bluuebunny/crossref_metadata_2025 huggingface dataset:
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

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 >1000 ohm meter indicate homogeneous folds, interpreted as Merawu and Penyatan Formation, resistivity <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

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

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

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

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

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

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

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.
Holistic Life Cycle Costing Approach for Different Development Phases of Drilling Tools
Authors: Johannknecht F. , Gatzen M. M. , Hahn D. , Lachmayer R.
Published: November 2016

Considering the current trend oil and gas corporations are facing, they are continuously focusing on increasing their operational efficiency. Declining oil and gas prices lead their operational departments to reduce the cost of drilling and producing hydrocarbons, which ultimately results in streamlining the operational cost of their drilling tools. Oilfield service companies with hybrid business models must take all life cycle cost into account. To influence these costs and to optimize capital and operational efficiency as well as service availability, comprehensive cost models are used in the product development process. For the consecutive development stages from feasibility through detailed design, models with increasing level of detail are required.

Cost modeling within the development process is typical in the petroleum industry. Currently, models are available for specific applications in single development phases. This paper describes a holistic approach to analyze and optimize life cycle cost and service availabilities of drilling systems from the early concept phase through deployment. The result is a fast, secure and easy usable software tool as well as a standardized process to develop competitive, high-technology drilling systems.

To identify requirements for these models, a stakeholder analysis is performed and described. Based on the analysis results, information flows are defined: Who provides and needs which information at what point of time within the process? With this foundation, new models are created or existing models extended to meet the requirements. In this context, best practices from different industries are also reviewed and implemented where applicable. A parallel use of the models during the respective development stage enables an iterative improvement. The development of the models and current results are detailed in this paper.

In early conceptual design phases, it is challenging to calculate life cycle cost with sparse information about the complex future drilling system, so cost-estimating relationships must be devised. Maintenance times and intervals, which are one of the main operational cost triggers, must be assessed by concurrent high level tool performance and reliability. Cost efficiency, tool performance and reliability must be balanced to achieve high customer expectations and high margins. During the detailed design phase, system costs, such as alternative costs, e.g., through non-availability of tools, in addition to bottom-up models on the component level, must be considered. These modular models are connected to each other to exchange data via standard interfaces. They calculate future cost projections and identify key cost drivers. This enables continuous cost optimization through the whole development process. Results to support decision-making as well as cost saving potentials are shown with an exemplary development process of a drilling tool by using the life cycle costing approach.
A Simulation Model of Land-Facies Karamay Oil Sand Reservoirs Under Water Injection
Authors: Pang H. , Jin Y. , Chen M. , Lin B. , Shan Q. , Xu Z.
Published: November 2016

The micro-scale hydraulic fracturing is a technique which is used to shorten the preheating period by means of controlling water injection to horizontal wells to create homogenously distributed microcracks in the zone between the two wells. Numerous simulation studies have been previously conducted to understand the growth of the steam chamber, however, the model to simulate mini-frac before preheating is left undone. Especially, counterpart research on land facies ultra-heavy oil sand of Xinjiang oilfield is few.

The provides micro-scale hydraulic fracturing model, in this study, is based on experimental analysis in terms of geomechanics theory and mini-frac tests result from field experiment in Xinjiang oilfield. First, laboratory triaxial tests were designed to determinate the mechanical behavior of the oil sand and the mudstone caprock. Drucker-Prager model was used to investigate the two dilation mechanisms, namely, shear dilation and tensile parting, during the simulation of micro-fracturing propagation. Finally, a micro-fracturing model coupled fluid-solid is implemented by with the finite element program ABAQUS, to describe the early SAGD start-up demonstrated on the SAGD well pair in Xinjiang oilfield.

The first-hand target of ABAQUS simulation in this study is to evaluate the performance of micro-fracturing process, particularly, to determine the degree of connectivity of injection and production wells. Thereby to predetermine the bottom hole pressure (BHP) and volume of injection in order to provide a specific guidance for work program carried out in oilfield. As the matter of convenience, this study, according to the simulation results, have discussed how to define the extent of the connected parameters to determine the connectivity of the well pairs. Furthermore, sensitivity analyses have been done to realize the different parameters on proficiency of micro-scale hydraulic fracturing in the field.

Our works are significantly important for the future development and promote the mini-frac tests to enhance the in-situ thermal recovery in Xinjiang oil field. In addition, the model and method can be implemented for any type of heavy oil field which requires early SAGD start-up to increase the oil recovery.
Smart, Porous Polymer Coatings to Bind Clay Minerals in Coal Bed Methane Wells
Authors: Ge Lei , Hamilton Christopher , Ferbina Tasha Rahman , Rudolph Victor , Rufford Thomas E.
Published: November 2016

We report a phase inversion polymer coating to prevent clay swelling and fines production in coal seam gas (coal bed methane) or other petroleum well bores. Importantly, this coating remains permeable to gas and water flow across producing coal seams. This approach uses a water-soluble solvent that can form a low-porosity, dense membrane across clay-containing interburden layers, which contain less free water than the coal matrix, but form a porous membrane across the coal layer. Problematic interburden samples and reference coal samples were from a core sample obtained from a coal seam gas well in the Surat Basin, Queensland. The mixture of polymer coating solution (polyethersulfone (PES)/N-methyl-2-pyrrolidinone (NMP)) was prepared and cast onto the target samples by a simple dip method, followed by the phase-inversion step. Polymer coatings were characterised by X-ray diffraction, Fourier transform infrared spectroscopy and scanning electron microscopy. The SEM images of coated mudstone and coated coal samples showed that the polymer formed a dense layer across the low-permeability mudstone, but an open porous structure was formed on the coal surface. The uncoated rock samples and polymer coated samples were exposed to a flow of distilled water, and the formation of any fine particles was observed by video camera. The flow tests show that the PES coating can significantly improve the stability of interburden samples containing swellable clays.
The Mechanism of Complex Hydraulic Fracture Creation Due to Strength Heterogeneity
Authors: Nagaso M. , Mikada H. , Takekawa J.
Published: November 2016

Understanding the mechanism of complex hydraulic fracture creation could develop a design and management of subsurface fluid paths in hydraulic fracturing. Although many studies about fracture network formation caused by various geophysical factors has been conducted, the influence of strength heterogeneities of rock is not fully revealed. We perform a series of numerical simulations of hydraulic fracturing with a particle method to reveal the generation mechanisms of hydraulic fractures whose geometrical complexity could depend on strength heterogeneities of subsurface materials. We use microscopic strength distribution, which is set randomly to follow the Weibull distribution, in our models as a substitute for the strength heterogeneities of real subsurface material after confirming the validity of this substitution by numerical analysis of uniaxial tensile tests. As a result of numerical simulations of hydraulic fracturing with our models with a range of strength heterogeneities, we found geometrically complex fractures are comparatively generated in the models as the increase in the strength heterogeneities. Because of weak interparticle connections included in the model due to heterogeneities, micro cracks are generated to cause the furcation of advancing hydraulic fractures around their tips. The further propagation of hydraulic fracture is strongly affected by these preceding micro cracks, and hydraulic fracture does not propagate straightly and complex network of hydraulic fractures is created. In addition, pores with specific shape and microscopically weak portions cause fracture to be complex. The direction of tensile stress induced by fluid infiltration depends on the shape of pores and fractures. The tensile stress would act in the maximum principle stress direction at the pore with specific shape and newly fracture perpendicularly to main hydraulic fracture is formed from the portion of weak strength at the pore wall. On the other hand, the models with weak strength heterogeneities show a simple linear extention of hydraulic fractures because fewer branches are formed around the tip of the advancing hydraulic fractures. In conclusion, micro cracks generated around the tip of hydraulic fractures and pores with specific shape cause the hydraulic fracture to become complex geometrically in the model after the furication with strong microscopic strength heterogeneities.
Success in Arresting Overall Field Decline and Increasing Oil Production in a Mature Field through Effective Production Enhancement Initiatives
Authors: Zamanuri A. , Abdulhadi M. , Chin H. V. , Lim C. C , Jacobs S. , Sayed Zainaiabidin S. M. A. , Khalil M. I. M. , Abd Wahid M. I. , Dolah K. A. , Munandai H.
Published: November 2016

In a mature oil field that has been producing for over 30 years, declining reservoir pressure and increasing water-cut are the two major factors that are affecting oil production rates. It is a common understanding that without any effort, this decline in oil production will remain until the end of the field's economic life. One of the approach to address this issue is through production enhancement work which has been proven successful in an oilfield offshore of Sarawak not only at arresting the overall field decline, but also increasing the overall oil production.

The practice for Production Enhancement (PE) work in this field mainly involves (i) shutting off the existing watered-out intervals, (ii) adding perforations to the existing sand and/or a different reservoir, (iii) zone change and gas lift valve change activities, (iv) re-activation of idle wells, (v) gas lift optimisation and well bean-up, (vi) reservoir management planning and (vii) restoring well integrity.

Due to the limited deck space on the platform and the unavailability of living quarters, the application of a work barge was essential for this type of PE work to house the necessary equipment and chemical for the enhancement job as well as acting as an accommodation vessel for the personnel. Concurrent well intervention operations on two different platforms was the selected option for time and cost optimisation and quicker first oil. For the same reasons, 24 hours operation was implemented whenever circumstances permitted. Further cost optimisation was implemented in subsequent campaign by utilizing slickline only as means of well intervention as well as withdrawing the option to have a dedicated work barge on site to support the campaign.

After the successful PE Campaign in four (4) consecutive years, this initiative has resulted in over 3500 bopd of incremental oil. The overall technical potential (TP) of the field also increased by more than 100 percent. This has effectively arrested the previously estimated 25 percent field decline before the campaigns and increased in the overall field production. This paper seeks to present the challenges, the plans and operational execution of the well intervention activities. The results of the successful PE campaign, implementation of best practices, lessons learnt and improvement plan will also be shared.
Geomechanical Models: Application to Drilling in Partially Depleted Fault Blocks
Authors: Rana Rohit , Hansen Kirk S. , Kandpal Jyoti , Kumar Rajan , Schutjens Peter , Muro Leytzher , Rees Daniel , Latief Agus I.
Published: November 2016

Knowledge of the in-situ stress state and how it varies with reservoir depletion is important for the design and execution of in-fill drilling. This paper highlights the key geomechanical aspects and their usage in planning of wells through severely depleted (up to 25 MPa) and overpressured zones within a very short depth interval (few 10s of m), in an onshore gas field in Brunei. With focus shifting from oil to deep-gas development, drilling complications include risks of wellbore instability, excessive mud loss and internal blowouts, as well as differential sticking in the depleted reservoirs. Moreover, fracturing of the depleted sands while drilling infill wells carries the risk of jeopardizing production at nearby producing wells because of locally altered flow paths. The risks were evaluated by application of empirical and analytical geomechanical models of stress changes with depletion, and by elasto-plastic finite element models of borehole instability (collapse) due to shear failure.

Our results show that for an average depletion rate of 1 MPa/year, the drilling window (difference between maximum allowable mud weight controlled by fracture pressure and minimum mud weight controlled by formation pore pressure or borehole collapse pressure, whichever is greater) is likely to remain open for the coming 12 years. Minifrac or extended leak-off tests at different stages of field development should be taken to monitor stress changes within the reservoirs and provide updates for calibration of the geomechanical model.

Next to showing the geomechanical model results and their application to drilling, we demonstrate the refinement of pore pressure/fracture pressure predictions (i.e. narrowing down the uncertainty in the drilling window) for mature fields where producing "from the bottom up" has not been feasible. We also indicate how risks associated with drilling through depleted/undepleted reservoir sequences in a single hole section can be managed to as low as reasonably practicable with the help of geomechanical input. These results "open the door" for accessing deeper potential pay zones by drilling through severely depleted formations.
Optimisation Leads to Improved Hybrid Bit Design and Enhanced Drilling Efficiencies in Challenging Vertical Application in Tarim Basin, China
Authors: Liu Y. , Chen M. , Sheng S. , Zeng J.
Published: November 2016

This paper describes the optimization of a hybrid bit which is a polycrystalline diamond compact (PDC) bit with rolling cone cutters to improve dynamics and durability. When drilling the hard & interbedded formations with conglomerates in the Tarim Basin in Northwest China, PDC bits break down with broken & chipped cutters in the cone, nose & shoulder sections of the profile. In addition severe torsional vibrations lead to twist-off's and stick-slip which damages the bit and drilling system. Even worse, because of the torsional vibration, less Weight on Bit (WOB) is being applied, which results in lower Rate of Penetration (ROP), less footage and more trips. Roller-cone bits generally drill faster than PDC bits, but bearing life is short in the hard and abrasive conglomerates.

Due to success in similar application elsewhere in the world, a hybrid bit was proposed and tried to drill the challenging formations in the Tarim Basin. In the first run the entire conglomerate interval was drilled at higher ROP, with lower torsional oscillations and saving 16 rig days. Although this was a success there was an opportunity for further improvement by strengthening the PDC cutting structure to avoid premature cutter damage mainly in the central, cone section of the profile.

An upgraded hybrid bit with split, overlapping blades and more durable Dual Chamfer cutters was deployed in the same interval. Respective performance of PDC, Roller Cone, Hybrid bit and Optimized Hybrid bit used in the same formation are compared in terms of footage, ROP, Mechanical Specific Efficiency (MSE) and dull condition. By using Optimized Hybrid bit, the customer saved multiple bit runs & drilled eight times farther with the ROP 92% faster than conventional PDC bit run in the same well.
A Two Dimensional Approach to Saturation Computation in Laminated Reservoirs
Authors: Farag S. M.
Published: November 2016

Laminated reservoirs where traditional shaly sand interpretation techniques underestimate the true formation hydrocarbon saturation, are common in South East Asia. Logging technology such as tensor resistivity measurements, nuclear magnetic resonance (NMR) and high resolution log analysis have been shown to be the best way to accurately evaluate such reservoirs; however, these logs can only be recorded in new wells. A simple technique to re-evaluate existing wells and compute more accurate fluid saturations using "conventional" logs (resistivity, density, neutron and gamma ray in this case) is proposed here.

From our experience with tensor resistivity and high resolution analysis, it is a good assumption in many laminated reservoirs that the effective water volume (Vwee) in the individual sand laminations remains roughly constant over short intervals. Traditional shaly sand interpretation is usually performed point by point with no assumptions about the continuity of the results. If we assume that Vwee in the individual sand laminations is roughly constant over a depth interval, then it is possible to invert for Vwee as long as the total shale volume is varying over the interval. We still need to make the usual assumptions about the conductivity of the shale and formation water needed for traditional shaly sand analysis. However, by simultaneously inverting over multiple depth levels, we can derive a narrow range of possible Vwee solutions. In suitable conditions, the resulting total water volume computation is much more accurate than conventional shaly sand analysis in laminated reservoirs.

The proposed interpretation method has been tested in several wells from different areas, to establish the range of applicability and limitations. The results compare favorably with tensor resistivity interpretation where the resistivity contrast between sand and shale laminations is moderate. As the sand to shale resistivity contrast increases, the method becomes more sensitive to the input parameters and the uncertainty increases. In all cases, the computed saturation is more accurate than standard point by point shaly sand interpretation in laminated intervals. Since the inversion outputs a range of solutions rather than a single value, the method has a built-in estimate of the accuracy of the results.

In suitable conditions, this formation evaluation technique extends the usable range of "conventional" log data in laminated shaly sand environments. This is especially useful for re-evaluating producing fields where drilling new wells and acquiring tensor resistivity and high resolution logs in the laminated facies is not practical. Details of the proposed interpretation workflow and quality control of the results are presented.
Three Dimensional Stress Field Estimation Using S-Wave Anisotropy Obtained from Ambient Noise Records of Vertical Seismic Array System
Authors: Kimura T. , Mikada H. , Araki E.
Published: November 2016

In this study, we propose a new approach to estimate depth-dependent stress field in a borehole instead of conventional in-situ measurement methods. Seismic interferometry and Alford rotation methods are used to obtain S-wave anisotropy as a proxy of stress field. Ambient noise records observed by horizontal components of vertical seismic array system installed in a borehole were used as input data. We first calculate virtual cross dipole seismic records by seismic interferometry method applied to the observed continuous ambient noise records. Then we applied the Alford rotation and layer stripping technique to obtain depth-dependent S-wave anisotropy parameters, i.e., the orientation of fast S-wave and the difference between fast and slow S-wave velocities of formations along the vertical axis of a borehole. Obtained results, the orientation of fast S-wave, have very good agreement with directions of principal horizontal stress, which was revealed in the analysis of borehole breakout just after drilling the borehole. We propose that our approach would readily be applied to monitor the stress field around a borehole instead of conventional in-situ measurement methods.
A Success Story for a High-Temperature Foam-Assisted Lift Application in a Mature Field, Gulf of Thailand
Authors: Sompopsart Suwin , Toempromraj Wararit , Nadoon Apiwat , Charoencheep Phongsiri , Sukchum Techasit , Harnboonzong Pithak , Whangkitjamorn Jugkapun , Lerlertpakdee Pongsathorn , Thanasutives Patana , Tivayanonda Vartit , Charoenniwesnukul Kritsada , Thongpian Duangkwan , Kultaveewuti Chatsuda , Wongrattananon Chuayrach , Ketpreechasawat Suampa , Wongpattananukul Kongphop , Pulputtapong Jirayu , Sirimongkolrat Saran , Pongsripian Winit , Phanich-aphichai Krittapas , Wattanasuwankorn Reawat , Thompson Stewart
Published: November 2016

Liquid loading is a common problem in many gas wells in the Gulf of Thailand. At the late stage of well life, reservoir pressure declines, gas production rates decrease, and liquid begins collecting on the wall of the tubing and accumulates at the bottom of the well, eventually killing the well. This paper presents promising results from foam-assisted lift (FAL) field trials to remove liquids, re-establish flow, and increase production in previously idle wells.

The injection of foaming agents can be used to remove liquids through artificial lift. High downhole temperatures in Gulf of Thailand wells requires special foaming agents that can operate at 450°F. Using high-temperature foaming agents in nearly dead wells can extend their life by reducing the production decline rate and preventing premature water loadup. Because foam density is significantly lower than liquid density, hydrostatic pressure is reduced, which assists the flow of fluids from the bottom hole to the surface, resulting in increased gas production rates and reserve recovery rates compared to natural flow.

An operator in the Gulf of Thailand experienced promising results from a field trial using high-temperature FAL with batch treatments in five high-temperature wells in the offshore field. Three wells that were previously not flowing were able to flow to the production system after treatment. One well was able to flow at even higher rates after the FAL treatment compared to prejob rates. Only one well did not respond to the treatment. Understanding the FAL procedure and addressing critical issues before implementing the technology can help enhance mature field production in otherwise idle wells.

Using FAL in mature wells with low or no production can help remove liquid accumulation at the bottom of the well, preventing premature water loadup and returning idle wells to production.
Rock Breaking Model Under Dynamic Load with the Application of Torsional and Axial Percussion Hammer
Authors: Xu Zichen , Jin Yan , Hou Bing , Don Jingnan , Pang Huiwen , Lu Yunhu
Published: November 2016

Currently, with proceeding in exploration and development of deep oil&gas, and hot dry rock resources rapidly, it is a high priority to solve the problem of drilling super hard rocks, such as basal conglomerates, tuffs and carbonates in drilling projects. As the drilling efficiency affects the economic feasibility of the drilling project, various methods to reduce the drilling cost have been proposed. Among these alternatives, dynamic load rock breaking method has been further developed in this study to achieve efficient drilling, which can change the way that polycrystalline diamond compact (PDC) operates on rocks.

It is a common problem in drilling in hard strata, such as rate of penetration, stick-slip vibration, chip hold down effect, and high temperature. To solve these problems, torsional and axial percussion hammer has been developed, which can generate both axial and torsional impacts at the same time. The vibration module of this tool, driven by pressurized drilling fluid, can impact on a hammer with a particular slope briefly and the energy instantaneously released in this process can then trigger percussion. The direction of the impact, depending on the resultant force of axial and torsional impact, closer to the dip angle of PDC, indicated that this tool conforms to the rock breaking mechanism of PDC bit. Therefore, this tool is expected to be more effective than traditional axial percussion hammer. In addition to perform structural design and optimize this tool, numerical simulation and laboratory test with designed parameters were conducted in this study. The tool described in this study can reduce stick-slip effect by providing pulse torque and WOB to the bit.

Statistical analysis in this study suggests that the effectiveness of percussion is directly correlated with stick-slip ratio, breakability of rock and frequency of percussion hammer. Based on these findings, rock breaking model with rock's compressive strength, stick-slip ratio and brittleness was established.

This tool was purely made of metal which can endure high temperature and resist corrosion. Field application of this tool in the Ordos and Tarim Basins demonstrates that it has remarkable service life and is effective in speeding up drilling with an average 150% increase of ROP. This torsional and axial percussion hammer is expected to lead to a revolutionary advance in the development of rock-breaking techniques for deep well drilling in hard strata.