bluuebunny/crossref_metadata_2025_split huggingface dataset:
Hydraulic Fractures Monitoring using Microseismic Techniques in Clastic Reservoir - A Pilot Test Case from India
Authors: Lim T. K. , Mishra S. , Gupta A. 
Published: January 2012

Abstract
Clastic gas reservoirs can be made economical through effective stimulation techniques. Hydraulic fracture mapping based on seismic techniques can lead to better understanding of the effectiveness of reservoir stimulation, when combined with in-depth reservoir geology and geophysical knowledge make development of such fields feasible.
Two stages, out of five hydraulic fractures stimulation were monitored and mapped in an attempt to assess the fracture propagation in a clastic gas reservoir located in Rajasthan, Western India. This was the first hydraulic fracture monitoring in India using downhole wireline sensors whereby recorded microseismic (MS) events indicating fracture growth as they are being created by rock failure. Events triggered by the stimulation treatment are detected and located in a four-dimensional (4D) space (space and time) relative to the well being treated.
The microseismic images indicate that fractures are well distributed within the Upper and Lower Fatehgarh formations, in the north-east south-west azimuth. The first monitoring was done on Stage-4 and recorded very few MS events, but indicated a relatively contained fracture. The fracture geometry estimated from the mapping matches closely with the parameters anticipated from the frac modeling work. The second monitoring was done on shallower Stage-5 and showed downward height growth during the initial stage of the treatment. This observation indicates that the hydraulic fractures may have intercepted a fault located within the treatment well. The result is being integrated with the planned stimulation model, mini-frac data, stress profile and other geological information. This will help in calibration of the stimulation model. Understanding of the fracture geometry from this technique along with the fracture geometry available from fracture modeling, well testing, etc. shall be combined to arrive at optimized designs for future fracturing campaigns in this clastic gas reservoir.
An Integrated Pore-Pressure Prediction Approach: A Success Strategy to Develop Deep Gas Reservoirs by Drilling through a Highly Depleted Shallow Zone, Semberah Field, East Kalimantan, Indonesia
Authors: Jauhari Usman , ST Slamet , Anggraini Dayu Agung , Sinaga Iranta Bona , Widiastuti Bhakti 
Published: January 2012

Abstract
The Semberah field is one of the main oil and gas producing areas operated by VICO Indonesia in East Kalimantan, Indonesia. Production from this field has been focused mostly from shallow-level reservoir (C-I intervals). After production of more than 30 years, the shallow and high-permeability intervals are currently highly depleted. Meanwhile, deep and low-permeability reservoirs (J level) have rarely been penetrated leaving significant reserves. Accessing these reserves is a highly challenging work today. A recent well was drilled to access the reserves in a J sand but the drilling had to be stopped earlier due to total loss of circulation whilst penetrating a shallow high-permeability and highly depleted sandstone I082A.
An integrated pore pressure prediction approach has been carried out during the planning of drilling and completion of a proposed S86 well. The objective was to successfully access deep target reserves in the J sandstone by safely drilling through the highly-depleted I082A sandstone. The approach integrated available data including well logs, cores, formation pressure, historical-match derived pressures, and drilling parameters.
Pore pressure prediction showed that the proposed S86 well would penetrate normal pressure regime (8.45 ppg) to –8,500’ SS. Within this interval, variously depleted reservoirs (3–6 ppg) would be penetrated. Starting from –8,500’ SS to –10,680’ (TD), the well was predicted to enter overpressure environment (8.45–13 ppg). Within the environment, a higly depleted I082A with 500 psi (0.87 ppg) was estimated to be encountered at ~8,819’ SS. The pore pressure prediction study recommended 1) to drill with normal mudweight of 10–12 ppg and set 9–5/8" casing point before penetrating I082A sandstone, 2) to drill through I082A to its bottom with low mudweight (8–9 ppg) and isolate with 7" short liner, 3) drill 6" open-hole to TD with high mudweight (12–13 ppg). The newly proposed well safely drilled through the highly depleted I082A sandstone and access to the reserves in the targeted J sandstone was successfully achieved. This great success has opened up an opportunity for further development drilling in the Semberah field.
Innovative Water Shut Off Solution Combining Real Time Downhole Measurement and Analysis with Zonal Isolation Technologies for Horizontal Open Hole Producer in Ratawi Field - A Case History from Partitioned Zone
Authors: Utomo Bagio , Al-Harbi Mosad , Razzak Shehabuddin , Al-Hadyani Fahad S. , Hamid Saad , Shaheen Tarek , Noya Vidal , Boonjai Pimteera 
Published: January 2012

Abstract
The increasing water production in mature fields has a significant impact on production economics. A structured approach is required to tackle this challenge. Water shut-off (WSO) operations in open-hole horizontal wells do not carry a high success rate, however, careful candidate recognition and treatment can improve the chance of success. Ratawi is an Oolitic Limestone reservoir in Wafra oilfield, Partitioned Zone (PZ) between Saudi Arabia and Kuwait. The reservoir has been undergoing water-flooding for pressure maintenance since 1998. Majority of the wells are completed as open-hole horizontal producers on artificial lift.
The paper describes WSO performed in the biggest water producing well in Ratawi field with 94% water cut. Being located in the crestal area, where the preservation of reservoir energy has been a focus of the reservoir management strategy, made it a prime target for WSO which could lead to water flood optimization and improved sweep efficiency. The water shut-off treatment was designed with two-fold objective; primarily, to plug-off the fractures and the near wellbore area suspected to produce water and secondly, to isolate the open-hole to prevent the damage to the oil bearing zones.
The challenging conditions for WSO required a synergistic approach by combining the latest technologies to achieve the desired objective. Real-time downhole measurements from the Fiber Optic Assisted Coiled Tubing (FOACT) were combined with the Open-Hole Inflatable Bridge Plug (OHIBP) to improve operational reliability while reducing risks of failure. The real time measurements assisted in reliable single-run OHIBP inflation under sub-hydrostatic conditions and also played a vital role in fine tuning the gel concentration in real time based on the formation response.
Due to this holistic approach, 4000BWPD was eliminated and 30% oil gain was observed without any subsequent acidizing. Moreover, the additional cost of a replacement well and abandoning the existing well was saved. The success of this treatment opens the opportunity to apply the same technique to other potential candidates across the globe.
The Natural Fracture Evaluation in the Unconventional Tight Oligocene Reservoirs - Case Studies from CuuLong Basin, Southern Offshore Vietnam
Authors: Li Bingjian , Ngoc Nhi Nguyen Do , Nguyen Quan Quoc , Dong Hoang Ngoc , Duy Cao Le , Weichman Dave , Farag Sherif , Phuong Pham The 
Published: January 2012

Abstract
The Oligocene Formation in CuuLong Basin, Southern offshore Vietnam, is predominantly fluvial-lacustrine sand and shale sequences deposited above the pre-Tertiary granite basement. The reservoir sands are usually tight with average porosity about 10%, and variable but mostly low permeability. In many wells targeting the granite basement, significant oil shows have been detected when drilling through the Oligocene section. However, it is usually difficult to get a well to flow naturally from this section due to the tight matrix. Therefore, the Oligocene sands were rarely paid much attention.
With commercial discoveries of both oil and gas made in several fields in the CuuLong basin recently, reassessment of the potential for the Oligocene sands has been brought back to the agenda. Natural fractures or faults are among the most important aspects to evaluate when assessing this tight formation. This paper presents a few recent case studies on fracture characterization for the Oligocene reservoirs. The data used includes core, borehole images, conventional open-hole logs, mud logs as well as DST dynamic data. Natural fractures including both open and mineralized ones are quite common in the tight Oligocene formation even though the fracture density and type might vary from one well to another depending on the structural location of the well, proximity to faults and depth in the vertical sequence. It is believed that the naturally open fracture or fault plays an important role in enhancing the reservoir permeability for potential natural flow in a well. The healed fractures, on the other hand, might block the lateral reservoir communication. Locating the fractured zones is also important for perforation decision and frac job design, if stimulation is required for a well.
Fluids Re-Injection (FRI): A Waste Management Technique
Authors: Al-Duailej Yasser K. , Al-Khaldi Mohammed H. , Al-Yami Ibrahim S. 
Published: January 2012

Abstract
Disposal of produced fluids, during different well activities, has been one of the main challenges for field operators due to environmental and economical concerns. The limitations on the discharge of oily wastes in addition to other regional regulations have resulted in several efforts to develop technologies and techniques that can be utilized as on-site disposal mechanism. One technique is to re-inject produced fluids into non-productive permeable zones of adjacent wells.
A comprehensive lab investigation was conducted in order to explore the feasibility of re-injecting various produced fluids during different activities such as mudcake clean-out, completion, or well stimulation treatments. This study includes also a detailed investigation of emulsion and scaling potential of various produced fluids mixtures: oil/clean-out fluid, oil/spent acid, spent acid/formation brine and clean-out/formation brine. In addition, a series of coreflood experiments was conducted to assess the effect of produced fluids injection on the initial permeability of core plugs taken from non-productive sandstone formation. These experiments were conducted at reservoir temperature using representative cores and collected produced fluids.
Coreflooding experiments showed that the effect of oil injection on core plugs permeability was mainly constrained by the initial core permeability. In tight cores, K = 25 mD, injection of oil damaged the core by forming external oil filter cake on the face of core. However, in cores with high initial permeability, K &gt; 1 D, nearly 10 PV of produced oil was injected with no observed formation damage. Similarly, clean-out fluids/oil mixtures were also injected with no observed formation damage. In contrast to oil/clean-out fluids, spent acid/oil injection effect on core permeability value was dependent on injected spent acid type. This paper provides the recommendations and limitations of using produced fluids re-injection as a waste management technique.
Experimental Design to Optimize Operating Conditions for SAGD Process, Peace River Oilsands, Alberta.
Authors: Nguyen Huy X. , Wisup Bae , Tran Xuan V. , Chung Taemoon 
Published: January 2012

Abstract
The SAGD process is a promising recovery method for producing heavy oils and bitumen resources. However, SAGD process has several economic risks including the high capital cost of initial investment for building ground facilities and uncertainties related to oil and gas prices. These risks may be critical in SAGD operation if the design for initial operating conditions is unsuitable. In order to ensure maximize profitability, optimal operation conditions should be evaluated by reservoir simulations.
In this study, central composite design and response surface methodology (RSM) were applied to determining optimal conditions for SAGD process. It was aimed to mitigate the risk of incomprehensive economic assessment on the process operation. The study started with the central composite face-centered (CCF) design to screen variables, and then insignificant variables were excluded from the study before developing the optimal design by response surface method. A two-stage approach was employed based on the efficient local optimization. At first, an initial sample of design was obtained using design of experiment technique. Simulation runs for design points were used to estimate oil recovery as well as NPV for each case. Based on the standard of CCF design, total 28 cases was run to optimize the parameters of operating conditions and the NPV responses during 10 years of simulation period. Second, RSM was used to search for promising designs in contour plots and response surface map. The best choice of operating conditions for maximizing the NPV correspond to well pattern spacing of 78m, steam rate of 640 m3/d, injector producer spacing of 14m, injection pressure of 6330 kPa, subcool 8°C, respectively.
Simulation results showed that cumulative oil for Fast-SAGD process does not significantly increase and even NPV is the lowest among the mentioned SAGD cases. In addition, cumulative oil recovery of SAGD1 base case is higher than those of SAGD2 and Fast-SAGD cases, as well as the lowest CSOR. However, in the economic point of view recognized that the case SAGD2 achieves the highest NPV, with the predicted values matched the experimental values reasonably well with R2 of 0.99 and Q2 of 0.88 for NPV response, while the NPV of Fast-SAGD process is the lowest because of the increasing capital cost for additional offset wells. Actually, the difference of 10kPa between steam injection pressure and reservoir pressure is not sufficient to increase the NPV for both Fast-SAGD and SAGD1 base case operations. The high cumulative oil is favorable conditions for accelerating profit, but oil and gas prices at that time is crucial to decide for operation conditions in heavy oil projects.
Challenges of Recovering by-Passed Condensate in Al-Raja Field Utilizing MBO Method
Authors: Gunawan Indra , Al-Abbasi Omar 
Published: January 2012

Abstract
This paper presents a case study on a reservoir simulation modeling of recycling gas condensate using Modified Black Oil formulation (MBO) to identify and recover the by-passed condensate in Al-Raja Field. Al-Raja field is a good candidate to utilize MBO formulation instead of fully compositional due to following reasons (1) Gas injection/recycling is able to maintain the reservoir pressure above or at the dew point pressure in Al-Raja Field. (2) by keeping reservoir pressure above dew point pressure, gas injection will prevent any Retrograde Liquid Deposit (RLD) occured in the reservoir. It was well accepted methodology that MBO can be used in lean to medium rich gas condensate reservoir under gas cycling above dew point.
Al-Raja field is located in the Eastern part of the Marib-AlJawf Basin Republic of Yemen. The field has a moderate-size medium rich gas condensate reservoir with an average gas production rate of 750 MMscf/D from 18 wells. The lean gas is being re-injected back into the reservoir using line-drive pattern wells. Some make up gas from nearby fields was provided to replace fuel and shrinkage volumes. The high vertical relief of the field structure leads to significant temperature gradient that resulted in challenges to model the oil-gas ratio (Rv). The primary objective of the study is (1) to evaluate the current gas recycling performance at well and field level, (2) identify the location of current by-passed condensate (3) utilize the model to improve and optimize the liquid recovery through several options of optimum field developments (infill wells).
To achieve the objectives, 3-D Static and Dynamic models with 4 components MBO definition were constructed. In this study, we will show how to generate PVT Modified Black Oil (MBO) properties such as solution gas-oil ratio (Rs), oil-gas ratio (Rv), oil formation volume factor (Bo), and gas formation factor (Bg), from PVT-EOS. Whitson and Torp procedures were selected to calculate MBO properties from PVT experimental data of gas condensate.
The use of the MBO approach enabled us to perform faster field performance history matching compared with the compositional. This approach preserves less run time to conduct the Al-Raja prediction including infill drilling optimization. The condensate-gas ratio distribution achieved after the history match process guided us to locate the optimum infill well locations in by-passed area for the future development. Moderate condensate areas were located, and several wells have been drilled and proved to be successful. More infill wells were recommended to raise the field production and recover the remaining reserve
A Novel Well Annular Barrier Solution Alternative to Swellable Casing Packers
Authors: Plessing Hans , Arnskov Michael Macdonald 
Published: January 2012

Abstract
Reservoirs with unstable formations or unable to sustain traditional cementing or other zonal isolation requirements may necessitate that additional external packers are incorporated. in the completion solution. Polymer-based packers are widely used in such cases as they are relatively uncomplicated to deploy, however, the degradeable polymers as such do also introduce an additional uncertainty and risk.
The approach presented is based on a solid metal expandable system developed for the applications where inflatable external casing packers traditionally have been used. The well annular barrier provides long term robust and reliable zonal isolation in cemented or un-cemented completions and may also be used in conjunction with liners or long-string casing. Additionally it provides higher differential pressure capacity and higher expansion coefficients without compromising the inner diameter. Consequently it does not impair or restrict flow conditions and furthermore enables subsequent well maintenance to take place unhindered.
The paper presents the development of a new solid metal expandable system for external casing applications and discusses the rationality behind the technology.
Crude Oil Recovery from Sludge Treated by Low IFT Micellar Emulsion
Authors: See Chun Hwa , Saphanuchart Wasan , Looi Ming Hoong , Loke Yoong Shang 
Published: January 2012

Abstract
Over time, crude oil in ship tankers will destabilize where heavier component of crude oil such as emulsified crude oil with sands, are partitioned at the bottom of storage tank. The presence of these components at the bottom of the storage tank such as water-in-oil emulsion, sands and insoluble heavy metals, will result in increase in density, viscosity and reduce in flowability. This thick and viscous mixture is called crude oil sludge. This part of the sludge normally tend to have high pour point (higher than ambient), up to 10 wt% of sands, water and heavy metals. The sludge is conventionally removed from the storage tank by using mechanical way in combination with high pressure hot water stream. The treated sludge from this process is normally highly viscous, &gt;10,000 cP, and contain around 5-40 wt% of water. This sludge is a water-in-oil emulsion stabilized by the natural emulsifiers in original crude oil. Fine solid in the sludge is another factor to stabilize the water-in-oil emulsion by adsorbing at the oil/water interface. The high emulsion stabilization and high viscosity leads to difficulties in post-treatment to recover the oil, especially when the sludge has very high wax content.
This paper presents a case study of applying a biodegrable, low IFT (interfacial tension) micellar emulsion and solvent extraction for recovering oil from highly viscous crude oil sludge, which could not be recovered by the current processes. This process yields total hydrocarbon (liquid oil and wax) recovery higher than 80%. It could yield approximately 23% recovery of light oil from this sludge (equivalent to &gt;80% extraction efficiency of light oil recovery calculated based on total light crude oil in the original sludge) while the current process does not recovery any light oil. The water stream can be recycled or easily treated. Sand that disposed was found to have less than 2% of hydrocarbons. Additinally, this process can be run at ambient temperature at around 25°C to30°C.
Development of and Validation of Small Volume Multi-Tasking Flow Assurance Tool
Authors: Burgass Rod , Tohidi Bahman 
Published: January 2012

Abstract
Wax and asphaltenes are well known to cause problems through adhesion and build-up on pipeline walls, restricting flow. Deployment of chemical inhibitors is commonly used in subsea pipelines. Measurement techniques for both asphaltenes and waxes commonly show widespread data scatter. Selection of inhibitor chemicals for both wax and asphaltenes are commonly based upon simple tests conducted on stabilised oil samples. This commonly leads to higher dose rates being used than actually required in the pipeline to successfully reduce or eliminate surface build-up.
We have developed a small volume testing facility for measuring wax and asphaltene phase equilibria and optimising inhibitor deployment. The developed device is based on Quartz Crystal Microbalance (QCM) Technology. The QCM is locally cooled to create a temperature gradient between bulk fluid and the surface of the QCM, simulating wall cooling effect. Different temperature gradients could be simulated. The developed device needs 35 ml of fluid and can work at high pressure conditions, simulating effect of pressure and dissolved gas on wax phase behaviour and adhesion tendencies. For wax evaluation, the device can closely simulate a typical "Cold Finger" test with many extra benefits, including; small size of the sample, being non-destructive, real time deposition rate, using live samples (as well as dead/stabilised samples).
In this communication we present some of the results generated using QCM Technology including Wax Appearance Temperatures (WAT) and Wax Disappearance Temperatures (WDT), wax inhibitor screening and results on asphaltene onset determination and inhibitor assessment. Results using the first prototype comparing with "Cold Finger" wax inhibitor screening and showing the effects of temperature gradient and pressure on wax build up for a live oil are presented. The results show that the device and technique proposed in this communication can provide a robust, reliable method for evaluating solid formation and deposition risks using very small sample volumes.
X-ray Micro-tomography Measurements of Fractured Tight Sandstone
Authors: Iglauer Stefan , Wang Shuo , Rasouli Vamegh 
Published: January 2012

Abstract
A tight sandstone was fractured in a triaxial stress cell by injecting fraccing fluid. The specimen was then scanned with a micro-computed tomograph. From the resulting three-dimensional images the fracture morphology and orientation could be determined. Such measurements can be supportive in the development and validation of fracture propagation models. Such models can help optimizing gas and/or oil production from shales, tight sands, carbonates and coal beds.