bluuebunny/crossref_metadata_2025_split huggingface dataset:
Solids-Free Viscoelastic Fluid Loss Pills and Dynamic Underbalance Improve Productivity from Newly Perforated Wells
Authors: Arangath R. , Babalatirov Y. , Griffith M. , Umirbayev A. 
Published: February 2011

Abstract
Many operators in Kazakhstan are producing from carbonate reservoirs with fairly low permeability and porosity with the presence of dominant natural fractures. The completion and perforation of the reservoir are critical phases during which special attention must be placed on the well cleanup to obtain the maximum hydrocarbon productivity. Wells in the tight carbonate formation of certain fields in western Kazakhstan have historically been perforated in overbalance conditions or in static underbalance conditions that require killing the well immediately after the perforation for installing the permanent completion. After the permanent completion has been put in place, an acid wash must be performed to remove all the damage induced by the killing operation and the perforating debris. Both ways of perforating the wells expose the reservoir to potentially damaging fluids during and after the perforation. The exposure time of these fluids can be prolonged if adverse meteorological conditions are encountered. The damaging fluids can significantly impair the productivity by blocking the newly perforated tunnel, as well as by filtering through the natural fractures, which in turn makes it very difficult to remove even after as acid wash. As a result, the wells do not produce to their full potential.
A new perforating approach utilizing a dynamic underbalanced technique, in conjunction with a solids-free, viscoelastic-based, fluid loss pill, was introduced in several new wells in western Kazakhstan for a major operator. The fluid loss pill was designed to be solids-free and to be easily broken, leaving no residue downhole. There were four main requirements for the fluid pill:
Effective—capable of stopping or minimizing completion brine losses at bottomhole static temperatures (BHSTs) up to 137°C. Degradable—easy to clean and with minimal residual damage to the reservoir or the perforations. Compatible—fully compatible with reservoir fluids and any well service fluids. Solids-free—making the post-completion cleanup operation easy.
The carbonate reservoir where this new approach was utilized has permeabilities varying from 6 to 38 mD, while the present reservoir pressure is approximately 4,200 psi at the reference depth of 3550 m. The new perforation approach allowed obtaining a cleaner perforation tunnel, increasing the average production compared with wells draining from the same reservoir that were completed with the traditional technique. The average production obtained with the new approach is approximately double that of the conventional technique. This has been verified on a campaign carried out on 11 wells, all located in the same area of the field, four of which were completed with the new perforation approach. Several other treatments have been performed and have indicated similar trends in production.
An Improved Adjoint Sensitivity Computation for Multiphase Flow Using Wavelets
Authors: Awotunde Abeeb A. , Horne Roland N. 
Published: February 2011

Abstract
In history matching, one of the challenges in the use of gradient-based Newton algorithms such as Gauss-Newton and Levenberg-Marquardt in solving the inverse problem is the huge cost associated with the computation of sensitivity matrix. Although the Newton type of algorithm gives faster convergence than most other gradient-based inverse solution algorithms, its use is limited to small and medium-scale problems in which the sensitivity coefficients are easily and quickly computed. Modelers often use less efficient algorithms such as conjugate-gradient and quasi-Newton to model large-scale problems because these algorithms avoid the direct computation of sensitivity coefficients. To find a direction of descent, such algorithms often use less precise curvature information that would be contained in the gradient of the objective function. Using a sensitivity matrix gives more complete information about the curvature of the function, however this comes with a significant computational cost for large-scale problems.
An improved adjoint sensitivity computation is presented for time-dependent partial differential equations describing multiphase flow in hydrocarbon reservoirs. The method combines the wavelet parameterization of data space with adjoint sensitivity formulation to reduce the cost of computing sensitivities. This reduction in cost is achieved by reducing the size of the linear system of equations that are typically solved to obtain the sensitivities. This cost-saving technique makes solving an inverse problem with algorithms such as Levenberg-Marquardt and Gauss-Newton viable for large multiphase flow history matching problems. The effectiveness of this approach is demonstrated for two numerical examples involving multiphase flow in a reservoir with several production and injection wells.
Successful Case Histories of the Conformance-While-Fracturing Technique in Egyptian Western-Desert Reservoirs
Authors: Ali Ahmed , Yassine Rami , Tawakol Moataz , Aal Ezz Abdel , Khalek Tamer Abdel , Hamdy Ahmed 
Published: February 2011

Abstract
Hydraulic fracturing has proven to be extremely successful in the western desert of Egypt. Approximately 85% of production in this area results from this stimulation technique, specifically in the reservoirs of interest documented in this paper. However, a deterrent to fracturing in many cases has been the proximity of the producing zones to underlying (or overlying) water zones, either located near the water-oil contact or hydrocarbon zones adjacent to water-bearing zones. In the absence of geological barriers, the fracture height can grow uncontrolled during a fracturing treatment into the water-bearing interval and cause unwanted water production. Excessive water production threatens the economics of a well by: shortening its production life, increasing disposal and lifting costs, boosting the fines migration, and increasing the rate of tubular corrosion and scale buildup. Many times, in marginal fields, these can be sufficient reasons to consider not fracturing.
This paper presents case histories where wells were hydraulically fractured using conventional techniques resulting in higher than 60% water cut (even as much as 100% in one case); while with the use of the conformance-while-fracturing (CWF) method, the water cut obtained was as low as 4%, even when the adjacent water zones were within 20 ft of the perforations. This technique provides a tremendous boost to the economics and an effective solution (increasing recoverable reserves from these wells by allowing the hydrocarbons to be produced almost water-free) to a field otherwise plagued with water production. The CWF technique incorporates a relative-permeability modifier (RPM) in the fracturing-fluids design. The RPM provides a reduction in effective permeability to water without significant changes to the relative permeability to oil. This paper discusses the geological and reservoir parameters of the wells and zones of interest, the properties of the RPM, the CWF job-design considerations (and the associated challenges to the job design), its field applications, and post-fracturing results in comparison to offset wells fractured conventionally in the same reservoir and at the same level. It is envisaged that CWF techniques will prove to be beneficial to other operators faced with similar production challenges.
Virtual Metering System for Oil and Gas Field Monitoring Based on a Differential Pressure Flowmeter
Authors: da Paz E. F. , Baliño J. L. , Slobodcicov I. , Filho D. F. 
Published: February 2011

Abstract
In this paper, a virtual metering system (VMS) for oil and gas monitoring based on a differential pressure transducer (orifice plate, venturi or nozzle) is presented. The model for the measuring device considers one-dimensional subsonic flow of gas, oil and water. Oil and water are considered to flow with a single velocity (homogeneous flow), while relative velocity between the gas and liquid phases is taken into account by means of a slip ratio calculated with Chisholm's correlation. Neglecting friction, mass transfer, compressibility and variations in the slip ratio along the converging portion of the flowmeter, it is possible to integrate the mass and conservation equations to obtain a generalization of the mass flow versus pressure drop relationship corresponding to a differential pressure flowmeter for multiphase flow. The total mass flow depends on a set of variables evaluated at operating condition: density and viscosity of the liquid and gas phase, mass quality, pressure drop across the flowmeter and geometry (contraction area and beta factor).
The determination of the fluid variables at operating condition is made by using a black oil model and a set of variables at standard condition that characterizes fluid composition, being the most important GOR, BSW and densities of the individual phases.
An experimental campaign was carried out at different wells located at Urucu field, Solimões basin (Amazonas, Brazil), using orifice plates. The total mass flow rate and the volumetric flows for each individual streams at standard condition calculated with the VMS showed an excellent agreement with the experimental data.
Success Story of Downhole Fluid Sampling in a Very Challenging Environment in the Gulf of Thailand
Authors: Kanjanavasoontara C. K. , Daungkaew Saifon , Yimyam Nitipong , Platt Christopher , Houtzager Fred 
Published: February 2011

Abstract
Traditionally, the Gulf of Thailand (GoT) has been known for high temperature, small borehole size, variable CO2, and highly compartmentalized reservoirs. In particular, it is a very challenging environment for Wireline Formation Testers (WFT). Owing to cost constraints, since the start of exploration and development campaigns in this area, usage of newer technologies has been highly selective. However, this has been changed significantly in the past few years where the right WFT technology has been applied to the right environment. This paper is the first to present a work process to derive clean fluid sampling in the very challenging environment of the GoT.
Time per station used to collect downhole fluid samples using WFT has been a major concern for a costly offshore operation. In addition, borehole stability is also another factor limiting WFT time. Given the time constraint, collected fluid samples usually have high drilling mud filtrate contaminations, in the ranges of 25 to 85wt%, and have not been suitable for further laboratory analysis and field development purpose. Balancing between the time used for fluid sampling and the quality of the collected fluid samples is not a simple task to manage.
This paper shares a successful story of downhole fluid sampling in exploration wells for one of the operators in the GoT. Instead of using a conventional probe with one Downhole Fluid Analyzer (DFA), the concentric shaped probe with two synchronized pump-out modules and two DFAs are used in this case. However, this is not as simple as other fields already presented in the literature because an unconsolidated sand character introduced complications into this sampling technique. Several attempts have been developed to make focused sampling work in these challenging environments. At the end, "Less than 5% OBM contaminated samples in oil reservoirs are successfully achieved in a timely manner." The average time used per each sampling station is approximately 30 minutes. This paper will also discuss the advantages and disadvantages for each technique applied and the final results. In addition, more improvements have been suggested to enhance this focused sample technology in more complex fluids, such as gas condensate reservoirs to make sure that less contaminated fluid sample can be collected in the limited time per station.
Coal Permeability and Its Behaviour with Gas Desorption, Pressure and Stress
Authors: Connell Luke D , Pan Zhejun , Lu Meng , Heryanto Deasy , Camilleri Michael 
Published: February 2011

Abstract
Coal permeability is sensitive to the effective stress and is therefore coupled to the geomechanical behaviour of the seam during gas migration. The geomechanical response of the seam is complicated by the additional effect of coal shrinkage with gas drainage. Existing coal permeability models, such as those proposed by Shi and Durucan (2004) and Palmer and Mansoori (1996), simplify the geomechanical processes by assuming uniaxial strain and constant vertical stress. Connell (2009) and Connell and Detournay (2009) investigated these assumptions using a fully coupled simulator. An important obstacle to the use of the coal permeability models of Shi-Durucan or Palmer-Mansoori is the characterisation of the various physical properties involved, since a number of difficult to measure properties are involved. This paper summarises the influences on coal permeability and in particular the role of coal shrinkage with gas desorption and compressibility with pore pressure and the importance these processes could have on predictions of gas production. The paper considers the assumptions involved in the derivation of the models to describe coal permeability and the impact these could have on predicting gas production. A novel model is derived which is more general and this serves as a basis for the discussion presented in this paper. Measurements of coal properties (cleat compressibility, geomechanical properties, Biot coefficient) with respect to pressure are presented for two Australian coals (a sample from the Hunter Valley and one from the Bowen basin) and the measured behaviour compared with that assumed in the Shi-Durucan and Palmer-Mansoori coal permeability models derivation.
Transforming Data into Knowledge using Data Mining Techniques: Application in Water Production Problem Diagnosis in Oil Wells
Authors: Rabiei M. , Gupta R. , Cheong Y. P. , Sanchez Soto G. A. 
Published: February 2011

Abstract
Excess water production is a serious economic and environmental problem in most mature oil fields. Accurate and timely diagnosis of the water production mechanism is critical in the success of the applied treatment methodology. While many empirical techniques have been traditionally used in production data analysis, the significance of water-oil ratio (WOR) in proper identification of the type of the water production problem in oil wells is not yet fully investigated. Data mining techniques could facilitate extracting any hidden predictive information from oil and water production data to be used in water control studies.
This paper applies a meta learning classification technique called Logistic Model Trees (LMT) to diagnose water production mechanisms based on WOR data and static reservoir parameters. Synthetic reservoir models are built to simulate excess water production due to coning, channeling and gravity segregated flows. Various cases are then generated by varying some of the input parameters in each model. A number of key features from plots of WOR against oil recovery factor are heuristically extracted by segmenting these plots at certain points. LMT classifiers are then applied to integrate these features with reservoir parameters to build classification models for predicting the water production mechanism in different scenarios of pre and post water-production stages.
It is observed that a valid association between WOR data and the water production mechanism exists. Our results with high prediction accuracy rates of 88% for pre-production and more than 94% for post-production stage demonstrate efficiency of the proposed LMT classifiers and significance of WOR values in classifying excess water production problems.
Assessing the Underground CO2 Storage Potential in a Highly Populated and Industrialized Area: The Case of Lombardia Region Italy
Authors: Macini P. , Mesini E. , Moia F. , Guandalini R. , Savoca D. 
Published: February 2011

Abstract
The paper is aimed to the assessment of the CO2 underground storage potential of Lombardia Region (Italy), one of the most populated and industrialized area of the Country. The study is intended to locate adequate sites for the potential application of carbon capture and geologic storage in deep underground formations.
The first part of the study concerns the evaluation and analysis of the mass of CO2 generated in Lombardia Region (the largest CO2 producer in Italy, with over 70 million metric tonnes per year of CO2 released in the atmosphere) by investigating both the localized sources (industry, power generation, etc.) and the diffused ones (transport, domestic heating, etc.). The second part of the study concerns the technical evaluation of the possibility to put into practice the geologic storage of CO2 in deep underground formations of Lombardia Region. Finally, the study reports some preliminary evaluation for the possible implementation of a CO2 storage pilot plant in the area. In particular, a potential candidate located in a deep saline aquifer has been identified, and its geological and hydrodynamic modelling has been extensively studied and analyzed. The investigated reservoir has a storage capacity of more than 370 million metric tonnes of CO2, corresponding to about 30 years of CO2emissions produced by the main thermoelectric power plants located in the same area.
Breaking Low Permeability Fracturing Myth – VICO Indonesia
Authors: Wijanarko Andre , Rylance Martin , Pizzolante Italo , Chatib Hazman , Dharma Budi 
Published: February 2011

Abstract
VICO Indonesia is the operator of the Sanga-Sanga Production Sharing Contract; located onshore of the Mahakam delta, in East Kalimantan, Indonesia. Since inception the PSC has produced over 70% of the estimated original gas in place. The fields are relatively mature with most of the remaining gas resources locked up within the lower permeability reservoirs, where conventional tight-gas completion approaches have not been very effective in ensuring depletion of the resource. A valuable prize of at least 0.5 TCF would be readily achievable, if these lower permeability resources could successfully be developed and recovered.
The lower permeability formations being referred to; are typically sub milli-darcy, and the ability to achieve any kind of sustainable economic production rate has been extremely problematic. Previous attempts at hydraulic fracturing within VICO, over nearly three decades, have been dramatically ineffective and have rarely enjoyed any sustained production improvement at all. Geologically the reservoirs are best described as distributary river channels, in a lower deltaic plain environment and therefore these individual sands can vary in size and connectivity quite substantially. Alternative technologies, such as horizontal drilling are being applied, but only within those sand bodies which are larger and which can therefore readily support the economics associated with horizontal well drilling.
In 2006 a detailed technical review of the previous 30 Years of hydraulic fracturing operations was commissioned, this review noted that there were five basic ‘skins’, which were causing problems for hydraulic fracturing. These ‘skins’ were: wellbore integrity, execution QA/QC, relative-permeability, regional tectonics and poro-elasticity. The data was extremely convincing and based upon the review a decision was made to implement a five well pilot in order to confirm the findings and present solutions.
This paper will describe the long and difficult journey of VICO hydraulic fracturing, from the original treatments through the recent review, the fracturing pilot from 2007 - 2009 and into the early stages of the new fracturing campaign planned for 2010 - 2012, The paper will present the results of the detailed study, the implementation phase of the pilot and the forward plan for the VICO low permeability zone(s) based upon the significant progress, successes and deliverables of the fracturing pilot in the Nilam G-Sands.
CO2 Storage in Saline Aquifers: Design of a Demonstration Project to Dispose CO2 Associated with Natural Gas Fields in South China Sea
Authors: Zhang L. , Ren S. R. , Zhang Y. , Mi H. G. , Ma Y. X. 
Published: February 2011

Abstract
DF1-1 gas field in the west of the South China Sea is associated with high concentration of CO2. Many options have been assessed by the operator (CNOOC) in recent years in order to dispose the CO2 separated from the gas stream. In this study, geological storage of CO2 into offshore saline aquifers near the gas separation plant on the Hainan Island is considered, and a demonstration project is proposed and designed in terms of aquifer selection and assessment, CO2 transportation and injection, and project economics. Several aquifer structures around the gas field and near the Hainan Island were investigated and assessed with respect to geological structure, reservoir and trap features, fluid properties, storage capacity and site location. A saline aquifer (namely LT13-1), 60 km offshore the Hainan Island, was chosen as the storage site. CO2 will be transported by a long-distance subsea pipeline at high pressure and injected into the aquifer via a subsea well-head and through a horizontal well. Reservoir simulation and injectivity analysis have been conducted to estimate the injection rate and pressure, and also to predict the movement of CO2 after injection. A scoping economic analysis of the project was also conducted and presented in the paper.
Quantifying the Effects of Well Type and Hydraulic Fracture Selection on Recovery for Various Reservoir Permeability Using a Numerical Reservoir Simulator
Authors: Shelley R. F. , Lolon E. , Dzubin B. , Vennes M. 
Published: February 2011

Abstract
The industry is faced with the task of producing hydrocarbons from increasingly tighter reservoir rock including ultra low permeability sand and shale. As a consequence, the selection of an appropriate well type and fracture stimulation design is becoming even more critical to project success. The purpose of this paper is to provide some clarity by providing a general understanding about the effects of well type selection and hydraulic fracturing on hydrocarbon recovery for various reservoir permeability scenarios. Well types modeled include vertical, stimulated vertical, horizontal, axial stimulated horizontal and transverse stimulated horizontal with variations in compartment length and effective fracture length. This information has proven useful in the evaluation and planning of moderate to low to ultra low permeability well projects.
The summaries that will be presented in this paper are a compilation of the results from numerous simulator runs for gas, black oil and gas condensate cases. These simulator runs included sensitivities on well type and permeability in order to compare recovery and production. Important conclusions pertaining to the recovery of hydrocarbons from ultra low permeability reservoirs and shale are made. In addition the obvious conclusion about the increasing difficulty of recovering hydrocarbons from lower permeability rock, a primary conclusion is that as reservoir permeability decreases, proper well type selection and effective hydraulic fracture stimulation design become much more crucial. The conclusions also show that for a given permeability, obtaining significant recovery of oil can be a much more difficult problem than with that of dry gas. These conclusions are supported by Bakken and Barnett Shale case histories which are included in this publication.