bluuebunny/crossref_metadata_2025_split huggingface dataset:
Method and Application of Cyclic Well Testing with Production Logging
Authors: Rochon J. , Jaffrezic V. , Boutaud de La Combe J. L. , Azari M. , Roy S. , Dorffer D. , Webb A. , Singer J. 
Published: September 2008

Abstract
One of the predicaments of traditional well testing is the requirement of shutting-in a well to conduct a pressure buildup test for the purpose of obtaining well and reservoir properties. This deterrent factor is more prominent in prolific wells due to loss of revenue and problems associated with crossflow or when bringing a well back on production. Moreover, in case of commingled reservoirs, conventional buildup provides only average values of permeability, skin, and pressure.
An innovative periodic well testing technique named WTPL (Well Testing by Production Logging) has been developed in which a cyclic wave function is imposed in the wellbore by modulating the flowrate. The analysis of the acquired rate function and the resulting pressure wave then provides formation characteristics such as permeability and skin in the vicinity of the well. This technique eliminates the disadvantage of shutting-in a well and maintains the production with a modulating periodic pattern. In addition, the WTPL can be easily applied to commingled reservoirs to estimate the individual permeability and skin for each layer. This effort has also resulted in the development of a downhole flow modulation tool capable of creating the cyclic flow patterns needed for the new testing method.
Best Practices for Formation Testing in Low Permeability Reservoirs
Authors: Weinheber Peter , Boratko Edward , Contreiras Kilamba Diogo , Van-Dunem Francisco , Spaeth Robert , Dussan V E B , Rueda Marco , Gisolf Adriaan 
Published: September 2008

Abstract
The data provided by wireline formation testers (WFT) is critical to the evaluation and understanding of petroleum reservoirs. Pretest pressures, gradients and mobilities are generally regarded as essential inputs to the reservoir evaluation model. However, acquiring this data in low permeability reservoirs can prove challenging. There is no stable flowing pressure during the pretest, build-up times can be long and the confidence level of the final pressure is often uncertain. These issues are painted on the ever-present backdrop of supercharging that can limit the data's utility or, in some cases, invalidate the results.
New generation formation testing tools that extend the range of pretest rates and volumes have greatly improved the quality of WFT data acquired in low permeability reservoirs. Job design and planning has always been important for the proper acquisition of formation test data. Several new options, made available through the enhanced capabilities of the new generation of tools, makes packer/probe and parameter selection even more critical. Additionally, the challenges of the low permeability environment require specific attention to real time quality control and evaluation of the test data as it is acquired.
In this paper we discuss best practices for formation testing in low permeability reservoirs with examples from the US Land area and an offshore carbonate formation in West Africa. We show the pitfalls that can arise with incorrect test design as well as the improvements brought by the latest tools when correctly configured.
While there is usually confidence in the mobility data from high permeability reservoirs the numbers generated from low permeability reservoirs is often suspect: pretest volumes are typically very low and there is no stable flowing pressure. In the examples the WFT probe results are compared and validated with subsequent mobility measurements made with inflatable dual packers.
Frequentist Meets Spatialist: A Marriage Made in Reservoir Characterization and Modeling
Authors: Ma Y. Z. , Seto A. , Gomez E. 
Published: September 2008

Abstract
As a branch of spatial statistics, geostatistics is commonly used to model geologic facies and petrophysical properties. The spatial characteristics of geostatistical methods in variogram, kriging and stochastic simulation have made them the tools of choice for reservoir modeling. Such techniques are especially useful to characterize the reservoir connectivity and sweep efficiency. However, geostatistical modeling methods do not always make an accurate inference of reservoir properties from well-logs to a reservoir model because of the stationarity and ergodicity assumptions and the multiscale of subsurface heterogeneities. This often causes incorrect frequency statistics of reservoir properties, which typically exhibit a non-Gaussian distribution. As a result, estimation of the hydrocarbon in-place and recoverable reserves can be grossly inaccurate and hundreds of millions of barrels of hydrocarbons can be lost or fictitiously added in a reservoir model. An accurate reservoir characterization should include not only the realistic description of the spatial continuity but also the sound inference of the reservoir properties from fine-scale well-logs to coarse-scale reservoir models. The latter can be achieved through appropriate inference of frequency statistics coupled with spatial statistics.
An application of using both spatial and frequency statistics in a real reservoir modeling example is presented. Facies probability maps were derived from geologic propensity analysis coupled with well-log data, and used for constraining the model to honor the facies spatial association of the reef complex. Careful examination of frequency statistics helped to detect the estimation biases in the initial geostatistical model. An enhanced reservoir modeling workflow with inference coupling spatial and frequency characteristics of the geologic propensity and well-log data was developed, which resulted in a more realistic model. The history match and production performance forecast using the new model was straightforward. More importantly, the new model shows more than 100 million barrels of additional oil in-place compared to the previous geostatistical models and uncertainty evaluation based on the facies scenarios and other geologic and petrophysical variables confirms the new result. The realization of more subsurface resource has implications for future field development to target unswept oils in the reservoir.
Pushing the Limit: High-Rate Artificial-Lift Evaluation for a Sour, Heavy-Oil, Thermal EOR Project in Oman
Authors: Lanier G. H. , Mahoney M. 
Published: September 2008

AbstractPetroleum Development Oman LLC (PDO) currently operates the subject sour, heavy-oil (14 deg API) field which has produced since 1976 from a naturally-fractured, carbonate reservoir located in the northern region of the Sultanate of Oman. Further field development options have recently been evaluated and the preferred concept will be based upon thermal-assisted gas oil gravity drainage (TAGOGD). To achieve this enhanced oil recovery mechanism, steam will be injected into the reservoir and eventually increase produced fluid temperatures to more than 200 deg C during the projected life of the project.A key objective for the project will involve significantly increasing the field's ultimate recovery utilizing high-rate oil producers capable of initially delivering over 1000 m3/d gross rate per well. To achieve these well offtake rates and field ultimate recovery objectives, highly-deviated and near-horizontal well trajectories will be employed for the planned oil producers. This paper will provide a brief background of the TAGOGD recovery mechanism, anticipated reservoir conditions and particular challenges including a summary of the evaluation of various artificial-lift technologies and preferred method to help enable this thermal EOR project achieve the desired objectives.
Innovative Frac Stimulation of Low-Perm Oil Zone in High-Deviation Well Offshore Congo
Authors: Lemesnager Fabien , M'Bouyou Patrick , Gavalda Jean , McDaniel B. W. , Quero Philippe , Ranjeva Jean-Michael , Cortier Alexandre , Hurey Michael 
Published: September 2008

Abstract
Total operates an offshore oil field approximately 60 Km West of Pointe-Noire, Republic of Congo. To date, the Albian reservoir has contributed most of the oil produced. However, a significant part of the oil in place is in the Cenomanian, a low permeability sandstone formation with poor quality. As of early 2007, only two of the initial 50 wells in the field had been completed in the Cenomanian. It was desired to evaluate the potential of hydraulic fracturing stimulation treatments to more fully comprehend the production capability of this reservoir. In early 2007, a third well was drilled and completed in this structure, penetrating the Cenomanian at a 60 degree inclination for this purpose.
Proppant fracturing from a wellbore with a 60 degree inclination in a hard-rock formation has always been difficult. Also adding another level of uncertainty was the fact that the Cenomanian has never been fracture stimulated.
This paper will detail the planning process from both the operator and the service provider perspectives with specific well control issues related to an over-pressured reservoir. Review of the well conditions and operational constraints indicated the best approach would be a multi-stage pinpoint stimulation method incorporating hydrajet perforating and sand plug isolations using a stimulation vessel especially designed for such work. Additionally, a comprehensive review of the actual three-stage stimulation treatments will detail the perforating, fracturing, and sand plug isolation after each stage. With BH memory gauges just below the jetting tool assembly, post-frac reviews of downhole pressure data is compared with the live annulus data used for real time decisions during the stimulation stages. Post-frac well cleanup and early production data will be included.
Characterization and Modeling Study of the Carbonate-Fractured Reservoir in the Cantarell Field, Mexico
Authors: Shen Feng , Villavicencio Antonio Pino , Garcia Jesus Hernandez , Bustos Arturo Vazquez , Avendano JoseLuis Rodriguez 
Published: September 2008

Abstract
An integrated fracture characterization and modeling study has been performed on a large reservoir, Cantarell field, Mexico. This paper presents the methodology used for analyzing and integrating multi disciplinary datasets in order to identify main types of fractures, to predict their distributions in the reservoirs and to determine the hydraulic properties of different fracture sets. There are three sets of conductive fractures interpreted from FMI data with the consideration of reservoir geomechanics, which strike in 0°~50°, 80°~120° and 140°~180°. For each set of fractures, two scale fractures are focused: large scale fractures (sub-seismic faults and fracture corridors) and small scale fractures. 3D seismic volumetric attributes, describing reservoir coherence, dip, azimuth and lineaments, are used for the seismic facies analysis. An integrated interpretation of the facies and attribute characters, along with the geological studies, leads to quantifying and ranking fracture contents. The large scale fractures are modeled based on the structural lineaments from the ranked facies. For small size fractures, the 3D statistic fracture model is generated by a sequential Gaussian simulation technique with FMI logs and constrained with ranked facies and maximum curvatures. A 3D stochastic fracture model is then generated incorporating the two scale fractures. Correlation with flow profiles, lost circulation, water breakthrough and product index is studied in order to qualitatively determine the fluid conductivity of modeled large scale fractures. A strategy is proposed to combine two scale fractures to produce the 3D fracture property model of the reservoir. The well test analysis is used to calibrate the fracture permeability quantitatively and help to understand the main flow mechanisms occurring in the reservoir. The model of permeability conduits, calculated from fracture networks and calibrated with dynamic data, can be used for well planning and simulation. In this paper, case studies are used to illustrate applications of these technologies and their efficiency.
Ocean Sustainability and Stakeholders: The Future of Oil and Gas Industry Operations in the Marine Environment
Authors: Holthus P. F. 
Published: September 2008

Abstract
Oceans and coasts provide the majority of the world's ecosystem benefits. The marine environment is increasingly critical to the future of oil and gas resources as more exploration and production occurs there, and the maritime transport of industry products continues to grow. While the industry has been proactive in developing discreet projects to respond to perceived challenges, ocean management regimes, such as marine protected areas, are being determined by governments, intergovernmental bodies and NGOs in a variety of fora.
There is a need to develop integrated ocean strategies and partnerships to ensure that energy requirements are met without damage to important ocean ecosystems. In addition, the industry needs to engage on ocean sustainability issues with the other sectors of the ocean business community (shipping, fisheries, cruise ships, etc) – and with other stakeholders (government, intergovernmental, NGO). A multi-sectoral and multi-stakeholder approach can result in cost-savings (e.g. collaborative research to find science-based solutions to shared issues) and reduce the risk of costly, unplanned and unnecessary restrictions to operations in the marine environment.
This paper will provide a global overview of the issues, the stakeholders, actions to date, and legal context critical to industry operations potentially constrained by ocean environment concerns, and identify potential strategies, options and priorities for action.
Critical Review of Existing Solutions to Predict and Model Liquid Loading in Gas Wells
Authors: Solomon F. A. , Falcone G. , Teodoriu C. 
Published: September 2008

Abstract
Liquid loading in gas wells is a multiphase flow phenomenon where the liquid content of the well creates back pressure (usually dominated by gravitational pressure changes) which restricts, and in some cases even stops, the flow of gas from the reservoir. The industry recognizes the importance of liquid loading and tries to alleviate the problem using various measures, yet the fundamental understanding of the associated multiphase phenomena remains weak. This paper discusses the complexity of the multiphase flow phenomena associated with liquid loading in gas wells. An extensive review of the current modeling solutions available to predict the arrival of liquid loading, diagnose its impact on production and screen remedial options is presented. The paper also critically reviews recent attempts to model the dynamic interactions between reservoir and wellbore. The review highlights the limitations of the current models, stressing the need for a fully transient multiphase flow approach.
Development of a New Plunger-Lift Model Using Smart Plunger() Data
Authors: Chava G. K. , Falcone G. , Teodoriu C. 
Published: September 2008

Abstract
The problem of liquid loading, which is common to all mature gas producing wells, needs to be identified and solved in order to achieve efficient gas production. Field operators not only need to select the best possible technical solution for liquid loading, but also one that is cost effective.
A popular remedial solution for liquid loading in onshore gas wells is plunger lift. However, this technology is currently designed using simplistic models with restrictive assumptions, coupled with field experience.
This paper provides an overview of the various plunger lift models available in the public domain and highlights their fundamental limitations. A new approach to plunger lift modeling is then proposed, which assumes the availability of pressure and temperature data provided by smart plungers. These devices are equipped with internal gauges to record pressure and temperature with time, which can be downloaded whenever the plunger is at surface. In the proposed model, these data are coupled with the fundamental conservation equations of mass, momentum and energy that govern the dynamics of plunger lift. The main difficulties of dealing with transient flows that are typical of plunger lift operations are identified. These include the dynamic interactions between reservoir, annulus and tubing, which are particularly relevant in tight gas reservoirs. The overall objective is to develop a model capable of predicting plunger lift operations in a more realistic fashion and so optimize lift cycles.
Investigation of Swirl Flows Applied to the Oil and Gas Industry
Authors: Surendra Meher , Falcone Gioia , Teodoriu Catalin 
Published: September 2008

Abstract
The work presented in this paper is part of a larger Research Project which is aimed at finding solutions to problems associated with liquid loading, erosion at pipe bends due to sand particles and phase separation. The work uses computational fluid dynamics (CFD) to design solutions that can reduce or eliminate the aforementioned problems. Here, the results from CFD simulations of two-phase air and water flows are critically analyzed via comparison with the results from experiments carried out by Falcone et al. (2003) using the ANUMET* concept. The entire experimental setup is modeled within the CFD simulation and flow rates for water and air are taken from the data used for the experiments. Important variables such as pressure drop and fluid film thickness, which were monitored closely during the experiments, are obtained from the CFD simulations and compared with the experimental results. The results presented in this paper provide insights into the physics of two-phase swirl flows, identifying areas of research that still need to be addressed.
Effect of Salinity and pH on Pickering Emulsion Stability
Authors: Wang X. , Alvarado V. 
Published: September 2008

Abstract
The stability and morphology of crude-oil emulsions with and without suspended kaolinite or silica were investigated as functions of salinity. First, synthetic reservoir brine with 1, 10 and 100 times dilution was emulsified with crude oils of commercial interest, at several water-oil ratios, on which salinity effect on emulsion stability was studied. Also, the emulsion was prepared by mixing this oil with 100 times dilution dispersed with particles to investigate pH effect on emulsion stability. The clay zeta potential at different pH was measured to estimate the effect of particle charge on emulsion stability. Clay particle-size distribution, which impacts the formation and stability of emulsions, was obtained using light diffraction. The stability of emulsion was determined by simple bottle tests and by using an optical microscope equipped with a digital camera. Our results show that both kaolinite and silica promote emulsion stability. Most emulsions turned out water-in-oil. Also, kaolinite of the order of 1μm in size more easily adsorb at the oil-water interface, while silica with larger diameter, such as 5μm, can form more stable emulsions than with 1μm and 3μm. Zeta potential measurements and bottle tests clearly show that clay particles with zero point of charge (ZPC) at low pH become less effective at stabilizing emulsions in contrast with reservoir conditions, while silica shows the opposite behavior, stabilizing better emulsion at ZPC. Salinity, especially calcium concentration, affects the morphology and stability of emulsions. We can conclude that low-salinity waterflooding provides adequate conditions for formation of relatively stable emulsions, provided kaolinite detachment occurs. This is also apparent in reports of produced water re-injection.
Numerical Modeling of Pressure and Temperature Profiles Including Phase Transitions in Carbon Dioxide Wells
Authors: Paterson Lincoln , Lu Meng , Connell Luke D. , Ennis-King Jonathan 
Published: September 2008

Abstract
Geological storage of carbon dioxide will usually be at conditions above the critical temperature and pressure, so the carbon dioxide will exist as a single dense phase. However, conditions in the upper part of a carbon dioxide well with surface temperatures below the critical point of 31 C can lead to boiling and condensation in the well. The consequences of this are most apparent when flow rate changes, for example when a well is shut-in or if there is a well blowout.
We have calculated density profiles for wells experiencing different thermal conditions to determine how bottom-hole pressures are related to wellhead pressures. There are two limiting cases, one when the fluid is in thermal equilibrium with the rock at the same horizon, the other when there is no heat exchange with the casing or the rock. We find that in deeper wells static columns can exist in a stable state with liquid to the surface, but for shallower wells or wells in depleted reservoirs that a static column can be initially unstable with two-phase conditions near the surface.
In producing wells, as the flow rate increases from static conditions, the pressure and temperature at the wellhead increases until high production rates are reached when the wellhead temperature then decreases, which can be to very low values. For injection wells, bottom-hole conditions are confined between the wellhead and the reservoir temperature.
In general, phase change does not prevent carbon dioxide injection. Nevertheless care is needed in shallower or depleted reservoirs for the interpretation of reservoir pressure, the use of pressure for monitoring, and in all reservoirs for the management of blowouts.