bluuebunny/crossref_metadata_2025_split huggingface dataset:
Economics of Gas-To-Liquid Processing (The Effect of Scaling on Profitability)
Authors: Uzoh Obinna Vincent , Bretz Robert Elvin 
Published: March 2015

Abstract
Previous economic studies of Gas-To-Liquids (GTL) processes have considered large scale plants for liquid production rates of 50,000 barrels of liquid per day (BLPD) (approximately the equivalent to 500 MMscf per day of gas consumption) or more. This paper is guided by the need to produce "stranded gas reserves" using small scale GTL technology. This study examined simple profitability indicators for small scale GTL plants. We made use of capital cost estimates supplied by a reputable company headquartered in Colorado, for a Fischer-Tropsch plant designed in the year 2000 with a production capacity of 50,000 BLPD.
Exponential scaling was used for estimating the capital cost for a base case unit with a production capacity of 1000 BLPD, or an equivalent typical gas consumption rate of 10 MMscf per day. A base case set of parameters was assumed and the profitability indicators of net present value (NPV) and discounted cash flow rate of return (IRR) were calculated.
A sensitivity study shown on a spider diagram was performed by varying five economic parameters; Capital Cost, Plant Capacity, Product Price, Feed Stock Price and Cost of Trucking. Each of these parameters was varied over an appropriate range while others were held constant. For each combination of parameters the NPV and IRR were calculated and a spider diagram for visualizing the sensitivity was prepared. Our calculations indicate that the profitability is most sensitive to changes in the product price.
Changes in capital costs at a given unit capacity caused the next most sensitive profitability behavior. Profitability is nearly as sensitive to the plant capacity as with the capital cost for a given capacity. Profitability is less sensitive to changes in the cost of the feed gas but over the range of possible costs, it could be a deal breaker. Profitability is least sensitive to the cost of transporting the product.
Our results indicate that under the right circumstances a relatively small GTL plant could be profitable. With success in ongoing work to develop more integrated Fischer-Tropsch (F-T) process, the capital cost could easily be reduced for such a small unit, making the economics even more profitable.
Fracture Characterization using Borehole Image Logs and Seismic Data to Define a Successful Drilling Target in the Fractured Basement - A Case Study from the Nam Con Son Basin, Southern Offshore Vietnam
Authors: Li Bingjian , Hoang Phuoc Son , Mai Binh Van , Marie lefranc 
Published: March 2015

Abstract
The fractured granite basement in the Nam Con Son basin of southern offshore Vietnam has become a new exploration target in recent years. However, there are two major challenges in the early days of exploration. First of all, it is not always easy to locate a drilling target, for example, a faulted zone or a better fractured area on seismic due to the often degraded data quality within basement. Secondly, it can be difficult to drill the target with better well trajectory due to often poor understanding of the potential productive fracture systems. Those two challenges are also very common for most of the fractured basement reservoirs.
In this study, available regional geology data including structural geology information and outcrops have been collected to help geoscientists to gain a basic understanding of the local geology related to the basement and fracture development. A full suite of well data from an existing wildcat well in the same block including conventional open hole logs, advanced well logs (i.e. borehole images and SonicScanner), mud logs as well as PLT (production logs) and DST data was carefully studied to extract all possible information on natural fracture and fault. This resulted in two main outputs - the fracture density log along the wellbore and the defined potential fracture/fault system with dip and strike. Then the fracture output from the existing well was used to fully calibrate the seismic attribute analysis for the whole block, which mapped out the fracture density in 3-D volume. A new exploration well with high deviation was designed on the basis of fracture density volume data as well as the understood potential productive fracture/fault attitude (dip & orientation) and drilled smoothly. A commercial hydrocarbon discovery was made in this new basin first time in the fractured basement.

Introduction
Hydrocarbon has been discovered in the Miocene and Oligocene clastics as well as carbonates in the Nam Con Son basin, southern offshore Vietnam since 1990's. However, drilling activity for the Pre-Tertiary granite basement has been still very limited without any commercial discovery until late 2010. This paper intends to summarize the fracture characterization for the studied field where the 1st commercial oil discovery in the basement was made in the Nam Con Son basin as well as the learned experience on how to define a drilling target based on the limited existing well data and seismic data in the exploration stage for this unconventional fractured tight reservoir.
Deploying Multi-Stage Completion Technology in HPHT Applications
Authors: Oberhofer Robert 
Published: March 2015

Abstract
Over the last several years open hole, multi-stage fracturing systems (OHMS) have proven to be an effective and efficient completion technology in many unconventional reservoirs. To date, OHMS completion technology has been limited to a maximum differential pressure of 68.9 MPa (10,000 psi) while performing the fracture stimulation treatment. As the industry targets deeper formations while drilling longer horizontal laterals, some wells now require treatment pressures higher than 68.9 MPa (10,000 psi) to perform the desired stimulation and realize the added production potential OHMS technology offers. As a result, there is a need for OHMS completion tools capable of handling very high pressure/high temperature (HPHT) conditions.
The challenge in creating HPHT completion tools is in the material requirements. Considerations must be made regarding how to ensure integrity of the seal between the liner and the annulus, the gripping capability of the packer elements, and the ability of the materials to withstand the downhole conditions. HPHT OHMS tools were designed and manufactured with improved metal alloy and premium seal technology. The basic design and function of this HPHT system is the same as the standard OHMS; therefore, the HPHT tools build on the field-proven technology.
Case study wells are presented in a recently developed, deep shale gas formation just east of the Rocky Mountains with highly overpressured downhole conditions. This, combined with a high fracture gradient, resulted in sub-optimal fracture initiation with the standard OHMS. By employing the HPHT OHMS, higher treating pressures were achieved with successful treatment results. Using this technology, several additional wells have been completed in the same geographical field and implemented in other HPHT applications.

Introduction
Over the last five years (2007 - 2011), more than 5,000 horizontal wellbores have been completed using OHMS in unconventional shales, tight sandstones and tight carbonate reservoirs in Western Canada. In addition to providing time and cost reductions, OHMS completions have realized production benefits compared to conventional completion methods because they allow contribution from natural fractures and the open hole lateral (Snyder and Seale, 2011; Edwards et al., 2010; Houston et al., 2010; Lohoefer et al., 2010; Lohoefer et al., 2010b; Samuelson et al., 2008).
OHMS fracturing method. With the advancement of horizontal drilling and completion practices in recent years, many wells are now drilled horizontally with the intention to fracture stimulate multiple intervals. A very common technique has been to complete the well with a multi-stage fracturing system that is installed on a liner in the open hole without cementing the horizontal (Seale et al., 2006; Seale, 2007) (Fig. 1).
Challenges Evaluating Shale Gas Well Performance Catalogue Fingerprint: How Do We Account for What We Don't Know?
Authors: Boulis A. , Jayakumar R. , Nyaaba C. , Rai R. 
Published: March 2015

Abstract
Shale gas has emerged as a viable source of clean energy with advances in horizontal drilling and multi-stage fracturing. Well performance in the ultra-low permeability shale gas is governed by the interaction between reservoir rock and the fractures created during hydraulic fracturing. Numerical modeling historically has been used to study impact of variation in reservoir properties and completion characteristics on well performance. Shale gas field development requires a large number of wells to be drilled. The inordinate resource requirement to numerically model each well, necessitates the development of quick diagnostic tools. This paper explores how readily available pressure and rate data can be utilized to estimate and understand the unknowns involved in the completion and the reservoir parameters. Synthetic models have been used to generate well performance history which was then diagnosed using an analytical modeling workflow to generate well performance signatures. The synthetic models provided a controlled basis to study the reservoir and completion phenomena which are difficult to measure in the real field data. In practical application, multiple unknowns can co-exist to impact the overall well performance
Some of the major unknowns that were studied are reservoir permeability, fracture spacing, fracture half-length, fracture and matrix permeability changes with pressure. This paper also captures the performance signature changes with variation in original gas in place (OGIP) and the impact of contribution from stimulated rock volume (SRV) and external rock volume (XRV) outside the SRV. Fracture geometry is rarely known with certainty so this paper also addresses the performance changes that can be observed for various fracture geometry realization while conserving the total fracture area in all the models. The final section of the paper will address understanding the impact on estimated ultimate recovery (EUR) forecast for a particular scenario and how error in estimating the same reduces over time. We believe this fingerprint catalogue will serve as a valuable resource for prompt identification of dominant flow mechanism while providing a diagnostic method for identifying key indicators that control overall well performance.
Analysis on the Impact of Fracturing Treatment Design and Reservoir Properties on Production from Shale Gas Reservoirs
Authors: Cohen C.E. , Abad C. , Weng X. , England K. , Phatak A. , Kresse O. , Nevvonen O. , Laffite V. , Abivin P. 
Published: March 2015

Abstract
Production from shale gas reservoirs depends greatly on the efficiency of hydraulic fracturing treatments. The cumulated experience in the industry has led to several best practices in treatment design, which have improved productivity of these reservoirs. However, further advancement of treatment design requires a deeper understanding of the complex physics involved in both hydraulic fracturing and production, such as stress shadow, proppant placement and treatment interaction with pre-existing natural fractures.
This paper sheds light on the non-linear physics involved in the production of shale gas reservoirs by improving the understanding of the complex relation between gas production, the reservoir properties, and several treatment design parameters. A fracturing-to-production simulation workflow integrating the Unconventional Fracture Model (Weng et al., 2011), with the Unconventional Production Model (Cohen et al., 2012) is presented. By applying this workflow to a realistic reservoir, we did an extensive parametric study to investigate the relation between production and treatment design parameters such as fracturing fluid viscosity, proppant size, proppant concentration, proppant injection order, treatment volume, pumping rate, pad size and hybrid treatment. The paper also evaluates the influence of unconventional reservoir properties - such as permeability, horizontal stress, horizontal stress anisotropy, horizontal stress orientation, Poisson's ratio and Young's modulus - on production. Since this paper focuses on fluid and proppant selection, our methodology was to run 28 simulations to cover the 2D parametric space of proppant size and fracturing fluid viscosity for all of these parameters. More than fourteen hundred simulations were run in this parametric study and the results provide guidelines for optimized treatment design.
This paper illustrates how this unique workflow can identifies the optimum fluid and proppant selection that gives the maximum production for a given reservoir and completion. In addition, the parametric study shows how these optimums evolve as a function of reservoir and treatment parameters. The results validate several best practices in treatment design for shale. For example, combination of different sizes of proppant optimizes production by maximizing initial production and slowing down production decline. Simulations also confirm the best practice of injecting the smallest proppant first. The study explains why slickwater treatments should be injected at maximum pumping rate and preferably with 40/70 mesh sand. It also illustrates why reservoirs with high Young's modulus (such as the Barnett shale) can be stimulated effectively with slickwater. Another key finding is that the optimum fluid viscosity increases with treatment volume.
Effect of Reservoir Porosity and Clay Content on Hydraulic Fracture Height Containment
Authors: Liu He , Wang Han , Wu Heng'An , Wang Xiu'Xi 
Published: March 2015

Abstract
The technique of hydraulic fracturing is an essential way for reservoir stimulation. Prediction of hydraulic fracture geometry has been a difficult challenge in petroleum engineering. A 3D non-linear model is established for simulating hydraulic fracturing processes based on the ABAQUS code. The fluid-solid coupling equations consist of rock stress equilibrium, porous fluid mass conservation, Darcy's law and effective stress principle. The differential equations are discretized in finite element form and solved. The cohesive elements based on damage mechanics are adopted to model the fracture initiation and propagation.
A typical hydraulic fracturing process of a horizontal well in Daqing Oilfield, China is simulated with this model. Variation of proppant concentration during the fracturing procedure is taken into account by the user-subroutine we developed. The bottomhole pressure evolution obtained from the simulation is consistent with the field-measured data. Thus the model is verified.
For vertical fracture, the effect of formation porosity and clay content on fracture height containment is investigated and discussed. The rock properties are connected to porosity and clay content by a set of formulae. The results show that larger porosity and clay content could confine the fracture height. As the porosity of the pay layer increases, the permeability increases while the elastic modulus decreases. Since the fracturing fluid leaks off into the reservoir more easily for larger porosity formations, the fracture height decreases and the bottomhole pressure drops. With the increase of the clay content of barrier layers, the elastic modulus decreases and the tensile strength of rock material increases. And the fracture height will decrease as the material is more difficult to be damaged for larger clay content formations.
Our work can provide a new understanding of fracture height containment and could benefit the design and practice of hydraulic fracture treatment.
Thermally Stable Cutter Technology Advances PDC Performance in Hard and Abrasive Formations, Kuwait
Authors: Hussein Ali , Al-Anezi Nayef Abdulla , Al-Sarraf Adel Q. , Dhabria Akshaya K. , Baqer Hussain A. , Maliekkal Harish , Ghoneim Osama , Zhang Youhe 
Published: March 2015

Abstract
Efficiently drilling the 16" hole section in high temperature/high pressure (HTHP) conditions through hard/abrasive Jurassic formations in Kuwait's oil fields has been a distinctive challenge for more than a decade. The difficult sequence of lithologies starts with abrasive Zubair sand (with pyrite) followed by reactive Ratawi shale and then hard carbonates (UCS 10–30kpsi). The Zubair is approximately 1300ft thick and has historically been drilled with four/six rollercone TCIs or a combination of two TCIs and two PDC bits or two/three PDCs. The objective has been to reduce the total number of bits/trips and ultimately drill the Zubair and as much Ratawi as possible with one PDC bit.
Initial attempts with PDC were encouraging, but not economically successful compared to rollercone cost/ft. To improve performance, an FEA-based modeling system was used to predict downhole behavior. Based on these knowledge gains, a new PDC bit design was produced with optimized blade orientation and reconfigured cutting structure. Although the new design did improve performance, the drilling team concluded the PDC shearing elements were unable to withstand the HTHP environment (thermal degradation) and vibration induced impact damage. The operator required new technology to enhance cutter longevity.
To deliver a suitable solution, new cutter technology was developed using a two-step manufacturing process high temperature/high pressure pressing technique. Laboratory tests indicated the new style cutter has significantly increased resistance to abrasive wear and thermal fatigue compared to standard cutters without compromising impact resistance.
The HTHP cutters were run in a nine-bladed PDC with outstanding results setting a new Kuwaiti single run Zubair footage record (1302ft) and Zubair/Ratawi field footage record (1347ft). The authors will discuss the application challenges and resulting performance improvement. Offset analysis will document a performance step-change that saved the operator an average of 10 days of rig-time (﹩500,000USD).
Feasibility of Using Laser Bit Beside of Common Bits to Drilling Slim Holes
Authors: Bazargan M. , Jalalifar H. , Koohian A. , Habibpour M. 
Published: March 2015

Abstract:
The capability level of rotary as well as first generation drilling operation could not be matched for deeply drilling programs. To reach that deep, the increasing in drill string length could also cause an additional constraint on hydraulic performance. The operation of slim hole drilling has significant potential to reduce well costs. This cost might be savings are especially important with increased demand for reduced capital finance under current economic conditions in the Iranian oil and gas industry.
This savings achievement could be caused by use of smaller drilling rigs, work over rigs, reduced casing size, reducing requirement for drilling consumables and other costs associated with hole size. Otherwise, using laser irradiation for drilling operation can save cost little more higher look like do not using casing and perforation in reservoir layer for slim hole which are drilled by high power laser systems.
As the matter of fact, Cost savings achieved from slim hole drilling could be offset by inability to effectively transmit the weight to the bit, increased mechanical failures of drill pipes and tools and reduced the well bore instability effects in particular, in drilling operation at greater depths This paper investigates the effects of borehole parameters during laser drilling operations in the case of slim hole.

Introduction:
For last 30 years old experiments and studies had shown laser drilling as benefit technical operation[27]. The earliest studies were resulting enhancing tunneling machines to be used to mining industry improved by lasers tools[21][22]. Lasers start works on industry with very low power but produced large wavelengths and it wasn't safe for industrial use The old methods of Drilling was the Rotary operation and drilling industry was developing[1][6].
Since the rotary drilling superseded cable tools drilling, there was a huge break for the oil industry when cable tool drilling had been replaced to the rotary drilling[18]. Developing started almost a century earlier, the basic method of using them was to reach gas and oil reservoir in our formations[24]. The current drill bits are very widely used tool for rough layer and drilled them in non-metallic goods in general and in step by step based products in regular. It's most widespread use is encountered in the home construction industry, really weak on the case for plumbing and electrical installations[23].
An Integrated Model for Selecting the Best Fuel to Develop in the Value Chain of Natural Gas
Authors: Mousaei Ahmad , Ghadirian Abbas Ali , Hatefi Mohammad Ali 
Published: March 2015

Abstract
A value chain is a series of events that takes a raw material and with each step adds value to it. Global interest in the application of natural gas in production and transportation has grown dramatically, representing a long-term, low-cost, domestic, secure, etc. alternative to petroleum-based fuels. Many technological solutions are currently considered on the market or in development that address the challenge and opportunity of natural gas.
In this paper, an integrated model is introduced for selecting the best fuel to develop in the value chain of natural gas through the four options:Compressed Natural Gas (CNG), Liquefied Natural Gas (LNG), Dimethyl Ether (DME)and Gas-To-Liquids (GTL). The presented model uses the Multiple Attribute Decision-making (MADM) techniques to select the best fuel in the value chain of natural gas based on the criteria such as market situations, technology available and transportation infrastructure. The model recommends some key guidelines for two branches of countries i.e. those have natural gas resources and the others. We believe that applying the proposed model helps the oil &gas / energy ministries in most effective and productive manner dealing with his complicated fuel-related production and transportation decision-making situations.
First Successful Application of an Environment Friendly Fracturing Fluid during On-The-Fly Proppant Fracturing
Authors: Al-Ghazal Mohammed , Al-Driweesh Saad , Al-Shammari Fowzi 
Published: March 2015

Abstract
With the increasing demand for natural gas, fracturing fluid technology needs to develop to enable optimized well completion operations with minimum ecological impact. The recent development of environmentally friendly polymer-free fracturing fluids — with superior operational performance —represents a major technological advance in the petroleum industry.
The use of these new fluids during fracturing operations has the following benefits: minimized environmental footprint and formation damage, operational efficiency and simplicity, and maximized fracture conductivity.
This paper discusses the first successful deployment, of an environmentally friendly polymer-free fracturing fluid, during on-the-fly proppant fracturing in Saudi Arabia. Also, the paper discusses the optimum layout of the fracturing equipment used during the job execution.
The fluid was used to fracture a gas zone located between two water zones. Therefore, one of the main objectives of the treatment was to control the height of the fracture to not break through and contaminate the water-bearing zones.
In addition, the fluid exhibited a low friction pressure and excellent proppant-carrying capacity. Moreover, the overall cost of this fracturing operation is in line with conventional, polymer-based fluid fracturing approaches.
Evaluation of the post-treatment results demonstrated the following: very positive well productivity, improved fracture geometry (longer fractures with better height containment), and faster fracture cleanup time.