bluuebunny/crossref_metadata_2025 huggingface dataset:
Development of Remedial Solution for Removal of Cured Resin Damage
Authors: Belakshe Ravikant , Songire Sumit , Prakash Chetan
Published: November 2016

Curable resins are widely used to mitigate sand production; however, resins are reactive compositions that, under certain conditions, cure prematurely, thus causing impairment for hydrocarbon production. Mechanical methods for damage removal are only effective in wellbores and cannot reach the damage in the formation. This paper investigates the dissolution efficiency of newly developed solvents for damage removal by dissolving the cured resin from pore spaces of the sand grains. The solvents are affordable and environmentally acceptable lactone solvents with boiling points above 200°C.

Resin consolidated sand cubes were soaked in two solvents to measure the ability to dissolve the cured resin at ambient temperature to 100°C. Core flooding tests were performed on resin consolidated sandpacks at 90°C to quantify solvent efficiency for removing damage caused by excessively cured resin. For quantitative analysis, sandpacks were prepared and initial permeability was measured, followed by pumping a resin composition in excess through the sandpacks to create damage by the cured resin. Damage was measured in terms of reduced permeability. Finally, damaged sandpacks were treated with solvent and regained permeability quantified the efficiency of resin dissolution.

Qualitative results showed that the solvents evaluated in this study were able to dissolve and remove cured resin from the sand surfaces effectively. The chemical reaction between cured resin and solvent is temperature dependent, and solvent performance increases with increased temperature. The dissolution mechanism is attributed to the high polarity of solvents, which allows them to react with the polar groups in cured resins. Quantitative analysis showed that the two solvents tested were able to dissolve cured resin in respective sandpacks, and regained permeability was observed from ~26 to ~85%, depending on resin type, when tested at 90°C. These single-component solvents are effective in terms of removing damage imparted by aqueous-based resin (ABR) as well as solvent-based resin (SBR) systems.

The described study is a step toward providing environmentally benign, chemically robust, and thermally stable solutions in view of current requirements by the oil and gas industry. The ability of the solvents to remove the cured resin could be beneficial in terms of eliminating formation damage caused by improper resin treatment. In addition, the same solvents can be used for cleaning equipment, wellbores, and completion tools which have been damaged or plugged by noncured or cured resin.
Intelligent Thinking Enables Emergency Well Killing in Sand Producing Gas Well Using Conventional Resources Huge Time Saving
Authors: Borah J. B. , Rabha N.
Published: November 2016

This paper presents an emergency well killing operation using rig less Coiled tubing unit intervention in a highly erosive environment. Conventional killing operation had resulted in severely eroded and punctured coiled tubing due to sand ingression and subsequent killing failure previously unseen in OIL's areas of operations. This called for reconsideration and alterations to conventional methods using the same available equipment and thereby successful killing of the well.

Sand ingression though common in OIL's oilfields had never previously compromised well completion to such degree. Well no. "DHL" was a gas producer producing 40000-50000 SCUMD of gas. Pressure build-up of 170 ksc was noticed in tubing, 5 ½" casing annulus and also in 9 5/8" casing annulus. Hole-probe survey of the well showed sand and mud build up. Subsequent MIT log survey of the well showed corroded and severely damaged completion. This rendered the well incapable of being killed by conventional methods of killing. Coiled tubing unit was deployed and it was tried to kill the well. However the first attempt failed to subside the well pressure and upon pull out severe pitting of the coiled tubing surface and tubing puncture was encountered due to the sand ingression. Alterations were thereby made in the circulation procedures and successful killing of the well was achieved for remedial work over operations.

Gas well killing is always critical and such conditions of compromised completion, sand ingression and erosion coupled with abnormal pressure build up further adds to the criticality and safety hazards. However with intelligent thinking the job may be achieved with the same resources saving costly man-hour, runtime of machine and downtime of reservoir. Coiled tubing thus proves to be a versatile tool for intervention in wells where regular methods are no longer feasible. In addition to this, with minor tweaks using the same equipment, such critical operations may be carried out as well which might seem unachievable at first.
An Analysis of Multiplicative Schwarz Procedure in Coupling of Reservoir and Networks in Next-Generation Reservoir Simulators
Authors: Temizel Cenk , Putra Dike , Gok Ihsan M. , Zhang Ming , Duangprasert Tanabordee , Aktas Sinem , Tek Suleyman , Balaji Karthik , Ranjith Rahul
Published: November 2016

With the increasing use of reservoir simulation, not only in conventional reservoir modeling, but also in complex and large reservoirs, the need for faster and more robust modeling of reservoirs, along with the facilities and surface networks, has become crucial to meet the requirements of modeling either large or multiple sub-reservoirs with thousands of wells and surface networks, including pipelines and gathering centers, connected all the way to the separators. Next-generation reservoir simulators have begun replacing conventional reservoir simulators over the last decade in conjunction with the addition of more features that enable them to model different phenomena of reservoir fluid flow and recovery techniques, putting them at the forefront of reservoir simulation. While next-generation simulators offer more convenient solutions through surface-subsurface coupling and faster simulations that save time in decision-making processes in reservoir management, there are still some difficulties for the user, as well as in the development of these simulators from a computational point of view. The objective of this study is to outline the strengths and weaknesses along with the challenges in this process to serve as a guide for more efficient use.

This study presents an analysis of an important component in the reservoir-network-coupling process in which the reservoir unknowns and network equations are solved iteratively. In the Schwarz procedure, the overlap region consists of reservoir cells included in the network set. An optimum solution for the number of cells extended into the network is important, because as the number of reservoir cells included in the network increases, the cost of the network to solve increases, which can become quite expensive, since bigger and more complex networks are needed to find the solution.

This study highlights the effect of using different options for a better understanding of the important components of the coupling process; the results serve as a guide for a more efficient use of this procedure.

Reservoir simulation involves several complex calculations to model the full-physics of the subsurface flow, as well as the well and surface facilities. It is not straightforward and easy to model and computationally evaluate the modeled phenomena. Discretizations and approximations contribute to error. Run time is another component that must be managed to find a balance between accuracy, precision, and time. Literature lacks practical examples of the Schwarz procedure, which is another important component in coupling reservoir and surface networks that should be used wisely and efficiently to find a balance between accuracy and computational time. A solid, practical example with the theoretical background that this study outlines will benefit the users of complex and large reservoir simulation models.
Heterogeneous Carbonates: A Modeling Method Ensuring Consistency Between the Saturation Height and Permeability Models for Bimodal Rocks
Authors: Hulea Iulian N. , Dijk Harm , Karnaukh Danila , Spalburg Mirano
Published: November 2016

Due to their heterogeneity, carbonate reservoirs are more difficult to model than their clastic counterparts. The main difficulty stems from the abundance of different pore types in contrast to the typical interparticle pore type encountered in clastics. The multiple pore types make the modelling and prediction of permeability also more difficult for carbonates. Capillary pressures curves or log data are used in order to build saturation height models, also a challenging property with a profound impact and hence constraining it with independent data is desirable.

Recently, we have proposed that permeability and saturation height models have to be consistent, this implies that in the modelling process a new strategy can be adopted. Our work suggests that by using a Brooks-Corey type function, the number of parameters used to predict the 3D hydrocarbon saturation values (for a given porosity/permeability/rock type combination) can be reduced. This approach has also benefits when a saturation height model is prepared for both multimodal and unimodal rocks.

For the bimodal data analyzed, 3 different Rock types are modelled by one Saturation height model per mode, the critical variable distinguishing between Rock types being the microporosity content. By using saturation height models in combination with the conventional permeability measurements, a new approach attempting to extract the fundamental properties of individual pore systems is shown. The key idea is around identifying the governing pore systems from Capillary pressures curves and permeability measurements. The approach results in the ability to predict permeability continuously as a function of pore system mixing ratios.

It will be shown that by decoupling the two pore systems porosities, the permeability heterogeneity can be explained both as a function of porosity and microporosity content.
Free Yourself from Seismic Uncertainties While Drilling with the Deep Directional Resistivity Tool: A Success Story from West African Offshore
Authors: Mahfoud Osama , Chiappero Adrian , Pelissier Nicolas , Merlet Frederic , Dorange Philippe , Majumdar Chandan , Murray Doug , Nono Aaron Nana , Denichou Jean-Michel
Published: November 2016

To meet the increasing energy demand of the world and with the advent of new technologies, operators have been drilling increasingly challenging hydrocarbon pockets to increase recovery of existing assets. New technologies have been developed to achieve a higher degree of accuracy in well positioning and ministering the aspiration supporting the objectives of producing from otherwise impossible targets.

Total E&P Angola, operator in Block-17 in offshore Angola, had launched the CLOV development over four fields: Cravo, Lirio, Orquidea and Violeta, located approximately 140 km from Luanda in water depths ranging from 1050 m to 1400 m. With a focus to develop a highly faulted compartment of the Orquidea field, the ORQ-554 well was planned through a series of faults to achieve the desired drainage length within the unconsolidated channel sands of the Oligocene reservoir. The lack of drilling information for the compartment along with poor seismic resolution of the highly faulted structure owed a high level of uncertainty of ±30 m true vertical depth (TVD) in positioning the well and thus the well could miss the target reservoirs if not calibrated with respect to the structure.

The above challenges, in addition to uncertainty in the reservoir position, orientation, and overall geological structure, were necessitated a technology that could bridge the gap between conventional logging and seismic data. A new directional electromagnetic (EM) logging-while-drilling (LWD) service with a radial depth of investigation on the order of ±30 m has been introduced to allow early detection and mapping of the approaching reservoir with sharper resolution than obtained with seismic measurements and to add important new pieces to the reservoir characterization puzzle. The multilayer inversion coupled with deeper depth of investigation, allowed for the marriage in of seismic and borehole data, leading a more effective and productive wellbore.

This paper will highlight why deep directional resistivity is a step change for doing proactive well placement of highly deviated wellbores as well as for gaining a larger-scale reservoir understanding. Based on the BHA design, the tool was able to provide a resistivity map of the reservoir up to 20m away from the wellbore, detecting multiple layers to improve understanding and in turn support the characterization of the reservoir beyond seismic structural and near-wellbore petrophysical information. In addition, the improved reservoir delineation resulted in more accurate geological models, reserve estimates, and potential improvements to the completion design.
Stratal Slicing: A Tool for Imaging Geologically Time-Equivalent Fluvial Architecture- A Field Case Study
Authors: Lew C. L. , Ismail H. H. , Kadir M. F. A , Tajuddin M. R.
Published: November 2016

The study area covers specific interval with structural and stratigraphic meandering systems within the A Field in Malay Basin. Previosuly, interval-based attributes (waveform classification and RGB Frequency Blending) allow interpreter to visualize composite fluvial features within the interval. However, they do not distinguish the timing and evolution of the fluvial feature within the multi-storey channel bodies. Therefore, stratal slicing technique was then tested in order to solve the issues. The strata within the area of interest in Field A is characterized by anticline and lateral thickness variation, making stratal slicing as the most suitable method for imaging the geological features on the time-equivalent deposition surfaces. Stratal slices were generated proportionally between two interpreted bounding coal surfaces. The stratal slices were then identified and adjusted to their corresponding time-equivalent stratigraphic surfaces based on well stratigraphic markers. Amplitude values from 3D volume were extracted for these slices for imaging and interpreting the fluvial features on the relevant stratigraphic surfaces. Two stacked channel-bodies were mapped using stratal slicing technique, which cannot be visualized from interval-based attributes. The fluvial features observed from the stratal surfaces were then characterized based on 4th order meandering fluvial architecture elements, which consisted of point bar, abandoned channel, crevasse splays, and flood plain. Abandoned channels were analyzed from the channel bodies which are essential in understanding the reservoir compartmentalization, heterogeneity and continuity. The fluvial depositonal maps produced from stratal surfaces served as the control to generate reservoir thickness maps which are crucial in understanding sand distribution for each fluvial feature. In summary, stratal slicing is a pragmatic technique in enhancing interpreter ability to visualize and map fluvial architecture elements at specific time-equivalent stratigraphic surface. The technique helps to identify and characterize the evolution of the fluvial features, resulted in two stacked channel bodies being interpreted. Identifying the abandoned channel which is completely mud-filled helps to explain the reservoir compartmentalization between point bars, which occurred in Field A. This approach is important to guide new strategies of simulation and injection planning for better optimization of the field development and enhanced oil recovery projects.
Application of Innovative High-Temperature High-Density Oil-Based Drilling Fluid Technology in the Efficient Exploration and Development of Ultra-Deep Natural Gas Resources in West China
Authors: Long Li , Xianguang Xu , Jinzhi Zhu , Rongchao Cheng , Jianhua Wang , Shuang Li , Haijun Yang
Published: November 2016

Tarim Basin is the biggest oil and gas bearing basin in China. The ultra-deep formations in the Tian Mountain Front Block in North Border of Tarim Basin is characterized by ultra-high temperature, abnormal high pressure, ultra-thick composite salt-gypsum formation, high-pressured brine layer, and high collapse stress formations are widely distributed, so it will bring great challenge to drilling engineering.

To solve significant non-productive time (NPT) and low rate of penetration (ROP) encountered in dealing with borehole instability, stuck pipe, and high pressured brine influx in the process of drilling operation of the salt-gypsum formations and fractured pay zones, high-temperature high-density oil-based drilling fluid (HDOBM) has been recommended. The high-density drilling fluid system has excellent comprehensive properties, and it could solve the contradiction between safety drilling of ultra-deep wells and formation complexity. Until now HDOBM has been used in the drilling engineering of above 60 wells in this block.

But HDOBM technology is faced with great technical problems to be solved. After many years of technical researches and spread, the existing problems in OBM, including exorbitant price, environmental pollution and high cost caused by downhole losses, have been solved, and a complete set of matching techniques are developed.

HDOBM technology has provided a strong technical support for efficient exploration and development of upper-deep oil and gas resources in Tarim Basin, and it has brought great economic and social benefits.
Solving 16" Deep Harsh Drilling Environment Challenges in South East Kuwait
Authors: Abdullah M. H. , Esmaiel A. H. , Al-Sarraf A. Q. , El Heiny A. H. , Maouche Z. , El–Gayar M. M.
Published: November 2016

The 16′ Vertical Performance Motor Section is the most challenging section in Exploration Deep Drilling in Burgan Field & All South East Kuwait. The section comprises drilling hard and abrasive Zubair formation followed by reactive Ratawi Shale formation. Several technologies were introduced during the last ten years in search of an economic solution to deliver this section safer and faster with limited success. The objective of this paper is to present the process and technology implemented to drill Zubair and Ratawi Shale formations in two different wells with the same bit at record rates of penetration.

Bit durability is generally the main driver in the 16′ section performance. Historically, one to two polycrystalline diamond compact (PDC) bits were utilized in this section and were pulled out for low penetration rates. The new solution required a thorough offset data analysis, including formation porosity, rock strength and abrasiveness analysis, applied drilling parameters and Mechanical Specific Energy (MSE) analysis using software. A customized PDC bit design was then developed using a state of the art bit/formation interaction model combined with an advanced cutter technology and hydraulics pairing for ultimate cutter cooling.

The new PDC bit design and the implementation of the softwares used to analyse offset wells drilling parameters and rock mechanics had a significant effect on the bit durability and Rate of Penetration (ROP). The optimized drilling parameters applied as per the former set roadmap aided in managing the bit cutting structure through Zubair and Ratawi Shale formations and the bit was pulled out in re-runnable condition with a new field ROP record. The same bit was then used again in different well and drilled Zubair and Ratawi Shale formations and pulled out with 1, 3 dull condition. Over the two wells drilled, the optimized drilling plan saved National Oil Company over US $200,000, reducing the cost per foot (CPF) drilled by 38% over the field average CPF, increasing the ROP by 55% over the field average and drilling 69% footage more than the previous section benchmark footage.

With the engineering evaluation of the offset data and the utilization of the new bit design, National Oil Company managed to drill Zubair and Ratawi Shale section in two different wells with the same bit for the first time and was able to improve drilling efficiency and cutting the drilling cost by eliminating bit trips and cost of new PDC bits.
New Inertial Steering Mode of Point-the-Bit RSS Expands Tool Operational Envelope
Authors: Hussain Sajjad , Li Fei , Rana Vikram , Sharma Varun , Dhaher Karam Sulaiman , Blackburn Jason , Haaland Sigurd , Sivertsen Atle , Eshraghi Daniel , Dashtpour Reza , Lunkad Siddhartha , Hongdul Thanong , Bairwa Girish Kumar
Published: November 2016

The point-the-bit rotary steerable system (RSS) is frequently used for high-profile directional drilling jobs in challenging environments that require high degree of directional control.

To achieve toolface control, the point-the-bit RSS control system requires two inputs: the rotation rate of the collar (CRPM) and the toolface orientation of the bit shaft. Previously, the tool utilized magnetic field measurements to compute the above two parameters and, subsequently, control the toolface for the well trajectory. However, the point-the-bit RSS steerability is compromised in a blind zone (where magnetic field measurement is significantly interfered with, such as inside casing, drilling out of a whipstock window, or close to offset wells, or does not have enough signal strength, such as in a zone of exclusion (ZOE) where the Earth's magnetic field projection on the cross section of tool is low. The new inertial steering mode of the point-the-bit RSS uses accelerometers and a rate gyroscope sensor to steer the tool, and it can be toggled on or off by a mud downlink. This inertial steering mode effectively expands the operational envelope of the point-the-bit RSS by improving tool steering ability when the tool is in a blind zone or ZOE.

Four successful field runs have been completed on one of the largest mature fields in North Sea Continental Shelf (NCS). In the first field run, the new inertial steering mode of the point-the-bit RSS was used to kick off a well, which is close to seven nearby producing wells, from an openhole cement plug through a 37-m narrow window between the 20-in. casing shoe and 13 3/8-in. casing stump and to drill a 17 ½-in. section in the same run. The new inertial steering mode helped to steer in the desired direction with good tool face control in the presence of high magnetic interference. In the second field run, the RSS tool successfully exited the whipstock window and steered in the desired direction using the new inertial steering mode, providing planned separation from the cuttings re-injection (CRI) zone and drilling the 12 ¼-in. section to target depth (TD). In the third field run, the new inertial steering mode was deployed to exit the whipstock window, drill the 8 ½-in. section to TD, and land on top of the reservoir close to five offset wells with a minimum 14-m center–to-center distance. The fourth field run helped the operator to exit whipstock window inside the 13 3/8-in. casing and steer the 12 ¼-in. section underneath motherbore in a high magnetic interference and collision risks environment.

Based on the four successful runs, the new inertial steering mode of the point-the-bit RSS has been proven for its tool face and trajectory control, expanding the tool's operational envelope.
A Method of Quickly Evaluating the Fracture Complexity of Network Fracturing
Authors: Yuan Xeufang , Zhang Yang , Liu Ju , Peng Fen , Teng Qi , Xiao Yang , Yi Xiangyi , Han Xu
Published: November 2016

Gas reservoir K in Tarim oil field which is an abnormal pressure fractured tight sand reservoir may generate complex fracture due to the high rock brittleness. Microseismic monitoring technology is a effective methods of evaluating the network fracturing, but it had been limited by economic cost and service conditions. With the extensive application of SRV, it is necessary to develop a fast and economic way to evaluate the complexity of network fracture in hydrofracture. The reservoir types and the fracture morphology were evaluated by analysis on the pressure drawdown after pumping, and the fracture complexity evaluation was completed by G function feature identification. Based on the above two points, a fast method of evaluating the complexity of network fracture had been created. The results of microseismic monitoring in several wells had verified the feasibility to this method which will provide basis and support for production prediction.

The date matching results shows that this method in our study strongly consistent with the collected field information. So, we can draw some conclusions as follows: (1) the analysis of pressure drawdown based on injection/drawdown theory could effectively identify the main flow types after stimulation. (2) the complexity of fracturing cracks and the natural fractures could be identified with G function analysis. (3) the results concluded by analysis of pressure drawdown and G function is consistent with the conclusion with Microseismic monitoring technology. The advantage of this research is that a rapid and practical evaluation method based on the fracture complexity evaluated by pressure drawdown analysis and G function analysis for hydraulic fracturing is formed.
Polymer EOR - A New HSE Hazard in an Old Industry
Authors: Bridgewater S. , Goldszal A. , Milani A.
Published: November 2016

There is an increasing trend in the oil and gas industry for the use of Enhanced Oil Recovery (EOR) techniques to improve the oil recovery from the reservoirs. The industry is well established to manage the hazards associated with hydrocarbon liquids and gases. However, polymer powder, used for Chemical EOR, presents a new set of hazards that needs to be incorporated into the HSE design of these facilities. This paper presents the main HSE design aspects to be addressed for the management of the process safety, environmental and personnel safety hazards introduced by polymer EOR facilities in the oil and gas industry.

Total has conducted a number of Chemical EOR studies and implemented pilot plants, with an aim to developing full oil fields based on polymer flooding of the reservoirs. A comprehensive review of these polymer projects has been carried out and the HSE lessons learnt have been assessed. Information from polymer suppliers has also been reviewed, supported by an extensive literature review of the HSE requirements and standards for other powder handling industries. The review focused on the HSE design aspects for those polymer EOR projects that use powder as the source material.

Hazards related to the handling of powder based products are effectively managed in other industries and documentation exists to guide designers on the requirements for managing these hazards in their processes. The use of polymer powder is not new to the oil and gas industry, however, very little guidance exists, to account for this hazard as part of the HSE design of the oil and gas facility, as it is less understood compared to the hazards presented by flammable oil and gases. An HSE guideline has been prepared to enable a better understanding of the hazards of using polymer powder in EOR facilities. The guideline serves as a bridge to facilitate the incorporation of this new hazard into an already established safety design management process. This paper presents the main HSE design aspects from this guidance document and addresses key areas such as flammability and dust explosion; area classification and ignition control; drainage and spill containment. The personnel safety requirements to protect the plant operators are also addressed.
A Probabilistic Model to Evaluate the Operation Reliability of the Underground System in Underground Gas Storage Transformed from Depleted Gas Reservoir
Authors: Song X. , Peng C. , Li G. , Wen K.
Published: November 2016

Underground gas storages (UGS) have been built around the world. Several UGS are transformed from depleted gas reservoirs near Beijing. UGS wells always endure complex working load, having high possibility of failure. Besides, repetitive injection/production circles induce dramatic periodic changes of pore pressure and wellbore stresses, meaning formation breakdown can be triggered. On account of these facts, it remains necessary to verify whether we can produce or inject gas as planned in UGS.

A probabilistic model based on stress-strength interference theory is set up to evaluate the reliability of the underground system, i.e. wellbore (tubing, casing and cement sheath) and formation. Firstly the strength and stress functions are established with material parameters and in situ stresses for these four parts. The parameters and forces are random variables in nature so all the strength and stress are random variables as well. Special attention is paid to the effect of erosion. Then the operation reliability of each part is the probability that strength is larger than stress, obtained using Monte-Carlo method.

The total operation reliability of underground system is defined as the weighted average of the reliabilities of the four parts. With productivity formula and wellbore flow equations embed, this probabilistic model is able to give the reliability (probability) of the underground system accomplishing the task of injecting/producing scheduled amount of gas into/from the formation within scheduled days. Note that the everyday change of pore pressure is considered in order to monitor the change of operation reliability with time. Several validation cases including injection and production are given and this model is able to give the operation reliability. It can help to clarify the potential problems such as casing collapse and sand production so that advance workover or adjustment can be performed. It is concluded that the probabilistic model raised in this paper is not only reasonable in theory but also cogent in practice.

This is the first time that stress-strength interference theory is employed to evaluate the reliability of the underground system in UGS. It is proven this model is valid and tress-strength interference theory has the potential to be applied in other reliability estimations of petroleum equipment and structures.
Unlocking Future Petroleum Potentials with Exploration Discoveries in North Malay Basin, Malaysia-Thailand Joint Development Area
Authors: Adnan M. Mohd , Ismail W. Wan , Kaewtapan J. , Setiawan A. S , Tanprasat S.
Published: November 2016

A comprehensive technical evaluation was conducted after the completion of six exploration and appraisal wells to assess the future petroleum potentials in North Malay Basin, offshore Malaysia-Thailand Joint Development Area (MTJDA). This paper focuses on major discoveries and findings from key wells, namely Well-E3, Well-A2ST, and Well-T3 to better understand the petroleum potentials for the subsequent development planning.

Well-E3 and Well-A2ST were drilled to investigate the stratigraphic trap play in the eastern flank of MTJDA and to explore the hydrocarbon potential in deeper depositional sequence below DS10 interval. The seismic dataset and amplitude analyses were used to identify channel fairways and qualitatively predict sand presence for well planning optimization. Both wells encountered gas-bearing sands with proven stratigraphic trap style, requires channel orientation oblique with the axial anticline structure. Full integration of well log dataset, formation pressure test and seismic attribute analyses have proven the exploration intervals with gas-bearing sands discoveries. In addition, rock physics analysis was performed to differentiate gas from wet sand and coals.

Well-T3 was drilled in the western flank to appraise the seismic anomaly associated with hydrocarbon sand and to investigate the CO2 content in the southernmost extension of hydrocarbon accumulation. The anomaly is observed as two distinct sand fairways of channel-bar complex. The northern lobe was dissected by deep seated fault system with high CO2 content. The southern lobe appears to be free from deep seated fault system. Well-T3 was drilled in the area where CO2 pathways was expected to have no connection with deep seated fault system and lower CO2 content than the main area. Formation pressures, samples and seismic anomaly supported the hypothesis that the northern and southern culminations are not connected with significant stratigraphic heterogeneity interpreted. An important oil discovery was also observed from pressure gradient and samples as the first oil discovery in the western flank.

Full integration of the well log dataset, formation pressures, seismic attribute analyses and rock physics modeling have resulted in an improved understanding of reservoir distribution and reduced the degree of uncertainty in reservoir connectivity, thus allowing a more robust development strategy. The new discoveries of proven stratigraphic trap in the eastern flank with deeper hydrocarbon culminations and proven oil discovery in the western flank with enhanced understanding of CO2 content have triggered more future petroleum potentials in MTJDA acreage.
Applying the Learning from The Gulf of Mexico Response to Enhance Emergency and Oil Spill Preparedness
Authors: Flynn Steven A
Published: November 2016

Extended Abstract

The Macondo blow-out in the Gulf of Mexico in 2010, and the earlier Montara incident in Australia, led the entire oil and gas industry to review both drilling safety and oil spill preparedness. As a result, the International Oil and Gas Producers Association (IOGP) established a multi-year programme to embed the learning from these and similar incidents, and to enhance future prevention and preparedness. This presentation provides an overview of the latest practical tools that can be used by operators to improve their emergency and spill response plans.
Wavelet Extraction and Local Seismic Phase Correction Using Combination of Different Moment
Authors: Naghadeh Diako Hariri , Morley Christopher Keith
Published: November 2016

In this paper wavelet phase is extracted using a combination of different moments (CDM), which is introduced as an indicator of localized seismic signal phase. The analysis demonstrates sharpness of the probability distribution of a discrete time series that is more robust than applying kurtosis. The improvement occurs because zero-phase wavelets with reverse polarities have equal maximum kurtosis value hence the correct wavelet polarity cannot be identified. Zero-phase wavelets with reverse polarities have minimum and maximum CDM values. Those enable the technique to handle a finite data segment based on the combination of different moments and it can also choose the correct wavelet polarity. High order statistics are sensitive to outliers so they will be instable in region with high level of noise. Combination of different moments can solve or decrease this limitation because of existing of low degree behind high degree moments. The most important parameter for correctly estimating the phase pertains to the best length of time window used for phase correction. Incorrect window length creates non-zero phase wavelets. To decompose signal to wavelets, an envelope of each trace is applied. Based on the time distance between two minima of envelope value, it is possible to choose the wavelet lengths to do phase correction. Synthetic and real data examples are used to demonstrate the effectiveness of this method in both wavelet extraction and for local correction of signal phase. Results of the seismic phase correction using this method demonstrate superiority than the local kurtosis method, because of high stability and dynamical range.
Rock Physics Applications for Seismic Interpretation in the Gulf of Thailand
Authors: Wilkins Michael , Pambayuning Sherry
Published: November 2016

Before undertaking any seismic interpretation project, it is essential to understand the rock physics of the area so that the interpreter knows what to look for in their seismic. Rock physics modelling can be used to predict the effects of lithology, fluid, porosity, depth and sand thickness on the seismic response. It can also help to understand whether direct hydrocarbon indicators (DHIs) such as flat spots, bright spots, dim spots or polarity reversals are expected and also the best seismic attributes to use to identify hydrocarbons. Well ties can be used to determine the quality of the seismic data and infer how reliably predictions based on the rock physics can be applied back to the seismic data.

The rock physics of several producing assets across the Gulf of Thailand have been examined and compared. Rock properties of over 200 wells have been analyzed based on stratigraphy, lithology, fluid fill, facies, porosity and depth. It was observed that the rock physics could be split into two distinct regimes based upon depositional environment separated by a key unconformity.

The first rock physics regime is observed in the shallow high porosity fluvial systems found within the Nong Yao Field and the younger reservoirs of the Jasmine and Manora Fields. In this regime, seismic attributes and seismic inversion have been successfully used to predict sand presence and thickness. Sands and shales have distinctly different rock properties and sands produce a strong class III-IV Amplitude Varation with Offset (AVO) response. Fluid effects can be observed on seismic although it is difficult as thickness and porosity changes may be incorrectly interpreted as fluid changes. The second rock physics regime is observed in the older, lower porosity lacustrine system found within the main reservoirs of the Manora Field and the pre-MMU reservoirs of the Jasmine Field. Within this regime, lithology prediction is much more difficult as sands and shales have very similar properties. Sands are modelled to have a class I-II AVO response and fluid effects are minimal.

Understanding the rock physics of these fields allows future work to be focused appropriately. At the Nong Yao Field and in the younger section of the Jasmine Field, technical work is focused on seismic inversion, seismic attribute analysis and other geophysical techniques for lithology and fluid prediction. Whereas at the Manora Field and in the older reservoirs of the Jasmine Field, technical work is focused more on structural mapping and geological modelling, and amplitude analysis is of lower priority.
Innovative Booster Compressor for Marginal Wellhead Platform
Authors: Sillapacharn Thitinun , Srichompoo Sireekorn , Hoonsuwan Phakhachon , Aroonsangob Peeradet , Jirarungsakunruang Sumate , Nitipan Tunchanok , Vasansiri Kritithy
Published: November 2016

It is recognized that several problems, including equipment redundancies and valuable space consumption, exist in the wellhead platform. For example, there are separators installed to separate gas and liquid that come from reservoirs at various operating pressure conditions. The challenge is to integrate these separators in to a single separation unit for space reduction as well as to broaden operating conditions to serve multiple process conditions.

A three-phase test separator together with drain vessels are installed at the wellhead platform in order to execute reservoir management, well monitoring program, and well intervention activities – such as well clean-up during start-up and liquid unloading where gas flow rates are too low for export due to liquid obstructions in well tubing. Furthermore, booster compressor and associate separation system are installed when the wells deplete to the point where they cannot be produced at under natural production conditions. The operation of the booster compressor allows lowering of the wellhead flow pressure and increasing in the reserve recovery factors.

To address the concerns of the oil price crisis and smaller gas prospects in the field, an Innovative Booster Compressor Package has been developed to serve two aspects of value improvement, (i) to minimize an investment cost and (ii) to maximize and ultimate recovery reserve.

To minimize an investment cost, the booster compressor inlet separator and separator blowcase were re-engineered and modified in order to maintain functions of test separator. The gas and liquid flowmeters can work together with an additional watercut meter enabling the determination of fluids flowrate. During the well unloading operation, well fluids entering the inlet separator at very low pressures and will be transported to the export pipeline with assisted gas from the booster compressor discharge line. This modification results in the elimination of the three-phase test separator and the drain system.

To maximize an ultimate recovery reserve, a compressor will either be operated at a high pressure suction with two parallel cylinders, or at a low pressure suction with two cylinders in series configuration. This allows lowering of the abandonment pressure and increasing the recovery factors of these wells. As a result, this swicthable configuration concept can incrase gas protential and assist in sustaining gas production.

A successful development of the Innovative Bosster Compressor has two benefits. First, at least twenty percent (20%) less investment cost is achieved because of the direct cost savings from vessel integration and from topside-area optimization. Second, an estimated ultimate recovery gain from a switchable low pressure booster compressor is expected at about three percent (3%) higher. These are significant efficiency improvements in the economics of the E&P industry.
Engineering a Fit-for-Purpose Bit Doubles Performance and Durability in Abrasive and Impact-Prone Formations
Authors: Agawani Waleed , Al-Saffar Waleed M. , Omar Marwa , Al-Shehab Ahmad Y. , Taha Mohamed , Ahmed Tausif , Abdelhamid Atef , Al-Awadhi Shaimaa
Published: November 2016

The Umm Gudair 12.25-in. vertical drilling performance section involves several technical challenges for engineering an application-specific PDC bit. The interval consists of two formations that require contradictory bit design principles. The abrasive Zubair formation incorporates sandstones interbedded with hard shale streaks, followed by dual Ratawi intervals of hard shales that are succeeded by compacted limestone. The initial sand interval abrades the cutting structure, resulting in slower rates of penetration in the deeper carbonates. The premature dulling of cutters then causes lower carbonate drilling efficiency. Typically, the section is drilled at 35 feet per hour (fph) and requires 2 bits to complete.

After reviewing offsets with faster than average rates of penetration that successfully completed the interval in the same application, a design compromise was achieved. The new optimized bit design is based on a seven-bladed bit with sixteen-mm cutters. Subsequent design iterations optimized the cutter selection and the cutting structure to maximize durability in the sands while remaining aggressive enough to drill the lower carbonates. An iterative design-and-simulate process then followed, simulating bit stability against formation strength data and optimising drilling fluid flow dynamics. The design was adjusted repeatedly based on the simulation results until a balance in aggressiveness, stability and flow was reached.

After the design process concluded, optimal drilling parameters for each formation were drawn up from offset wells, and the new design was field tested. Drilling stability improved in the sand interval while cutting structure integrity was sustained into the deeper carbonates, resulting in improved rates of penetration in both intervals. After several runs, the results demonstrated that significant gains in rates of penetration were made; reaching over 90 feet per hour (fph) in some cases, almost doubling current rates of penetration. The post-run dull condition of the bits tended to be virtually new (1-1-WT), and in one instance the bit re-ran on a second well, drilling the interval at 53fph.

This paper demonstrates a successful engineering design process for such a challenging section in the Umm Gudair Field. It then highlights the technologies featured in this bit and their value in drilling this application. Finally, field test results are analysed and the improvements in drilling performance and time and monetary savings to the operator are quantified.
Full Waveform Inversion of Cross-Dipole Acoustic Waveforms
Authors: Fuse S. , Mikada H. , Takekawa J.
Published: November 2016

In the present study, we examine the possibility to estimate the anisotropic properties of formations from the waveforms obtained by acoustic logging using numerical simulation. Our numerical model includes a vertical borehole in anisotropic layer with various azimuths. The anisotropic layer is set as transversely isotropic medium with a horizontal axis of symmetry (HTI) or transversely isotropic medium with a tilted axis of symmetry (TTI) which has 5 independent elastic parameters in the stiffness matrix. It has been assumed in the acoustic logging that the medium to estimate the anisotropy is HTI or TTI with a subtle tilt angle under the assumption of weak anisotropy and the shear wave splitting is used to estimate the azimuthal angle and the order of anisotropy with cross dipole acoustic measurements. Since it is necessary to have a general method that could deal with TTI in terms of both the tilted angle and the order of anisotropy, we conduct numerical experiments under a hypothesis that the cross dipole waveforms could be exploited for further data processing. We then apply a method of Full Waveform Inversion (FWI) for acoustic logging model in isotropic medium to investigate the effectiveness of the method. Our results show that the waveforms include information about the anisotropic layer even if no difference can be observed in the travel time. Besides, it is suggested that FWI technique for anisotropic medium should be useful to estimate the anisotropic parameters in the acoustic logging.