bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Effect of Pore-Scale Heterogeneities on Carbonate Stimulation Treatments
Authors: Ziauddin Murtaza , Bize Emmanuel 
Published: December 2007

Abstract
Most carbonate reservoirs are heterogeneous at multiple-length scales. These heterogeneities strongly influence the outcome of acid stimulation treatments which are routinely performed to improve well productivity. However, most previous studies reported in the literature have focused on investigating the effects of injection rate, temperature, and fluid properties and few have focused on the influence of rock properties on stimulation treatments. This study primarily explores the influence of pore scale heterogeneities on stimulation treatments. Some results on the influence of core scale heterogeneities are also presented.
Core samples from eight different carbonate rocks were selected for the study. Samples were characterized for mineralogy, texture, fabric, porosity and density distribution using Nuclear Magnetic Resonance (NMR), Computed Tomography (CT) scanning, Scanning Electron Microscopy (SEM), mercury injection as well as resistivity measurements, chemical testing, etc. Each sample was then classified into a Reservoir Rock Type (RRT) which is primarily based on the porosity spatial distribution (PSD) in the carbonate. Each RRT represents a group of carbonate rocks with similar porosity spatial distribution and is expected to exhibit similar behavior to fluid flow and, therefore, to acid dissolutions. The 8 carbonate rocks investigated in this study represent 6 different RRTs.
Each carbonate type was treated with reactive fluids. Two different sets of coreflow tests were performed on 6 x 1.5 inch plugs. The first set of experiments involved determination of the evolution of permeability with porosity for the RRT. In these experiments the core was treated at high injection rates with a fluid of low reactivity. Injection at a high flow rate ensured uniform dissolution of the medium. Porosity was monitored by analysis of the effluent and permeability was monitored by the pressure drop across the cores.
The second set involved determining the acid breakthrough curves for each of the carbonate types using HCl (hydrochloric acid) as the reacting fluid. The characteristic pore-volume to breakthroughs (PVBT) and the wormhole velocities were obtained for each carbonate by injecting acid at different flow rates.
The results of the tests confirm the original hypothesis that the response of the carbonate rock to acid depends on the RRT it belongs to. In other words, rock samples with similar PSD exhibit similar trends in PVBT. The significance of the results to the design of matrix treatments in carbonate reservoirs is discussed.
Possible Alteration of Tight Limestone Rocks Properties and the Effect of Water Shielding on the Performance of Supercritical CO2 Flooding for Carbonate Formation
Authors: Zekri Abdulrazag Y. , Shedid Shedid A. , Almehaideb Reyadh A. 
Published: December 2007

Abstract
This work presents results obtained in a laboratory study investigating the possible alteration of tight limestone cores properties such as porosity, permeability, and wettability; and the effect of water shielding on a water driven slug of super critical CO2. Reservoir condition corefloods were conducted using actual rock cores and fluids obtained from a field in Abu Dhabi at 4000 psia and 250 °F. Recovery from core floods and the permeability and porosity before and after the flood were measured to examine the effects of SC CO2 flood on the tight composite limestone cores. Oil samples produced in the experiments were analyzed using gas chromatography (GC) to assess the mechanism of CO2–improved oil recovery. The characteristics of relative permeability were measured prior to and after SC CO2 flood. Changes in the relative permeability characteristic were used to evaluate the effect of SC CO2 flood on the limestone rock wettability alteration. Oil/water interfacial tensions (IFT) measurements as function of pore volume injected were conducted to evaluate any possible changes in interfacial forces due to the SC CO2 flooding.
Ultradeep Drilling Pushes Drillingstring Technology Innovations
Authors: Jellison Michael J. , Chandler R. Brett , Payne Mike L. , Shepard Jeff S. 
Published: December 2007

Abstract
Drilling ultra-deep (UD) wells places significant requirements on the drill string. Lengthy drill strings lead to high tensile loads which can lead to slip crushing of the drill string, hoisting capacity issues and drill pipe collapse capacity concerns at the blowout preventer (BOP). BOP shear rams may also have difficulty shearing today's high strength, high toughness drill pipe. BHA connection failures pose greater risk and cost at UD well depths.
This paper analyzes the many challenges associated with drill string designs specifically for UD drilling. It presents emerging drill string technologies that are solutions expected to increase depth capability for the industry's continued advancement of deep drilling operations.
A Quantitative Model for the Effect of Wettability on the Conductivity of Porous Rocks
Authors: Montaron Bernard 
Published: December 2007

Abstract
Reservoir rock wettability is an important parameter to consider for oil recovery optimization. The great majority of sandstone formations is known to be strongly water-wet. In contrast, most carbonate reservoir rocks are believed to be mixed-wet or oil-wet to some degree with a non-uniform distribution of the wettability in the reservoir. Despite the importance of this parameter there is currently no proven quantitative logging technique that can provide a continuous wettability log.
A detailed analysis of a new model for the conductivity of reservoir rock called the ‘connectivity equation’ is provided in the paper. Similar to Archie's law this simple model has only two parameters: An exponent called the conductivity exponent μ, and the water connectivity parameter Cw. Under some conditions Cw can be equal to zero and the equation becomes identical to Archie's law in its simplest form (n = m = μ). However, in the general case the model is fundamentally different from Archie's law because in the connectivity equation resistivity is only a function of the water volume fraction. Cw is shown to account for water connectivity effects in the pore network. These effects are encoded in the expression of Cw with three terms linked respectively to 1- the ‘super-connectivity’ of micro pores in micritic grains for carbonate rocks, or the super-connectivity created by shale in shaly sandstones, 2- wettability effects in meso/macro pores, and 3- the low connectivity of vuggy porosity. This model is compared with published data and is shown to correctly account for most situations, including ‘non-Archie’ rocks such as low resistivity pay in carbonates, strongly oil-wet rocks, and the dual water model for shaly sands. A good correlation between Cw – obtained from a combination of wireline logs – and wettability measured on cores is found on data from a Middle East carbonate reservoir.
Multiskilling as a Key Factor for Economically Viable Operations in a Mature Oil Province: Oseberg East as a Case Example
Authors: Dagestad Jan Ove , Saeverhagen Erland , Nathan Eugene , Knutsen Sigurd 
Published: December 2007

Abstract
Innovative solutions for development of new technology and business models are needed to meet the economic challenges of declining production from the mature North Sea oil province.
Bed space limitations imposed by platform redesign and modification at Oseberg East as part of the operator's improved oil recovery (IOR) strategy dictate a manning solution which significantly reduces persons on board (POB) if tail production is to be economically viable.
Previous POB reduction models have typically focused on reducing the drilling contractor and production-phase manning levels on the platform. This study extends operational efficiency by employing an Integrated Services Model that encompasses multiple service providers in addition to the drilling contractor. Considering the entire crew in the context of "manning by tasks instead of manning by services" results in a substantial reduction of headcount whilst maintaining quality of execution.
The solution developed covers directional drilling, downhole fluids, cementing, logging while drilling and completion operations, as well as drilling contractor and operator tasks. Emphasis has been put on transfering all work tasks that do not require physical presence at the rigsite to the onshore organization, for which use of modern communication technology is key.
The business model promotes operational efficiency between service companies and drilling contractor through the development of non-traditional working processes that transgress individual company boundaries. Employees from third parties will be cross-trained such that their presence onboard is utilized in mission critical operations even where responsibility for the operation does not rest with their home organization. Maximising the effectiveness of onboard headcount is considered a first step in developing long-term, cost-effective solutions that will help ensure the longevity of mature assets.
This paper describes solutions developed during the detailed planning phase of the Oseberg East tail production project, challenges to implementation, and expected benefits of the new service delivery model.
How Good is the Torque-Drag Model?
Authors: Mitchell Robert F. , Samuel Robello 
Published: December 2007

Abstract
Perhaps the only "standard" drillstring model in use today is the torque-drag model originally developed by Johancsik (1973) in 1984, and put in a standard form by Sheppard (1987). Because of the simplicity and general availability of this model, it has been used extensively for planning and in the field. This model is known to be an approximation of real drillstring behavior, in particular, that the bending stiffness is neglected, so the torque-drag model is often called a "soft-string" model. There have been many "stiff-string" models developed, but there is no "industry standard" formulation. Field experience indicates that the friction coefficient that matches torque data does not match drag data.
Why does this model work well in some circumstances, yet not so well in other cases? Part of the problem may lie in the description of the wellbore trajectory and the wellbore tortuosity. However, this study concentrates on the actual model formulation. The torque-drag model formulation has been reviewed in the context of a large displacement equilibrium analysis and it was determined that the model satisfies all of the force equilibrium equations, but only one of the moment equilibrium equations. The remaining two moment equations therefore provide objective criteria for evaluating specific torque-drag problems.
Several example problems with different inclinations and wellbore curvatures are studied to show how these criteria can be used to validate torque-drag models. Some general observations are made about torque-drag model applicability, but the real value of this study is the test criteria themselves.
New Choke Correlations for Sabryiah Field, Kuwait
Authors: Alrumah M. , Bizanti M. 
Published: December 2007

Abstract
Multiphase flow occurs in almost all producing oil wells and nearly every flowing well has some sort of choke to regulate the flowing rate, for the following reasons: (1) to maintain sufficient back pressure to prevent sand entry, (2) to protect surface equipment from high pressure, (3) to prevent gas or water coning and (4) to produce the reservoir at the optimum flow rate.
Present choke correlations are best used for the area where same conditions met with the data used to generate the correlations.
Inaccurate flow rate predictions could lead to gas/water coning, sand entry, and excessive pressures at the separator which can be a major factor of killing the producer well.
In this paper, actual data production tests from vertical wells from Sabriyah Fields in Kuwait, were utilized to establish a new generalized multiphase flow choke correlation that predicts liquid flow rates as a function of flowing wellhead pressure, gas-liquid ratio, and surface wellhead choke size. The primary proposed correlation exhibits more accuracy (only 4% average error) than the existent correlations. The multiphase correlation coefficient was determined as 89%. These results will undoubtedly encourage the production engineer to utilize the proposed correlation for future practical answers when a lack of available information, time, and calculation capabilities arises.
Microfine Particles—An Alternative to Heavy Brines
Authors: Steele Christopher , Hart William L. 
Published: December 2007

Abstract
Packer fluids are used to provide hydrostatic pressure in the annulus for well control purposes or to prevent casing collapse. As such they must be capable of doing so for lengthy periods, be non-corrosive and capable of inhibiting corrosion.
Completion fluids are used to permit the completion operations of a well. These may involve running completion strings, setting screens, gravel packs, downhole valves etc. To function effectively, completion fluids need to be able to provide hydrostatic pressure for well control and must be non-damaging to the reservoir to prevent loss of productivity.
Historically, clear brines have been used for both functions. This is to obviate the chances of solids settling with the potential of:
Loss of hydrostatic pressure Plugging of equipment Plugging of and damage to formation permeability
However, the assumption that clean brines fulfil these objectives and fluids containing solids do not is misconstrued. At higher brine densities, corrosiveness, formation incompatibility, associated HSE issues and costs may mitigate against their use.
For instance, some bromide brines are naturally corrosive and require treatment with corrosion inhibitors to be rendered non-corrosive. Such inhibitors may be damaging to the formation by altering wettability or relative permeability. There are also HSE issues attached to the use of these brines.
This paper describes the formulation and application of fluids using microfine particles to produce fit-for-purpose packer and completion fluids, which minimise sag, corrosion & formation impairment, whilst maintaining hydrostatic pressure and well control.
Actual field work done using the microfine weighting agents, manganese tetraoxide with PSD's of ~1 micron D50 have been shown to provide packer & completion fluids, which meet the requirements described above.
HARADH–III: Industry's Largest Field Development Using Maximum–Reservoir–Contact Wells, Smart Well Completions and I-field Concept
Authors: Al-Kaabi Abdulaziz O. , Al-Afaleg Nabeel I. , Pham Tony , Al-Muallem Ali S. , Al-Bani Fahad A. , Hart Richard G. , Hembling Drew E. 
Published: December 2007

Abstract
The development of Haradh-III in the Southernmost area of Ghawar represents a major shift in paradigm in terms of the combination of the technologies. The field development combines four main technology features which include maximum reservoir contact (MRC) wells, smart completions, extensive use of real-time geosteering and I-field initiatives.
This paper describes the motivation, implementation, and post-production evaluation of this unique field development. In the case of Haradh-III, field development with smart MRC wells delays water encroachment, improves flood front conformance and recovery, lowers water production and long term development and operating costs. Bottom water encroachment into the wellbore is mitigated as down-hole Internal Control Valves (ICV), as part of the smart completion, are adjusted. This in turn lengthens the life of the well, allows sweep and recovery to take place in the reservoir below the horizontal wellbores through the most effective sweep process: the replacement mechanism by gravity. The objectives of the development are accomplished utilizing a reduced number of wells, minimizing the accompanying infrastructure therefore lowering the capital expenditure while reducing the operating cost by maintaining, on a long-term basis, a low-water producing system, all occurring in real-time and within the I-field environment.
Scale Control in Chalk Reservoirs: The Challenge of Understanding the Impact of Reservoir Processes and Optimizing Scale Management by Chemical Placement and Retention—From the Laboratory to the Field
Authors: Jordan M. M. , Mackay E. J. 
Published: December 2007

Abstract
The scale control challenges for a large North Sea carbonate reservoir are reviewed in this paper. Field data from a reservoir where the process of scale ion stripping between the seawater injection well and production wells is known to occur is studied in detail to identify if it is possible to predict the impact it has on scale management. Injection water sulphate ions are shown to break through eventually, but the seawater fraction at which this occurs varies between different wells. The impact of the various possible driving mechanisms, and the extent to which matrix and fracture flow contribute to the process, are described. The discussion is generalised to findings applicable to other carbonate systems.
The mechanisms of scale inhibitor retention when phosphonate, polymer, and vinyl sulphonate co-polymer inhibitor squeeze treatments are applied in this carbonate reservoir are outlined. Chemical placement represents the most significant technical challenge when performing scale squeeze treatments into fractured chalk reservoirs. Examples from over 50 field treatments applied in the reservoir, where both phosphonate and vinyl sulphonate polymer chemicals have been deployed, are used to illustrate the difference in chemical retention observed in laboratory evaluations. The laboratory studies demonstrated a clear potential for significant extension in treatment lifetime by changing from a phosphonate to a vinyl sulphonate co-polymer-based scale inhibitor. The selection and qualification of chemical placement systems for deployment of inhibitors in fractured carbonate reservoirs are also outlined.
A key factor in the success of such treatments is an understanding of chemical placement and the effectiveness of the treatment chemicals. Evaluation of residual chemical concentration or scaling ion chemistry has long been used in monitoring programs, and more recently probes have been developed which increase the rate of evaluation/interpretation. All these methods prove that the chemical is present in the brine when sampled, or that scale formation is not occurring at the point of brine analysis. This paper outlines the experimental methods developed to evaluate the suspended solids collected from the produced brine by environmental scanning electron microscope (ESEM) and the associated brine chemistry to evaluate the scale risk within the produced fluids. The combination of these methods has improved the integrated scale management program in terms of evaluating scale squeeze placement effectiveness and squeeze lifetimes, and provide the confidence the extend the period between scale squeeze treatments, and in some cases stop treatment were brine analysis alone would have suggested further scale squeeze applications.
The Optimization of Gas/ Steam Injection Using Numerical Simulation
Authors: Moussine Kamil , Ibragimov Nail , Khisamov Rais 
Published: December 2007

Abstract
Simultaneous injection of heated exhaust gas (mainly CO2 and N2) and steam is one of EOR methods used in Russia for heavy oil recovery. In this case the energy released by gas-steam generator is used more efficiently compared to pure steam injection. Another benefit of using this EOR method is an additional reduction of the oil viscosity caused by exhaust gases solution in oil. This technology is particularly efficient when used for the small reservoirs being developed by a single well.
Practical implementation of this technology is not always successful. One of the main reasons of failure is that parameters of the injected gas-steam mixture are far from being optimal.
This study presents results of numerical simulation of the gas-steam injection process, so called huff-and-puff injection. The aim of the modeling was to estimate an influence of reservoir geometry and heterogeneity as well as huff-and-puff injection parameters on oil recovery factor. The reservoir's and oil properties were typical for Volga-Ural oil province of Russia. The radial geometry was used in numerical simulation with model radius equal to 400 meters. The main results of this study can be summarized as follows: heavy oil reservoir development based on primary depletion is not profitable; EOR methods are needed;efficiency of the huff-and-puff gas-steam injection increases with oil column thickness increasethere is optimal time for well being shut-in after gas-steam injection, this time is dependant on volume of injected energy;the reservoir heterogeneity plays significant role in thermal oil recovery process.
Estimating Optimum Well Spacing in a Middle East Onshore Oil Field Using a Genetic–Algorithm–Optimization Approach
Authors: Tabatabaei Nejad S. A. , Aleagha A. V. , Salari S. 
Published: December 2007

AbstractIn developing phase of a hydrocarbon reservoir and planning for drilling the production wells, it is necessary to drill these wells in an appropriate spacing to achieve maximum economic revenues, during reservoir life span. Traditionally, the optimum well spacing has been determined graphically from a plot of economic return versus spacing among the wells. This paper derives an equation to solve this problem directly without the plot and presents an illustrative example for its application in a recent developed Iranian onshore oil field. Then we optimize achieved function using a genetic algorithm (GA) approach with an initial random population with 20 chromosomes and 100 generation number as main optimization engine in order to finding optimum well spacing versus maximum project NPV. Our procedure show a well-matched results with figures that calculated by project contractor achieving from a trial and error process during defining the field developing scenarios.