bluuebunny/crossref_metadata_2025_split huggingface dataset:
Modeling, Upscaling, and History Matching Thin, Irregularly-Shaped Flow Barriers: A Comprehensive Approach for Predicting Reservoir Connectivity
Authors: Stright L. 
Published: December 2007

Abstract
Accurate modeling of flow path connectivity is critical to reservoir flow performance prediction. Flow path connectivity is controlled by the complex shape, extent and spatial relationships between pay intervals, their intersection with wells, and the existence of flow barriers between wells. This reservoir heterogeneity can be captured in a flow simulation model as facies patterns among cells and as effective properties within cells (porosity and permeability). However, fine-scale, irregularly-shaped flow barriers between cells cannot be accurately represented with pixel-based modeling techniques.
To preserve these important fine-scale geological features at the flow simulation block scale, an additional modeling variable is introduced as the edge of a model cell. This cell edge is a continuous or categorical value associated with the cell face and is defined in conjunction with the cell centered property which is often reserved for facies types and/or petrophysical properties. An edge model is created that captures the facies and edge properties as a vector of information at each cell location. For the flow simulation model, the edge properties are easily translated into transmissibility multipliers.
Using the example of 3D shale-drapes attached to channel-sand bodies in a deep water depositional setting, a methodology is presented in which these shale drapes are accurately upscaled and history matched to production data while maintaining the geological concept that describes the drape geometry. The perturbation parameter in history matching is the continuity of the shales as an edge property.
More generally, this coupled modeling of cell-center and cell-edge allows for more flexible reservoir modeling, opening up the potential for modeling and history matching complex geological features effectively at the scale that they are relevant, without additional computational cost of flow simulation.
Use of Diatomaceous Materials for Heavy-Metal Recovery From Oil and Gas Produced Water
Authors: Obanijesu E. O. , Dada E. O. , Bello O. O. 
Published: December 2007

Abstract
Production potentials of massive offshore oil and gas reserves represent a promising source of energy security for the world. However, recent developments in environmental pollution control are drawing attention to the problem of persistent hazardous metal content of produced (formation and injected) water from oil and gas reservoir that are discharged everyday from offshore facilities. The removal of heavy metal has become a very important industrial problem. Present methods for metal recovery from produced water are becoming increasingly undesirable for a number of reasons. The continued success of metal recovery from produced water hinges on the development of new technology.
In this study, a pilot-scale packed-bed reactor has been developed in order to investigate influences of process parameters and their interactions on the recovery of metals from produced water using diatomaceous material. The material was formed into a packed configuration to provide a high adsorbent area-to-aqueous solution volume ratio. Activated carbon and ion-exchange resin were tested for comparison. The results obtained show that flow-rate, residence time, metal concentration loading and packed-bed geometry significantly influenced the efficiency of the reactor system metal recovery and have to be considered in the design of large-scale system. An optimum residence time of 2 hours has been found to give the metal recovery capacities of 60%, 76% and 80% for the ion-exchange resin, diatomaceous material and activated carbon respectively. The sequestered metals were efficiently eluted from the diatomaceous material using different elution solutions for different metals. Selectivity of adsorbent for specific metals can be manipulated on the uptake and elution sides of the process. Present study also revealed that diatomaceous material can be regenerated and used many times over just as conventional adsorbents or ion-exchange resins in process wastewater purification as well as metal recovery processes.
The application of the packed-bed reactor using the readily available diatomaceous material is therefore recommended for economical and cost effective large-scale purification and recovery of metals from oil and gas produced water loaded with metals.
Successful Experiences for Water and Gas Shutoff Treatments in North Monagas, Venezuela
Authors: Perdomo Lenin , Rodríguez Héctor , Llamedo Maria , Oliveros Luis , González Edwin , Molina Osmel , Giovingo Claudio 
Published: December 2007

AbstractNormally, the average on success rate of water shut-off treatments in the world ranges between 40% – 50%. This average is lower for gas shut-off treatments. In North Monagas, Venezuela, where some hard conditions are present, such as high bottom hole temperatures (over 280 F), in some cases very tight reservoirs which complicates a matrix penetration of any gel treatment without overcoming the fracture gradient, in other cases naturally fractured wells which complicates the effectively fillout of all fracture nets; this success rate could decrease even more, making the treatment not economically attractive.In order to obtain a high success rate in North Monagas, it was designed a special aqueous polymer gel with a low viscosity to handle the difficulty of matrix penetration without overcome the fracture gradient, and delay its crosslinking process for a period of long time due to very low injected rates. Also, it can maintain its blocking properties at temperatures over 290 F without the need to inject cool-down pads; it can perform effectively even gas shut-off treatments, taking into account its difficulty due to higher mobility than water and oil.Carefully studied Coiled Tubing (CT) operations were carried out taking into account the hard conditions already described, without damage other oil producing zones. Several case histories are showed in this paper, including some gas shut-off operations, with the results obtained in each one. As a result, higher water/gas shut-off success rate than the typical average (40% – 50%) was achieved.
Eliminating Hammer Injuries in the Oil Field
Authors: Bull Brad , Neal Greg 
Published: December 2007

Abstract
A majority of onsite injuries in the energy services industry result from the use of hammers to make and break wing union connections. These injuries almost universally occur during rig-up and rig-down of high-pressure manifold equipment. The injuries can be immediate or long-term issues that usually arise from the strain experienced when swinging a hammer. This paper discusses the development and testing of a safer alternative to the current method of tightening connections called the pneumatic union driver (PUD),1 which uses compressed air as the power source to tighten connections.
The current hammer union has been a staple of the industry since it was patented in 1942.2 This connection has historically been made by repeatedly striking the lug face with a sledge hammer. Most personnel use a sledge hammer in the range of 4 to 10 lb, and each connection is typically struck from 4 to 8 times. Because locations may have 20 to 80+ connections, a typical job can present personnel with as many as 600 opportunities for injury. Hammering jobs are also typically assigned to the least experienced personnel and often performed in adverse environmental conditions (i.e. dark, cold, wet, hot, etc.).
The PUD is a modified pneumatic chipping hammer designed to apply controlled impact energy to the current hammer union. The PUD is placed on a hammer union using an adapter that fits over one lug and aligns the tool bit with the next lug. When the trigger is depressed, the chipping hammer repeatedly strikes the lug. This impact energy reduces friction in the connection. While the lug is being impacted, a moderate amount of force (20–30 lb) is applied to the handle of the tool to tighten the connection. This paper details the testing and performance requirements for the PUD. Comparison testing with conventional hammers indicated that the time required to tighten connections for both methods was approximately the same.
Drilling Simulation vs. Actual Performance in Western Canada
Authors: Hareland G. , Nygaard R. , Virginillo B. , Munro H. 
Published: December 2007

Abstract
During the past two years a drilling performance simulator has been applied in a pre-drill mode to more then 50 wells with an average depth of 3000 meters in Western Canada. The main goal of applying the simulator was to optimize the drilling performance by increasing rate of penetration (ROP) and decreasing drilling time and costs. To maximize performance the correct bits, hydraulics, operating parameters and pull depths were selected in advance. The drilling simulator uses offset well drilling data and records to generate the apparent rock strength which is then correlated to the formations depths for the new well to be drilled. Multiple combinations of drill bits and operating parameters are simulated to obtain the optimum drilling solution for the next well. The results indicate very good match between predicted and actual field results for ROPs as well as total drilling times and well costs. The simulation approach initially easily matched pacesetter performance of previously drilled wells in the mature field and then by further applying the simulator new pacesetters where set improving performance overall with more then 15 percent. The presimulated optimized results were sent to the field and during the drilling of the well the field data was overlaid with the presimulated field data to compare progress. During the drilling follow-up the bit wear and apparent rock strength calculated from the field data were compared to the presimulated to evaluate the current status of the bit and drilling progress. The follow-up process gave room to take immediate actions and a baseline for communication with the field and office during daily meetings.
This paper presents the commercially available simulator and multiple cases which compares the pre-simulated to the actual performance. The results clearly indicate the large potential for the use of such a simulator in drilling operations.
Application of Rock Strength in Drilling Evalution
Authors: Nygaard R. , Hareland G. 
Published: December 2007

Abstract
Different sources can be used to develop rock strength information along the wellbore. Such strength information is important when assessing the stability of the wellbore, selecting mud weights and designing casing programs. However, there are other areas, especially in drilling, where rock strength information is applicable, but still underutilized.
A methodology is developed to estimate drilling time and bit wear before drilling if rock strength is known. To estimate drilling time and bit wear, effects of other parameters like drilling parameters, well bore size and drilling bit design has to be normalized. This methodology has been used to estimate drilling time and estimate bit wear and further evaluate drilling performance while drilling.
After drilling the additional information has been used to conduct a post analysis and transfer knowledge from well to well. The advantage of this methodology is it eliminates the effect of geological variability when comparing performance between wells and fields.
New Era of Formation Evaluation While Drilling of Complex Reservoirs in Saudi Arabia
Authors: Al-Fawwaz Abdullah , Al-Mashrafi Nedhal , Butt Parvez , Fareed Abdul 
Published: December 2007

Abstract
Within the Saudi Aramco organization, complex reservoir formation evaluation is regarded as a key discipline – fulfilling a critical role in maximizing production and facilitating accurate estimation of reserves. The timely acquisition of high quality and detailed petrophysical properties of the various reservoirs in Saudi Arabia is central to this role. Towards this end, Saudi Aramco Reservoir Description Division (RDD) introduced a new-generation multi-functional Logging While Drilling (LWD) technology into Saudi Arabia, for evaluation of on-shore complex carbonate as well as offshore clastic reservoirs.
The traditional LWD measurements of propagation resistivity, gamma ray, density and neutron porosity along with advanced gamma ray capture spectroscopy measurements were compacted into a single collar. The electronic pulsed neutron source required for the spectroscopy measurements also provides a much improved neutron porosity measurement.
This technology has been used in a number of Saudi Aramco horizontal wells in carbonate and clastic reservoirs. The data from these wells has been comprehensively evaluated. The results of the evaluation of the data acquired by the new tool and conclusions about the tool's introduction into Saudi Arabia are summarized in this paper.
EOS-Related Mathematical Model To Predict Sulfur Deposition and Cost-Effective Approach of Removing Sulfides From Sour Natural Gas
Authors: Guo Xiao , Du Zhimin , Mei Haiyan , Fu Dekui , Wang Xun , Yang Xuefeng 
Published: December 2007

Abstract
Sulfur deposition in the formation, the vicinity of the wellbore and the production line, may significantly reduce the inflow performance of sour gas wells and increase operation cost. The work of sulfur deposition prediction and removal are increasingly performing in sour natural gas reservoirs of South China. In this paper, a gas-liquid-solid mathematical model to predict sulfur deposition, has been developed based on the characteristics of composition and phase behavior of gasliquid system. i.e., the phase behavior of gas-liquid system is calculated in light of EOS, and the elemental sulfur is considered as a non-ideal solid described by virtue of regular solution theory. The EOS-related mathematical model proved to successfully match and predict sulfur deposition via some test examples. In addition, two formulated desulphuring agents of sulphone-amine solution and MDEA reinforcing solution are presented based on the solubility of H2S, CO2 and their mixture in water. The influences of operation conditions and other factors on desulphuring agents were investigated through both indoor and industrial experiments, and the results indicated that these two formulated desulphuring agents could effectively increase the rate of removing sulfur and also overcome the problems encountered during microbial oxidation of removing sulfides. The preliminary work can help engineer evaluate accurately sulfur deposition and remove effectively sulfides so that the impact of sulfur deposition on gas production is minimized during the development of sour natural gas reservoirs.
Myths and Realities in Upscaling Reservoir Data and Models
Authors: Ringrose Philip S. 
Published: December 2007

Abstract
Reservoir modelling practice has developed into a complex set of numerical algorithms and recipes for modelling subsurface geology and fluid flow. Within these workflows a number of myths have sometimes been propagated, especially in relation to (a) methods for handling net-to-gross, (b) implementation of upscaling methods and (c) conditioning of reservoir models to well data. This paper discusses different practices in the use and upscaling of reservoir data and models, by comparing two end-member approaches: (i) the net-to-gross method and (ii) total property modelling. Implications for upscaling and conditioning reservoir models to well data are discussed, and recommended practices are suggested. A set of analytical solutions is proposed to test and quantify typical errors and misunderstandings which can be embedded in reservoir modelling workflows.
Identification of Production Potential in Unconventional Reservoirs
Authors: Grieser Bill , Bray Jim 
Published: December 2007

Abstract
Unconventional natural gas systems include fractured shale gas (FSG), tight gas sands (TGS), basin center gas (BCG), shallow basin methane (SBM), and coalbed methane (CBM). Recently, more operators are focusing attention on shale reservoirs. The most notable shale play being developed in the north Texas region is the Barnett shale. This success has encouraged operators to investigate producing potential of the Woodford and Caney shales in Oklahoma.
Shale plays are unique in that they often are both the source rock and producing rock contained in the same package. This duality leads to difficulty in log and reservoir interpretation. To date, conventional log interpretation has proved inadequate in identifying producing potential. Simply perforating areas of high porosity and pumping massive hydraulic fracture (MHF) treatments do not always yield commercial production results. Identifying areas of high producing potential using gamma ray, density, resistivity, and sonic transit time to locate high total organic carbon (TOC) has also yielded mixed production results.
We believe the addition of mechanical properties of the rock can help identify shale intervals with a high propensity to contain natural fractures and a high probability to create a fracture network during hydraulic fracturing. We propose a linkage between the mechanical properties of the rock and the hydraulic fracture network created during a MHF treatment and the resulting production outcome. Desirable combinations of mechanical properties are selected to help locate areas in the shale that have a propensity to fracture as a network with sufficient aerial extent to impact production results. We use these mechanical properties in addition to TOC and porosity to select fracture initiation sites and give a qualitative assessment of producing capacity. In this paper, we describe calculated log parameters that illustrate this technique.
Better Porosity Estimate of Gas Sandstone Reservoirs Using Density and NMR Logging Data
Authors: Hamada G. M. , Abushanab M. A. 
Published: December 2007

Abstract
Neutron/density measurements have been used to derive formation porosity. While this yields acceptable results in clean liquid-filled lithologies (sands), the effects of lithology, hydrocarbon fill (gas), and formation heterogeneity in shaly sands increases the uncertainty in computed porosities. The technique of using combined NMR relaxation times and bulk density data described in this paper significantly reduces uncertainty in derived logging parameters through elimination of the neutron log. This removes the need to correct for flushed zone
This paper describes the application of DMR technique in cored wells in a gas field, Western Desert, Egypt and it discusses the results obtained, limitations and benefits, along with the data acquisition requirements. Field examples demonstrate the importance of the (DMR) technique in place of the use of NMR or conventional logs separately in determining formation porosity and gas saturation in tight gas sand reservoirs.
Producing the Well by a Compensated Pump
Authors: Buchman Smil S. 
Published: December 2007

Abstract
The production cumulative index (bbl/psi) or CPI, is the relation of the cumulative production versus the decline in the reservoir static pressure. This recorded index shows that the reservoir produces more bbl/psi static pressure as the reservoir static pressure decreases. The increase in the CPI can also be seen in a DST during the build up period. The increase in the CPI is explained by a better use of the reservoir energy when the production is lifted for shorter distances above the perforation. To increase the CPI it is necessary to produce the well by a compensated pump. This is a pump which is not driven by the intake fluid. Producing the well by a compensated pump increases the well efficiency in rate and cumulative production by about 200–250%.

1. Introduction
The static pressure and the cumulative production are the two most important reservoir parameters. The static pressure represents the reservoir physical status, and the economical status is represented by the cumulative oil and water recovered during the production activity. Accordingly, maximizing the ratio between the recovered production versus the well static pressure decline, is the main goal of the production activity. This ratio is called the cumulative production index (CPI) and it is defined in bbl/psi. The well production recorded data shows that the CPI is variable and increases continuously as the reservoir static pressure decreases. Producing the well with the maximum CPI is the target of good production practice.

2. Recorded Well Production Activity
a. The well cumulative production The oil reservoir is a huge sealed volume of permeable and porous rock. The reservoir is always sealed because after recovering the liquids from the underground the reservoir static pressure declines and actual never rebounds. The reservoir pores store the liquids and the permeability allows it to flow from the reservoir into the well bore. The only source of energy used to move the production through the pay zone and up into the well is the expansion of the reservoir fluids. Table 1, shows the Wilcox reservoir1 static pressure decline versus the cumulative production recovered:
Table 1. Wilcox Reservoir, Cumulative Production Index
The data shows a CPI increase from 1,850 to 17,020 bbl/psi or an efficiency increase of 920% versus a static pressure decrease from 3793 to 3277 or 86%. As the reservoir static pressure declined the well produced appreciable more oil per psi reservoir static pressure decline.
Yates Field2 production history is another example of the increase in the CPI as the reservoir static pressure declined.
Meeting the Environmental Challenges in Cementing
Authors: Håheim Ståle , Scoggins W. Chrys , Lebo Stuart , Ø. Pedersen Rikke 
Published: December 2007

Abstract
With the oil industry moving into increasingly sensitive areas, the call for environmentally friendly cement chemicals is more important than ever. The focus on minimizing harmful chemical usage, and finding suitable replacement additives for cement systems, without compromising the properties of the slurry has been a priority for a long time.
Within the North-East Atlantic area, where environmental legislation is defined by the OSPAR commission1, there is a definitive list of products that are considered to be non-harmful to the environment, known as PLONOR (Pose Little Or NO Risk).2
This paper describes the development of some PLONOR cementing additives, the first use of an all-PLONOR cement slurry in the Norwegian sector of the North Sea, and the proposed use of a low fluid-loss, gas controlling cement slurry containing only PLONOR additives.
The challenge was to find a defoamer, dispersant and fluid loss additive from the chemicals on the PLONOR list. Although it is the additive with the lowest loading in the cement system, the defoamer was the biggest challenge. Since defoamer is required in all cement slurries, finding a PLONOR alternative was the most critical. The new dispersant and the fluid-loss additives are based on existing technology, but the challenge was to make the allowable PLONOR chemistry fit the functional requirements for use in a cement system.
One milestone of the project was achieved in January 2006, when the first ever cement job using only PLONOR additives was pumped in the North Sea. This was a slurry for a 13 3/8" casing that was used as a field test for the new PLONOR defoamer.
An operator has recently committed to pump the first PLONOR low fluid-loss, gas-tight cement slurry. This means that the next milestone is within reach in the near future.