bluuebunny/crossref_metadata_2025_split huggingface dataset:
Anisotropic Permeability Measurement of Porous Media: A 3-Dimensional Method
Authors: Asadi Mahmoud , Ghalambor Ali , Rose Walter D. , Shirazi Mogdeh K. 
Published: December 2007

Abstract
A simple model is developed to measure principal permeabilities of anisotropic media. The developed model presents an accurate procedure to measure principal permeabilities of both two and three-dimensional anisotropic media. A special core cutting procedure is developed to measure principal permeabilities of an anisotropic medium under isotropic conditions. This procedure enables flow rate measurements at upper and lower sections of an anisotropic sample end face. A logarithmic plot of upper flow rate to lower flow rate ratio versus the sample's end-face angle, results in the precise measurement of the end-face angle which once the sample is shaped to that angle flow velocity vector is uniform and parallel to the sample's long axis over the entire core length. Once this is accomplished, similar procedure is applied to the left and right halves of the core sample's end- face. This procedure assures the elimination of end effect flow pattern, which is created due to the anisotropicity of the system. Measurement of flow rate in an arbitrary Cartesian axis system results in determination of nine elements of a second rank permeability tensor. Through the eigen-value theory, principal permeabilities (Kmax, Kmin, and Kint) of an anisotropic medium are then calculated.
Integrated Amplitude Versus Offset (AVO) Approach for Delineating Stratigraphic Traps
Authors: Yusof Mohd Azudin Bin Mohd 
Published: December 2007

Abstract
Exploration for Stratigraphic trap is of higher risk but the reward can be spectacular since the closure is not limited to structural spill point. Specialized exploration tools such as 3D seismic have become economically feasible and the use of super computers has resulted in improvement in data quality and interpretation. 3D marine seismic data acquisition has become more efficient and even 3D AVO is becoming cheaper. However, integration of well data or nearby well information is highly recommended to reduce risk since high amplitudes visible on seismic data do not necessarily related to Direct Hydrocarbon Indicator (DHI). As a prerequisite, seismic processing steps need to be evaluated carefully to preserve amplitudes. This paper is based on a test AVO processing and interpretation done on Field A in the Malay Basin. Result from the test line processing and interpretation has broadened in-house expertise on the AVO technique. The analysis could also be used to upgrade the probable or possible reserves to proven reserves and to delineate stratigraphic traps.
Integrating Pressure Data from Formation Tester Tool and DST to Characterize Deepwater Fields, East Kalimantan, Indonesia
Authors: MacArthur Jack , Vo D. T. , Palar Steve , Terry Albert , Brown Trevor , May Ron 
Published: December 2007

Abstract
In the last three years, two significant commercial hydrocarbon accumulations in Indonesia deep waters of the Makassar Strait were discovered. These fields are located approximately 16 miles northeast of the giant Attaka Field in 1400 ft to 3400 ft of water.
To date more than 40 exploration and appraisal wells have been drilled in both fields and extensive pressure data has been collected by formation tester tool and drillstem testing tool. The pressure data, used with other data such as seismic and well logs, has enabled Unocal Indonesia to characterize deepwater turbidite sand reservoirs.
In this deepwater environment, DST is used selectively and only with strong justification due to its prohibitive cost. Instead, the use of the pressure testing tool is pushed to its limit in order to gain extensive pressure, rock and fluid properties data, conventionally obtained by DST.
This paper will show the experience of Unocal Indonesia to characterize deepwater reservoirs by means of pressure data from the formation tester tool and DST's to complement geological and seismic data interpretations. Reservoir characteristics such as fluid type, fluid contacts, reservoir connectivity and sand geometry can be inferred from the pressure gradients and pressure transients. These data are used in constructing reservoir fluid flow models for field development plan.
Managing Assets under Uncertainty
Authors: Davis J. P. , Fletcher A. J. P. 
Published: December 2007

Abstract
The management of exploration, appraisal and production is a problem of leveraging the expertise of a company to maximise the potential of the asset. The word company is very appropriate here as it describes well the gathering of disparate disciplines focussed on a specific purpose. The management of the asset is a process that requires the gathering and integration of evidence of many different types from different experts with all kinds of uncertainties.
This paper describes a methodology and tool for handling that process in multidisciplinary teams. It is a generic technology that can be applied across the business. It is being applied to estimating the dependability of reserves estimates, estimating the likelihood of success of a prospect, enterprise resource management, technology selection and condition monitoring. Case studies are presented.
The method has three elements:
a process model of the management process highlighting dependencies, a record of the attributes of the process, and, a rich uncertainty calculus for the integration of uncertainties.
The uncertainties are expressed using interval probability which allows the evidence for success to be separated from the evidence against success. The whole approach is implemented in a highly visual graphical environment that allows new users to build new models very quickly.
Case studies have shown that the added value comes not just from the numerical assessment of the overall dependability of the project, but from improved communications both inside and outside the team. A shared understanding of the situation is developed and misunderstandings resolved. The model gives a one page pictorial overview of where the project stands, showing where the vulnerabilities and sensitivities are. In terms of corporate memory it provides an easy to assimilate record of how the conclusions were reached and a shared memory for the team.
Integrated Modelling and Uncertainty Management of a Gas Injection Scheme in a Highly Fractured Carbonate Reservoir
Authors: Woodhead T. J. , Willemse E. J. M. , Mills R. M. 
Published: December 2007

Abstract
Multiple scenario modelling methodology has been used to study gas injection in a fractured carbonate reservoir to facilitate an increase in productivity and ultimate field recovery as a result of reservoir repressurisation. The complex physical processes involved in the production mechanism, and a relatively sparse data set, highlighted the underlying problem of making predictions based on reservoir models for which a large degree of uncertainty exists. These uncertainties have a significant impact, both in the understanding of the reservoir fracture geology and in the data used for describing the fluid flow processes. A novel approach was developed to represent uncertainty ranges in model forecasts in which multiple history-matched simulation models were constructed to represent the impact of a range in each of the uncertainty parameters on the forecast. The methodology builds on an approach previously reported in Bentley and Woodhead (Ref.1). The results were then combined statistically into probability distributions of recovery profiles. The results show clearly the large impact of data uncertainty on incremental recovery arising from the gas injection scheme. The treatment of uncertainty presented here is a step forward in the modelling methodology for mature assets in which multiple scenario modelling has to be constrained by the necessity to history match all model realisations against production data.
Electrical Dissipation Factor: A Novel Way To Detect Changes in Shale Water Content
Authors: Adisoemarta P. S. , Heinze L. R. , Morriss S. L. 
Published: December 2007

Abstract
The alteration of shales, caused by adsorption of water while drilling, is one of many contributors to the wellbore stability problem that costs the industry in the order of $ 400-500 million annually (Bol et.al., 1992). This alteration of shale problem has acquired a logging perspective due to the increasing use of measurements while drilling. The capability of taking real time and time-lapse measurements while still drilling introduces the possibility of detecting a swelling problem while something can still be done about it.
The objective of this study (Adisoemarta, 1999) is to observe the changes of complex electrical characteristic of shale as a function of water content. The word "complex" in the electrical characteristic term means this study will not only observe the "in-phase" electrical response but also the "out-ofphase" response.
By taking the ratio of the in-phase to the out-of-phase electrical response, this study found that this ratio, the dissipation factor, changes linearly as a function of shale water content. This method can be easily applied to both the drilling / wellbore stability or formation evaluation areas.
Benefits of Using Automation Software for Gas Production Optimization
Authors: Ray Louis , Juran Kenneth 
Published: December 2007

Abstract
This paper describes the cash flow enhancement benefits of using automation software for gas production optimization. Efficiently monitoring well and facility operations, analyzing well performance, and accurately predicting problems with software optimization tools has resulted in significantly decreased failure rates and increased production per well.
The automation software allows producers to move from a reactive mode to a proactive mode. Wells become more stable, and analysts can spend more time fine tuning operations for maximum production rather than fixing emergencies. In short, the networked automation software system calls on computers and other devices to handle the manual and repetitive work of monitoring wells and facilities, as well as collecting and crunching numbers.
The optimization process goes beyond basic operations, but extends into production optimization involving well testing, facilities monitoring and alarming, production monitoring, and gas injection. The net effect is increased runtime and arrested decline curves, resulting in more reserves.
Tiltmeter Hydraulic Fracture Mapping in the North Robertson Field, West Texas
Authors: Mayerhofer M. , Demetrius S. , Griffin L. , Bezant R. B. , Nevans J. , Doublet L. 
Published: December 2007

Abstract
This paper presents both downhole and surface tiltmeter hydraulic fracture mapping results of five fracture treatments (in two wells) in the Clearfork formation located in the North Robertson Field, West Texas. This field is under waterflood and both injectors and producers are generally fracture treated in three stages at depths of roughly 6,000 to 7,100 feet. Surface tiltmeter mapping was performed on all five treatments to determine hydraulic fracture azimuth and dip. Downhole tiltmeter mapping was performed on 2 treatments in one well to determine the fracture geometry (height and length). In addition, other diagnostic technologies such as fracture modeling and radioactive tracers were used and their results and conclusions are discussed in conjunction with tiltmeter mapping. Understanding hydraulic fracture growth is of critical importance for evaluating well placement and the risk of communication between producers and injectors and to assess fracture staging, perforating and well performance issues.
A Prospectors Dream Come True: Tons of Unique Data, All Under One Roof!
Authors: Barrett Damian , Trentham Bob 
Published: December 2007

Abstract
Have you ever worked on a prospect that all you needed to finish it off wasa mud log or core analysis on that one older well in your cross-section? Or youdrilled your first well in your prospect and needed a full scale offset log tocorrelate with on location? Now you can have access to the largest and uniquecollection of data in the Permian Basin - all under one roof, The MidlandEnergy Library (MEL). This old, new and unique data has not been lost, it hasbeen donated to MEL.

Mission Statement
The Mission of MEL is to collect, preserve, catalog and exhibit scientific, geological and engineering data gathered by the petroleum industry into aworking library for use by industry professionals, educators, students andother members of the interested public.

Rare Specialty Data
MEL has over 1550 DST's and 8570 mud logs in Texas, over 350 DST's and 2400mud logs in NM and over 6750 core reports in Texas and NM and over 55,000sample logs. One to 4000 ownership map spotted weekly with new wells from PIweekly reports. Gravity and Magnetic maps, velocity surveys, dipmeters andsynthetics. There are even company donated prospect files that are just waitingto be found and drilled. There are over 550,000 Fusulinid slides withmicroscopes and a petrographic microscope with a camera. The collections arefrom Hollingsworth, Wendell Stewart, Van Howbert, Ed Volger and John M. Cys.Byrums 15 volume set of rules and regulations. There are over 670,000 Texaslarge and small-scale logs and 177,000 NM large and small scale logs. One ofthe best resources is the friendly, helpful staff that knows where everythingis and can quickly help you find what you need or do tech work for you for aminimal charge.

Poster Session
You will not want to miss seeing this poster session. You will get to seesome of this unique data, pictures of where it is stored; books with listingskof the special core, DST, and mud log data sorted by operator or location foryou to look through. If for some reason, you did not make it to the conferenceto see the poster, you will be able to view it onlineat: http://www.texasonline.net/mel/index.htm. However, the best way to learn more about the library is to call in and set anappointment for your personal tour.

Vision Statement
The vision of the library is to become the primary respository and atabasefor scientific, geological and engineering date relating to the United Statesoil and gas industry and to make this data abailable to the public through aworking library. It is further vision that by becoming the databse for theUnited States oil and gas industry, the library can assist the City of Midlandin achieving its goal of becoming the headquarters city for the independentsegment in the United States oil and gas industry.
Material Balance for Multi-Layered, Commingled, Tight Gas Reservoirs
Authors: Kuppe Frank , Chugh Shelin , Connell Paul 
Published: December 2007

Abstract
A simple spreadsheet model has been developed to estimate Original Gas In Place (OGIP), layer productivity and recoverable reserves for wells with commingled production, completed in multi-layered tight gas reservoirs. Differentiating the productivity between multiple layers of contrasting permeability is old technology. This model, however, replicates the observed material balance trend while also honouring total well production data by varying layer properties. The P/Z trend of the higher permeability layers and lower permeability layers is mapped to "envelope" the productivity index (PI) weighted P/Z curve that is used to match historical data.
This technique has been made applicable to the multi-layered reservoir environment by grouping the various kh terms, from all "high permeability" layers, into one model layer and all "low permeability" kh values into the "tighter" model layer. Published literature1 has already shown that the generation of the layer P/Z curves is applicable for reservoirs with permeability in the range of 0.1 to 10 md. The model has been successfully applied to match and predict the productivity for various wells in Cooper Basin fields, with permeability in this range, and P/Z plots that exhibit curvature. Case studies show that any change in bottom hole pressure conditions (eg. compression) or skin (eg. stimulation) can also be accounted for in the model. Various simulation models have been generated to confirm this technique's applicability to wells in Australia's Cooper Basin, and to establish the PI weighting method.
Economics of CO2 Sequestration in Coalbed Methane Reservoirs
Authors: Wong S. , Gunter W. D. , Mavor M. J. 
Published: December 2007

Abstract
Enhanced Coalbed Methane Recovery (ECBM) is presently not commercial due to the high cost of compression and capture of the injection gas either carbon dioxide (CO2) or nitrogen (N2). Recently, the necessity to reduce greenhouse gas emissions has provided a dual role for coalbeds – as a source of natural gas and as a repository for CO2. The second role arises because of the storage mechanism for gas in coal. Unlike CO2-enhanced oil recovery processes, CO2 injected during ECBM recovery is strongly adsorbed onto the coal, and in a relatively homogeneous reservoir is not expected to break through to the production wells until the bulk of the coalbed methane (CBM) reservoir is swept of methane. This provides a huge CO2 storage potential in coalbeds throughout the world. However, based on current economic factors, it makes more sense to partially deplete the coal reservoir of methane before injecting CO2. The exact strategy depends on two economic factors, the costs and credits for sequestration of CO2 and the natural gas sales price. CO2 credits would have a major effect on the production strategy used for CBM, and would favor early use of ECBM. An example is used later in this paper to illustrate this point that takes into account the differences between "gross CO2" sequestered (CO2 captured), and "CO2 avoided" (net CO2 sequestered).
Brine Mixing in Waterflooded Reservoirs and the Implications for Scale Prevention
Authors: Mackay E. J. , Sorbie K. S. 
Published: December 2007

Abstract
Although waterflooding is a common method for increasing oil recovery, certain production problems may arise after water breakthrough. In addition to affecting oil recovery, these problems may also have an adverse impact on the environment. One particular production problem is mineral scale formation due to mixing of incompatible brines. For example, barium sulphate formation in the production well and tubulars occurs in many oilfields when sulphate rich injection water (usually seawater) mixes with barium rich formation water close to or in the wellbore. Understanding where the scale forms is important when attempting to prevent it damaging productivity. However, there is some field evidence which suggests that scale deposition deep within the reservoir may occur without having any adverse effect on oil recovery. This paper addresses the two related issues of (i) where sulphate scales form, and (ii) whether any operator action is required where wells are producing lower concentrations of scaling ions than would be expected if scale formation was completely inhibited. These issues were raised by two papers presented at the 1st SPE International Symposium on Oilfield Scale in January 1999, and it was the ensuing discussion which initiated the present study.
All of the principal mechanisms of brine mixing in waterflood displacements are considered and modelled. This leads to a fuller understanding of where - and to what extent - brine mixing will occur within the reservoir. As a consequence, we may address the questions of why scale deposition deep within the reservoir may in certain circumstances occur, while in other situations it is probably very limited. It is demonstrated that, although connate water in the oil zone is mobilised by injected water, typically little mixing would be expected far from the wellbore. Conversely, as the different brine types, which have retained the scaling ions, approach the wellbore, mixing and scale deposition are to be expected. Mixing in the aquifer where brine mobility can be much higher, however, may result in lower than expected ion concentrations. The reduced ion concentrations may be caused by scale dropout, or by mixing of formation brines with different compositions, or by a combination of both mechanisms. In either case, modelling of such processes has confirmed that they are possible explanations for low barium levels. The impact of scale dropout deep in the reservoir on the design of inhibitor squeeze treatments is discussed.
An Experimental Study of Removing Iron Sulfide Scale from Well Tubulars
Authors: Nasr-El-Din H. A. , Fadhel B. A. , Al-Humaidan A. Y. , Frenier W. W. , Hill D. 
Published: December 2007

Abstract
This paper describes the effect of chemical interactions on the efficiency of removing iron sulfide scale. Most types of iron sulfide can be removed by inorganic acids. A corrosion inhibitor (amine-type chemical) is added to the acid to protect the well tubulars. In addition, a hydrogen sulfide scavenger (aldehyde type) is used to prevent precipitation of elemental sulfur and iron sulfide. Other chemicals are also added to the acid to enhance acid-contact with the scale and prevent precipitation of iron once the acid is spent. Laboratory tests were conducted to evaluate the effect of chemical interaction on the efficiency of removing iron sulfide scale. The influences of various acid additives (anionic, cationic and non-ionic) on the dissolution power of the acid and the corrosion of oilfield steels were examined over a wide range of parameters.

Results, Conclusions
Laboratory data indicated for the first time that the ability of the acid to remove iron sulfide scale depends, among other factors, on the ionic character of the acid additives. Corrosion inhibitors, which are used to protect the casing and well tubulars from the acid, were found to adsorb on the iron sulfide scale and inhibit acid reaction with the scale. Hydrogen sulfide scavengers, aldehyde type chemicals, were found to inhibit acid reaction, especially at high concentrations. A similar trend was noted with methanol and citric acid. On the other hand, TX-100 (a nonionic surfactant) and SDS (an anionic surfactant) was found to enhance the dissolution of iron sulfide by the acid.
Acid additives, especially anionic surfactants and mutual solvents were found to affect the ability of the corrosion inhibitor to protect the base metal.
Fracture and Production Data Integration Using Discrete Fracture Network Models for Carbonate Reservoir Management, South Oregon Basin Field, Wyoming
Authors: Parney R. , Cladouhos T. , La Pointe P. , Dershowitz W. , Curran B. 
Published: December 2007

Abstract
This paper describes the development of a discrete feature network (DFN) model for the South Oregon Basin field in the Big Horn Basin of Wyoming. This DFN model is being developed to support well placement and gel treatment in order to recover previously bypassed oil in this highly heterogeneous, structurally controlled carbonate reservoir.
The DFN model developed in this paper is based on data from outcrop studies, fracture and lithologic data from wells and lineament maps from 3D seismic. The model is calibrated against tracer test results.