xu H. , Sun H. , Wang Z. , Zhang M. , Chi X. , Liao L. 
Published: November 2016

Abstract
Changqing oilfield is a typical low permeability, low porosity sandstone reservoir, and most wells drilled in the field have to be fractured before production. Nevertheless, the fracturing scales were relatively small. With the number increase and rapid production decrease of old fractured well, study and application of re-fracturing technologies to restore or improve old oil wells productions become necessary.
In this paper, we break through traditional re-fracturing ideas in sandstone reservoirs (such as old fractures re-extending or deflection fracturing), and put forward SRV fracturing technology to increase the stimulated reservoir volume by increasing fracturing scale, injecting base fluid / cross-linked fluid alternately, and using temporary plugging agents. Firstly, applicable conditions of this technology were studied, such as reservoir properties, rock brittleness, natural fractures and horizontal stress difference. Then, two kinds of temporary plug agents were selected and evaluated, also technological parameters and construction processes were optimized in lab. Finally, pre-fracturing evaluation of old oil wells was carried out and field tests of 3 wells were conducted.
Field tests results showed that the selected plugging agents could realize temporarily plugging of the fractures by measuring downhole pressures. Microseismic fracture monitoring result indicated that SRV fracturing, by means of fluid alternate injection and plugging agent, could really increase SRV of the old oil well. After stimulation, average daily oil production of the 3 wells increased 72%.
Laboratory researches and field tests results indicate that increase stimulated reservoir volume for old oil wells in low perm sandstone reservoir is technically feasible, and this technology has a good application prospect, which benefits the traditional re-fracturing methods significantly.
First Slanted ICD Completions Through Sand - Shale Sequence at High Angle - 84 Deg in Kuwait Reservoir
Authors: Al-Ajmi Abdullah , Al-Rushoud Abdulaziz , Gohain Ashis , Al-Haj Hussein , Al-naqa Faisal , Moustafa Shady , Mobasher Mohamed , Elsherif Ahmed , Osman Saleh , Wenang Martine , Keot Chandan Jyoti 
Published: November 2016

Abstract
The drilling of development wells in layered sand-shale sequence involves thin and sinuous targets. Optimal well placement is a requirement for these thin reservoirs in order to drain them in a cost effective manner. A slanted well with 84 deg inclination was planned and drilled to drain oil from the Lower Cretaceous layered sands of target formation as part of a development plan to increase the production rate from the North Kuwait oil field which is aligned to Kuwait Oil Company's (KOC) goal of producing 4 million bbl/d oil by 2020 and sustained it until 2030.
Plan is to build the inclination through the 12 ″ hole section kicking off with Motorized Rotary steerable system up to 54 deg inclination. The 8 ″ section is planned to build from 54 deg to 84 deg and again planned to be drilled with rotary steerable system and neutron, porosity technologies to allow precise landing with high angle in the required zone of interest. The 6 1/8″ section is planned to be drilled with Rotary steerable and triple combo Logging While Drilling (LWD) technologies to precisely drill through the required zone of interest. The well was planned to be drilled with Rotary steerable tools to enable smooth well profile and avoid micro doglegs to enable smooth deployment of ICD completions through difeerent layers - sand - shale - silt - shale sequences.
After drilling the top hole curve sections, well was successfully landed into the target sand channel and drilled through the drain hole section using resistivity, gamma ray and density neutron tools. Well was monitored in real time with a multi task team comprising drilling department, field development, well placement and target depth was called out while it approached the expected zones with water fingering. After the completion of the 6 1/8″ reservoir section, achieving very smooth profile with pre - selected technologies, a dedicated cleanout run was performed to make sure that the hole profile is more precise and smoother for the deployment of ICD completions for the first time in a high angle deviated well crossing through different layers. After taking all the precautions related to hole cleaning, mud weight management to mitigate the shale sections open at high angles and well geometry, well was completed with ICD completions for the first time in Kuwait for a slanted 84 deg well within sand-shale sequence.