bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development Strategy Planning for a Shale Reservoir
Authors: Younus Hafiz Muhammad , Kazmi Fatima , Ali Waqas , Khan Muhammad Noman , Khalid Afrah 
Published: March 2015

Abstract
As the demand of natural gas is increasing along with decline in conventional gas resources, the exploitation of unconventional resources has become essential to meet the increasing demand. Shale being unconventional hydrocarbon resource; is very complex in terms of fluid flow and storage mechanisms and require advanced techniques to be modeled correctly. As high investments are involved to develop the resource, therefore representative model is required to decide whether to exploit a shale resource or not, and optimize the development strategy in order to maximize the recovery and profitability.
Mostly shale resources are modeled using analytical methods in which best fit model on one well is applied on all other wells of the field to simulate their behavior. However this may not be the case in actual due to heterogeneities in the reservoir. One way to simulate the performance of shale is to use a numerical simulation model in which one can predict the effect of various scenarios on production such as horizontal length, number of stages of frac, etc. In addition it allows to optimize various parameters for the development of field which may not be done through analytical models.
In this paper a numerical simulation model is developed for a shale resource. This model is used as a tool for planning and optimizing the development strategy of the resource. The model contains horizontal wells with multi stage fracturing and is validated using well production data of a shale resource. Vertical Lift Performance (VLP) curves are generated from a well modeling software and are incorporated in the simulation model. Horizontal development wells are incorporated to maintain a specific plateau rate. Sensitivity of various parameters such as number of wells, timing of the wells and plateau rate is carried out to study various cases.
The results of these cases including plateau rate and period and gas recoveries are presented and the optimum case is selected based on the profitability and maximum recovery. The adopted approach can be used efficiently to evaluate a shale gas prospect to establish its development and appraisal strategy.
Integration of Geomechanics Along with Application of New Fracturing Technique Results in Production Increment Above Expectations
Authors: Siddiqui Adil Ahmed , Khan M. Wahaj , Khan M. Noman , Kamaletdinov Bulat , Palekar Arshad Hussain 
Published: March 2015

Abstract
Hydraulic fracturing is one of the most effective methods of improving the deliverability of low permeability wells. Hydraulic fracturing in a rich gas condensate field has earned cost benefits by reducing number of infill wells, producing condensate drop out from reservoirs and increasing overall productivity of oil and gas.
The target development well was drilled and completed in September 2013 and post completion testing rates as well as pressure build up analysis indicated severe formation damage issues and requirement for hydraulic fracturing. In the same field hydraulic fracturing was carried out earlier in other wells but yielded mixed results. In some of the wells 2-3 times increase in productivity was observed while in some wells, the results were below expectations, despite placing ~100,000 lbs of proppant. In one of the well, formation break down did not occur. Utilizing prior frac experience it was decided to optimize the upcoming frac job but at the same time not to compromise on the frac quality.
Extensive pre-job evaluation and planning which included review of available logs and previous frac data, development of 1D Mechanical Earth Model (MEM), frac modeling, implementation of Channel fracturing technique, optimization of fracturing chemical and proppant volumes was done to get maximum benefit of this major well stimulation job. As a result of these efforts frac jobs of the target sandstone reservoirs was completed successfully and the well was put on production in minimum clean-up and post frac testing time.
As a result of above effort in planning and optimization of frac job at the target well, significant increase in production was observed which exceeded the operator expectations and raised the confidence level in 1D MEM application for hydraulic frac design (i.e. geomechanics) and the new frac technique by the service company. Based on post frac results, these techniques are being utilized in the upcoming wells in the target field.
Attempting To Quantify Subsurface Uncertainties With Dynamic Data – A Reservoir Management Case Study
Authors: Noman Muhammad , Khan Muhammad Nisar , Amjad Bilal , Afsar Javaid 
Published: March 2015

Abstract
Analyses of dynamic data that include pressure and production history have long been recognized as a tool to evaluate the underground reservoir size, fluid volumes and future performance. This study encompasses a similar case utilizing analytical and numerical methods to interpret the dynamic data. As a result several geological features were confirmed and a few sub-seismic features were identified.
The field under discussion is located in Lower Indus Basin of Pakistan and characterized by hydrocarbon accumulations in Lower-Goru Upper-Sand reservoirs. Exploratory well A-1 discovered the field by finding gas bearing Sandstone reservoir established based on formation evaluation and open-hole log profile. The structure was bounded by two major intersecting faults and one splay fault, all juxtaposed against shale barriers. Due to these structural features A-Sand was expected to exhibit depletion drive mechanism. When A-1 was put on production, it performed as a dry gas producer for brief period of time then its gas rates started declining with increasing CGR. Routine surveillance recorded depletion in reservoir pressure and the well loaded up after a year. After reviving on Gas Lift and A-1 became essentially an oil producer with a GOR of 2000 scf/stb. BHP surveys showed no further depletion than 400 psia. These facts hinted at pressure support to A Sand reservoir as opposed to originally assumed closed structure. To enhance oil production hydraulic jet pump was installed and achieved apex oil rates from the well, interestingly, without commensurate increase in water production. On Jet Pump also, well exhibited fairly constant liquid withdrawals strengthened idea of pressure recharging. To identify source of A-Sand recharging, it was decided to (1) analyse pressure-production history (2) Closely analyse interpreted analytical model built on pressure data (3) Perform numerical PTA by integrating G&G data, and (4) develop Allen diagrams to see possible juxtaposition with downthrown blocks.
The study concluded that Splay fault on reservoir structure may not be completely sealing since both Analytical and Numerical Model transient models strongly suggested slightly different position of splay fault on the west of the well. Allen Diagram further showed decreasing throw of the same fault intimating possibility of juxtaposition. Hence, it was concluded that the oil source and pressure support most probably lies beyond the western fault and could be confirmed by refining subsurface structure through re-interpretation of seismic data.This way, the work emphasized the role of dynamic data in adding value to a company's knowledge of subsurface elements and hence widen the scope of field development strategy.
Prediction of Optimum Thermal Insulation Thickness for Oil and Gas Process Piping and Equipments Using Simple Method
Authors: Bahadori Alireza , Vuthaluru Hari 
Published: March 2015

Abstract
Selection and determination of optimum thickness of insulation is of prime interest for many engineering applications. In this study, a simple method is developed to estimate the thickness of thermal insulation required to arrive at a desired heat flow or surface temperature for flat surfaces, ducts and pipes. The proposed simple method, which is easier than current available models involving a large number of parameters, requiring more complicated and longer computations, covers the temperature difference between ambient and outside temperatures up to 250°C and the temperature drop through insulation up to 1000°C. The proposed correlation calculates the thermal thickness up to 250 mm for flat surfaces and estimates the thermal thickness for ducts and pipes with outside diameters up to 2400 mm. The accuracy of the proposed method was found to be in excellent agreement with the reported data for wide range of conditions where the average absolute deviation between reported data and the proposed method is around 3.25%. The method is based on basic fundamentals of heat transfer and reliable data. Therefore the formulated simple-to-use expression is justified and applicable to any industrial application. The correlation proposed in the present work is novel and unique expression which is non-existent in the literature. This is expected to benefit and making design decisions which could lead to informed decisions on the selection of optimum insulation thickness for a given application in any process industry.
Basement Reservoirs - A Review of their Geological and Production Characteristics
Authors: Gutmanis Jon 
Published: March 2015

Introduction
This presentation describes the geological characteristics, technical issues and development challenges associated with hydrocarbon exploitation in crystalline basement formations. The term 'basement' here refers to crystalline formations ranging from intrusive and extrusive magmatic bodies (especially granites) to the family of low to medium grade metamorphic rocks. Hydrocarbons have been under production from these types of rocks around the world for many decades (see www.geoscience.co.uk for a review) but since around 1990 there has been growing interest and exploration in these formations where matrix porosity is neglible and storage and production are dominated by the fracture system (a Type 1 reservoir of Nelson 2001). For example, the Arabian shield basement of Yemen and the Tertiary basement granites offshore Vietnam are two classic areas for this type of development, and significant production has been achieved. Other less publicised locations have also been investigated including prospects on the UK continental shelf.
The presentation draws on reservoir characterisation and modelling projects in basement hydrocarbon fields around the world, as well as investigations of basement rocks for deep geothermal resource exploitation (EGS) and also for sub-surface disposal of radioactive waste. The objective is to provide a synthesis and consolidation of learnings from these investigations in terms of the geological character and controls on fracture development, fluid flow and ultimately reservoir quality for hydrocarbon exploitation.

Basement Charging Mechanisms
Most basement hydrocarbons are hosted in structural highs of varying but generally moderate to large elevation (hundreds or even 1000m +). The highs are formed by fault-controlled blocks, often in rift settings, or by palaeo-hills buried below sedimentary cover. A second type of setting comprises intrusive igneous bodies (plutons) within sedimentary sequences. In all cases an overlying seal formation is found at some level. Additionally, some of the overlying, or fault-juxtaposed, sedimentary units may also be charged so that a composite hydrocarbon play is developed. For example, sandstone 'washes' above top granite surfaces or carbonate formations which developed on or adjacent to the fault blocks.
Most basement charging is thought to have taken place by lateral or up-dip migration from kitchen areas in nearby structural lows. The migration route is through higher permeability sedimentary units, active faults and perhaps also at the basement / cover interface, thence into the basement itself. One example, from the basement fields West of Shetland on the UK continental shelf, is shown in Figure 1. Other examples are found in the rift basins offshore Vietnam (CuuLong Basin) and onshore in Yemen (eg Sab'atayn Rift).
Simulating the Permeability Reduction due to Asphaltene Deposition in Porous Media
Authors: Alizadeh Nasser , Khaksar Manshad Abbas , Fadili Ali , Leung Edmund , Ashoori Siavash 
Published: March 2015

Abstract
A static to dynamic approach to modeling Asphaltenes has been developed and validated. A new algorithm for static asphaltene modeling uses a multi-solid thermodynamics approach where the equality of fugacity for each component and phase is applied at equilibrium conditions. This is required for minimizing the Gibbs free energy. The fractal distribution function used for the splitting and characterization of heavy components provides accurate results. The precipitation and re-dissolution of asphaltenes are investigated for a relatively heavy crude oil from an Iranian field. A series of experiments are designed and conducte quantitatively to obtain the permeability reduction in a slim tube. Using a dynamic reservoir simulator, a 3-dimensional asphaltene model is developed to simulate the precipitation, flocculation, deposition and its impact on permeability in a slim tube. With this approach, the asphaltene is defined as a set of component(s) that can precipitate depending on their molar percentage weight in solution. The simulated permeability reduction due to asphaltene deposition shows good agreement with our experimental data.

1. Introduction
Asphaltenes can reduce the hydrocarbon effective mobility by:a) Blocking pore throats thus reducing the rock permeability.b) Adsorbing onto the rock and altering the formation wettability from water-wet to oil-wet, hence diminishing the effective permeability to oil and increasing the irreducible oil saturation.c) Increasing the reservoir fluid viscosity by forming a colloidal solution in the oil phase.
The most frequently encountered scenario of asphaltene-induced formation damage is when under saturated oil is being produced without water. The most dominant damage mechanism is blockage of pore throats by asphaltene precipitation and thus causing a reduction in rock permeability. In comparison most wax-related formation damage is caused by cooling due to excessive draw down across the perforations or due to hot oiling operations or organic solids entering the formation due to overbalance conditions. In all cases, the damage area is restricted to the wellbore zone (several inches to 1 feet). In the case of asphaltenes, the formation damage may occur many feet from the wellbore depending on the drawdown [1,2]. Several authors have studied different models for asphaltene deposition in core tests. Civan et al. [3, 4] assumed that the flow channels in porous media are grouped into plugging and non-plugging pathways, and for the deposition model they use surface adsorption, pore throat plugging, and entrainment of deposits. Ali and Islam [5] assumed that Asphaltene is suspended in crude oil and ready to deposit, and for the deposition model they consider surface adsorption and entrainment of deposits. Wang et al. [6,7] considered asphaltene precipitation could be simulated by ideal solution theory, and for the deposition model they used surface adsorption, plugging, and entrainment.
Drilling & Completion Technology Solutions for Challenging North Field Operations
Authors: Clancey Byron Michael , Remmert Stephen Matthew , Sorem William A. , Khemakhem A.S. David , Shuchart Chris E. 
Published: March 2015

Abstract
From the start of the current phase of North Field drilling activity in 2002, RasGas Company Limited (RasGas) has continued to push the envelope in terms of both technology and operating practices in drilling and completions. Following the successful introduction of an Optimized Big Bore (OBB) well design in 20021,2,3, advancements have been made in areas of drillstring design, drilling optimization techniques, management of lost circulation events and overpressured water flows, and stimulation technology associated with increasingly longer completion intervals. This paper highlights how these advancements have enabled year-on-year improvement in drilling and completion cycle times, even though well complexity has increased over the same time period.
Research on the Well logging Technique of Hydrocarbons Identification for the Complicated Reservoirs in WN Oilfield
Authors: Ma Lijuan , Linghu Song 
Published: March 2015

Abstract
The identification and evaluation of reservoirs in WN oilfield is difficult because of complicated lithology and pore structure which are strongly aeolotropic and change vastly both in horizontal and vertical directions. All these lead to little difference in log response between reservoirs and nonreservoirs, oil layers and aqueous layers, high productivity layers and low productivity layers. This paper puts emphasis on lithologic identification and classifies reservoirs by parameter based on lithologic classification. Then different interpretation models are constructed according to different reservoirs, and the interpretation accuracy is enhanced. Different parameters are applied to interpretation charts by corresponding zones and layer systems, which constructs the charts system with high accuracy to cover the whole WN oilfield. Moreover special research is made to low resistivity reservoirs. The research shows that mud invasion and formation water with high salinity are key factors to form low resistivity reservoirs and builds interpretation standards and charts of low resistivity reservoirs. After the achievement is applied to practice the success ratio of reservoir identification reaches about 80% and many new reservoirs are located. The reserve of WN oilfield increases by a larger mount.

Introduction:
WN oilfield is a tertiary structure in ChaiDM basin, and the whole is a nosing anticline which inclines from southeast to northwest. It has northwest direction tectonic axis. The formation of this structure has high dip in its southwest flank and low dip in its northeast flank. The oilfield is a classic continental deposit which mainly develops sedimentary microfacies of shallow lake and beach bar, partly sedimentary microfacies of subwater distributary channel, front sheet sand and distal bar of delta front subfacies. From top down on the size of grains in the formation changes from fine to coarse, the lithology gradually changes from brownish-red shale, sandy shale, argillaceous siltstone, siltstone, fine sandstone, rudaceous sandstone to gravel. The content of carbonate cement which fills between granules as the form of micrite calcite is high. The oilfield is heavily cut by many faults. Every block fault constitutes a separate reservoir where the most abundant oil/gas has been found. In vertical direction oil/gas mainly distributes in ????????????? measures of the lower Youshashan formation in N21 section. Generally WN oilfield is a structural reservoir with complicated lithology. Oil/gas distribution both in horizontal and vertical directions is controlled by structure, fault and lithology (physical property).
3D Modeling of the Arab Formation (Maydan Mahzam Field, Offshore Qatar): An Integrated Approach
Authors: Al Emadi Ahmed Abubakr M. , Jorry Stephan , Chautru Jean-Marc , Caline Bruno , Blum Marie-Stephanie , Jedaan Nizar Mohamad R. , Fryer Vance I. , Leandri Patrick , Fraisse Christian 
Published: March 2015

Abstract
The Late Jurassic Arab Formation consists of complex carbonate and evaporite facies associations deposited along ramps and intra-shelf Arabian basins, which form large hydrocarbon fields. Most of the time, the 3D reservoir characterization of such reservoirs is challenging, due to superimposed diagenetic overprints. The aim of this paper is to present an integrated approach using original rock-typing and modeling methods for the characterization of the four main reservoirs of the Arab Formation in Maydan Mahzam Field (Qatar).
A sedimentological study was conducted on cores, and a sequence stratigraphy framework was developed. Three depositional models are proposed to illustrate the progradation of the Arab D carbonate platform toward the Southeast and the deposition of inner ramp/sabkha facies of the Arab A, Arab B and Arab C reservoirs. Rock-types that are characterized by specific geological, petrophysical and Kr/Pc properties have been defined from cores and thin sections, taking into account log response and SCAL measurements. These rock-types have been extended to all the wells by mean of a semi-interactive statistical classification applied on log data. They have been propagated in a 3D grid using a non-stationary geostatistical approach guided by 3D probability cubes. The probability cubes calculation is based on local vertical proportion curves determined from well sets and from the sedimentological models which cover undrilled areas.
This paper contributes to a better understanding of the sedimentology of the Arab Formation in Qatar and helps to refine the regional distribution of the Arab D reservoir facies. It demonstrates that an accurate rock-typing scheme combined with the definition of a sequence stratigraphy framework are of prime importance for building 3D static models, which honor geological concepts for carbonate reservoir simulation.
Petroleum Development Oman Minimizes Gas Consumption for Thermal EOR using Power Station Waste Heat
Authors: Terres Richard , Busaidi Khamis , Moelker Willem , Van Zanten Wouter 
Published: March 2015

Abstract
Petroleum Development Oman (PDO) is harnessing waste heat from its power generation to provide steam for several of its steam Enhanced Oil Recovery (EOR) developments.
Within the next decade over a third of PDO's production will come from major miscible gas injection, chemical and thermal EOR developments. To meet the power requirements of this evolving portfolio, PDO has plans to construct several new power stations. With these new power stations, PDO will minimize its energy usage through the use of power station waste heat for its thermal EOR projects. To do this, PDO has changed the way it plans, constructs and operates its power generation activities. PDO used to locate power stations where power was required. Now, the power stations are located where the waste heat from the power stations is required.
PDO currently has under design and construction four heat recovery units at a power station in central Oman. A further network of linked power stations and thermal EOR developments will be constructed throughout Oman. This program will require substantial capital to be invested in the waste heat recovery systems as well as upgrading the overhead power line network. An additional challenge is the requirement for coordination of projects that traditionally would have been managed independently. The steam EOR projects have been scheduled and scaled to fit with the power load growth and the power grid must be operated to maximize and balance the steam injection at the oil fields.
PDO is committed to this strategic investment as well as the project and operational reorganizations because it knows that there will be payback in terms of a significantly reduced fuel requirement and a reduced emissions footprint.

Introduction
Petroleum Development Oman (PDO) is committed to operating responsibly and to minimizing fuel gas consumption even while honouring its primary business objective of oil and gas production for the Sultanate of Oman. To this end, PDO is harnessing waste heat from its power generation to provide steam for several of its steam Enhanced Oil Recovery (EOR) developments.
PDO has been producing oil and gas in the Sultanate of Oman for over 40 years (Figure 1). Virtually all of PDO's oil production currently utilizes primary and secondary recovery mechanisms; but, within the next decade over a third of its production will come from major EOR developments. To meet the power requirements of this evolving and more energy intensive portfolio, PDO has plans to construct several new power stations.