bluuebunny/crossref_metadata_2025_split huggingface dataset:
Water Coning Model for Horizontal Wells in High Mobility Reservoir, West Kuwait
Authors: Al-Enezi K. , Das O. P. , Aslam M. , Bahuguna R. , Latif A. 
Published: July 2010

Abstract
Water coning is a serious problem in horizontal wells in Burgan reservoir of Minagish field located in West Kuwait. The reservoir consists of massive channel sands with active bottom aquifer and having very high permeability in the order of few Darcy. The reservoir contains medium quality crude having viscosity of about 30 cp with mobility ratio of 30 to 40. The localized increase in drawdown at sand-face due to high liquid production rate results in early water breakthrough in most of the horizontal wells, even with high stand off from OWC (Oil Water Contact). After water breakthrough the water cut in the wells starts increasing strictly, resulting in by passed oil region below horizontal well. As producing water-oil ratio starts increasing, the operating cost of the well and oil production cost starts rising significantly. In one of the horizontal well of Burgan reservoir, the water cut increased to 90% over a very short period of production and the water cone could not subside even after the well was shut-in for almost three years, confirmed by running the water saturation logs in the subject well as well as in the nearby offset wells. The water saturation logs clearly indicates the oil water interface and the extent of water coning.
The paper covers an analytical model developed for horizontal well to predict the critical drawdown, critical production rate, extent of water coning, time for water breakthrough and shut-in time required to subside the cone for very high mobility Burgan reservoir. The predicted results are in agreement with the actual well performance and production logging results.
The detailed coning study and model presented in this paper have assisted in planning the advanced completion techniques like Inflow Control Device (ICD) and intelligent multilateral wells with ICD, ICV (Inflow Control Valve) completions to address the severe water coning problems. This allows uniform depletion of reservoir below the horizontal wells for facilitating the steady water-oil interface upward movement below the wellbore. Also the horizontal wells will be placed at optimum distance from the OWC to maximize oil recovery and minimizing the risk of by passed oil.
In Situ Upgrading Extra-heavy Oil by Catalytic Aquathermolysis Treatment Using a New Catalyst based Anamphiphilic Molybdenum Chelate
Authors: Wu Chuan , Lei Guanglun , Yao Chuanjin , Jia Xiaofei 
Published: July 2010

Abstract
The aquathermolysis of Shengli extra-heavy oil during steam stimulation was studied by using anamphiphilic molybdenum chelate-aromatic sulfonic iron as catalyst for the reaction in this papers. The laboratory experiment shows that the viscosity reduction ratio of heavy oil is over 97.15% at 200°C, 24 hr, 0.2 % catalyst solution. The viscosity of upgraded heavy oil is changed from 524.5Pa·s to 14.95mPa·s at 50°C. The chemical and physical properties of heavy oil both before and after reaction were studied by using Fourier transform infrared (FT-IR) spectroscopy, gas chromatography/mass spectrometry (GC-MS), elemental analysis (EL). The percentage of saturate aromatic and H/C increased, and resin, asphalt and S, O, N decreased after the aquathermolysis. The changes of the composition and structure of the heavy oil can lead to the viscosity reduction and improve the quality of heavy oil. It has shown that the mechanism of aquahtermolysis is discussed further. We found the new mechanism of catalyst not only broken C-S bond, but also broken C-O and C-N bonds, and accelerated the reaction of aquathermolysis. The results are very useful for the popularization and application of the new technology for the insitu upgrading of heavy oil by aquathermolysis.
Minimizing Wellbore Damage in a Sandstone Reservoir Using Effective Mud Management Practices
Authors: Mohamed Monir , Rabaa Ali S. , Phillips James E. , Al-Ammari Saleh M. 
Published: July 2010

Abstract
Inducing formation damage in sandstone reservoirs through poor drilling fluids management can negatively affect well productivity. A detailed mud management plan that addresses fluid design and particle size monitoring can help minimize formation damage and improve well productivity. This was demonstrated successfully on 26 wells where the operator implemented an engineered oil-based drill-in fluid (DIF) and a particle size distribution (PSD) analyzer in the field while drilling the reservoir.
The oil-based DIF was formulated with a 70/30 oil/water ratio (OWR) and then treated with a sized calcium carbonate bridging agent to minimize spurt and total fluid loss. The PSD analyzer was used to continuously monitor and maintain optimal PSD values in the DIF. In addition, core samples were examined using a scanning electron microscope (SEM) to determine an average pore size value.
The bridging agent treatment was engineered to help minimize formation damage that results from the invasion of fines, or colloidal solids. Overbalance pressures were also minimized to avoid the risk of differential sticking. The reservoir section was drilled with controlled rates of penetration.
To achieve better bridging results, D90, D50 and D10 particle size distributions were maintained in the programmed range throughout the entire reservoir section. Upon reaching total depth (TD), the bottomhole assembly (BHA) was changed to a reaming assembly and the entire open-hole section was reamed to TD.
After the open hole was deemed in good condition, the well was displaced to a solids-free invert emulsion mud with the same density as the DIF.
A total of 26 wells have been successfully drilled and completed with sand screens using this mud management plan. Testing results indicated minimum skin damage and good stable production rates.
Stuck Coiled-Tubing Recovery Utilizing Surface Equipment and Methods
Authors: Gonzalez O. , Bernat B. 
Published: July 2010

Abstract
Coil Tubing technology grew as an off-shoot of the military needs during World War II. One such need was the requirement to spool continuous lengths of flexible pipeline across the English Channel, and the other post WWII need was to spool out long lengths of communication antenna from submerged submarines. These early advancements laid the ground work for other industries to capitalize on.
It didn't take long for oilfield engineers to figure out the advantages of a continous tubing string for drilling and for working over wells. The need to ‘inject’ coil into a well bore under pressure has resulted in numerous designs, but they all have the basic components of the Injector Head with Guide Arch, Stripper, and a Quad BOP Stack.
As with all oilfield tubulars, the eventuality of having the pipe stuck due to unforeseen circumstances created a satellite industry in removing such stuck tubulars. Many downhole fishing tools have been borrowed from their larger threaded cousins, i.e. tubing, drillpipe and casing strings.
This paper briefly reviews the current techniques of extracting stuck coil tubing strings using downhole intervention, and presents a 12 year old process of surface intervention only, using Surface Resonant Vibratory Energy. Rig up procedures and case histories of this surface technique will be presented along with some engineering theory of the underlying acoustic principles of pipe extraction.
When Should We Run Production Logging Tool?
Authors: Jongkittinarukorn Kittiphong , Kitcharoen Tanyawadee 
Published: July 2010

Abstract
Geology in Gulf of Thailand (GOT) is complicated because of fluvial deposition and multi-stacked reservoirs. The number of sands per well is ranging from three to more than twenty. Under logistic constraints and complex geology, commingled completion strategy is applied to produce these many small gas-condensate reservoirs. Most wells are on primary production without artificial lift. Therefore, water production can cause wells to load up and stop flowing. The gas well loading phenomenon is one of the serious problems that destroy value through production and reserves loss.
To reduce water production, we need to locate the water-producing sand(s) and perform water shut-off (WSO) job(s). Successful water source identification and WSO jobs require good production logging (PL) data. Well condition significantly affects the quality of PL data and WSO decision. On one hand, running PL too late, with high water-gas ratio (WGR), obviously yields insufficient time for WSO action before liquid loading. On the other hand, running PL too early, with low WGR, yields no WSO action. Because of low WGR, it is difficult to clearly identify which sand is the main water source. However, the optimum time for running PLs could not be determined by the available analytical tools.
This study uses a statistical approach, reviewing more than 350 PLs for both oil and gas wells in the GOT. Binary Logistic models are created for prediction of the probability of success (POS) to detect water entry. Based on the well conditions, the optimum time for running memory production logging tools (MPLT) can be estimated with the models. This study found that gas rate, oil rate, water rate, and number of perforated sands significantly affect the POS. Through wellwork prioritization, these models can optimize resource allocation by running MPLT at the right well conditions.
The Effects of Barium Sulphate Saturation Ratio, Calcium and Magnesium on the Inhibition Efficiency: I Phosphonate Scale Inhibitors
Authors: Shaw S. S. , Sorbie K. S. , Boak L. S. 
Published: July 2010

Abstract
Phosphonate scale inhibitors (SIs) are commonly applied for barite scale prevention in oilfields. Their inhibition efficiency (IE) is affected by the barium sulphate saturation ratio (SR) of the brine mix as well as in the presence of divalent cations, Ca2+ and Mg2+. What is less well known is that the precise balance between these factors (SR and Ca2+/Mg2+) can vary significantly for different phosphonate species. This paper presents novel IE experimental results for phosphonate scale inhibitors DETPMP and HMTPMP (pentaphosphonates), OMTHP (hexaphosphonate) and HMDP (tetraphosphonate). Minimum Inhibitor Concentration (MIC) levels for each SI are established using a wide range of brine mixing ratios which changes (i) barite saturation ratio and precipitate mass; (ii) molar ratio of Ca/Mg and (iii) the ionic strength in the brine mix.
The phosphonate SIs were categorised into two types based on their IE/MIC behaviour: Type 1 (e.g. DETPMP and OMTHP) are affected principally by SR and are rather less sensitive to Ca2+/Mg2+and Type 2 (e.g. HMTPMP and HMDP) which are severely affected by brine Ca2+/Mg2+ as well as SR. To demonstrate these effects conclusively, a series of IE experiments are presented with varying brine mix but at a fixed Ca2+/Mg2+ ratio in which the MIC level using both types of phosphonate SI then correlates very well with the barite saturation ratio. In addition, we find the MICs of both types of SI are much lower in the fixed (higher Ca2+/Mg2+ratio) case experiments, compared to the base case – due to the beneficial effect of higher [Ca2+]. The effects observed are important for field application of phosphonate SIs since they show how the various species are sensitive to the changing scaling problem as the %SW increases, in terms of both SR and Ca2+/Mg2+ratio.
The Performance Characteristics of Cr3+ Polymer Gel and Its Application Analysis in Bohai Oilfield
Authors: Lu X. G. , Wang W. , Wang R. J. , Liu Y. G. , Shan J. Ch. 
Published: July 2010

Abstract
The molecular configuration dimension and the flow performance of Cr3+ polymer gel which was formed from partially hydrolyzed polyacrylamide (HPAM) and Cr3+ were studied by making use of the viscosity measurement, core flow performance test and dynamic light scattering (DLS).
The results showed that Cr3+ polymer gels with different molecular structures could be prepared by changing the gelling conditions such as electrolyte concentration of solvent water, Cr3+ or polymer concentration and so on. If electrolyte concentration of solvent water was high while polymer and Cr3+ concentration were low, the cross-linking reaction between polymer molecule and Cr3+ mainly took place among different chains of the same polymer molecule forming Cr3+ polymer gel with the intra-molecular cross-linking structure. Compared with polymer solution at the same concentration, apparent viscosity of intra-molecular cross-linking Cr3+ polymer gel remained almost unchangeable, but the resistance coefficient and the residual resistance coefficient were much higher while the residual resistance coefficient was higher than the resistance coefficient. Moreover, the molecular configuration dimension (Dh) of the gel was only a little bigger than that of polymer solution so that it still had a favorable compatibility with the rock pore of oil reservoir.
As seen from the statistics of the pilot test, Cr3+ polymer gel presented outstanding profile modification as well as oil displacement. The channeling of high permeability zones of oil reservoir were blocked so well, the injection pressure became so high, and thereby there has already being a great effect on enhancing oil recovery and decreasing water cut.
An Integrated Application of Reducing Uncertainties for 3D Pore Pressure Prediction: A Case Study
Authors: Fan Honghai , Zhi Ye , Ji Rongyi 
Published: July 2010

Abstract
Pore pressure is an important geologic parameter in drilling operation, once it influences the definition of mud weight, casing design, drilling cost evaluation, etc. Inaccurate estimates of pore pressure can lead to high costs and unsafe conditions. Basically, the current prediction methods of pore pressure are based on one-dimensional, and can not provide horizontal and the spatial distribution of formation pressure information. While the existing three-dimensional (3D) pore pressure prediction method is not mature enough, and prediction accuracy is not high.
This paper presents an integrated application of reducing uncertainties in order to improve the accuracy of 3D pore pressure prediction and also to give a case study. Firstly, we transform the seismic interval velocities inverted from a 3D calibrated seismic migration volume to pore pressure with an initial pore pressure prediction model, this prediction results clearly have a large range and low accuracy. Next, used seismic data in conjunction with well logging data, mud weight and measured pressure, we can modify and improve model parameters of the initial prediction model. At last, the 3D pore pressure data volume is re-calculated by this new 3D prediction model. This integrated application has been used to improve the pressure prediction results of a petroleum province in the Western of China, and we can get a high precision 3D pore pressure data with this method through analysis and compare.
Fulmar Sandstones, Correcting Some Received Wisdoms in the Greater Kittiwake Area (North Sea)
Authors: Coghlan G. , McRae G. 
Published: July 2010

Abstract
The Fulmar Formation Sandstones in the Central North Sea are a prolific oil and gas play with new developments still being added 35 years after the first discovery in 1975. Typically interpreted as shallow marine, shore-face sands, there is a pronounced halokinetic element to the distribution of the hydrocarbon accumulations.
The Greater Kittiwake Area, GKA, covers several license blocks in quadrant 21. The Kittiwake oil field was developed standalone with a small platform and tanker export with first production in 1990. A satellite field, Mallard, was added in 1998. The fields and surrounding acreage, including several small Fulmar discoveries, were acquired from the original owners in 2003.
Since then Mallard was redeveloped leading to a ten-fold increase in production. Also three Fulmar discoveries were tied-back – Gadwall, Goosander and Grouse. In addition to the production capacity boost, production uptimes were improved and there was sufficient confidence to install an export pipeline. Other satellite discoveries are under consideration as future tie-backs.
There have been surprises along this journey that contradicted pre-development assumptions about Fulmar sandstone reservoirs. A key one relates to the unanticipated strength of the aquifer response in the ‘new’ satellite developments. This flew in the face of received wisdom about Fulmar reservoirs typically not experiencing aquifer drive. It challenges regional expectations about the prerequisite aquifer distribution and size for aquifer drive, also about levels of diagenesis in the water-leg.
In GKA, the Fulmar formation often thins off-structure below seismic resolution - coupled with regional depositional models this is difficult to square with field data from which aquifer drive can be inferred unambiguously. Anticipating where aquifer influx will likely be experienced is important for future developments, as pressure maintenance by waterflood is otherwise required for such tie-backs bringing higher costs and complexity.
Downhole Disposal of Black Water – Engineering Re-design
Authors: Deng Lianjun , Wang Parker , Chen Kaijun 
Published: July 2010

Abstract
Traditional treatment of black water on offshore facility is grind, disinfect and discharge overboard. But in some environmentally sensitive seas, offshore discharge of black water from the facilities was limited by the regulatory agencies. Therefore the black water effluent from the living quarters on the facilities can be disposed of in a safe, environmentally prudent and economic manner. To achieve this goal, process must be re-designed in terms of treatment capacity, effluent quality, particle size and re-injection process. There are always some other wastes been re-injected such as cuttings, waste mud, packer fluid etc. Principles are given in this paper on process re-design to guide a successful and effective system upgrading.
Increasing the Service Lifetime of Coated Titanium Anodes
Authors: Hoseinieh S. M. , Ashrafizadeh F. , Maddahi M. H. 
Published: July 2010

Abstract
Mixed metal oxide coated titanium anodes have been applied widely to cathodic protection as impressed current anodes in the oil/gas industry and for chlorine production in chlor-alkali industry. The anodic stability and service life are the main concerns in these applications. It has been known that oxide anodes have a very limited service life under operating conditions because of the severe corrosion of active component in the oxide mixture such as RuO2, leading to final deactivation of the anode.
To increase the effective life of anodes, this study considered alternative anode materials and concluded that the anode life is improved by doping the anode coating with IrO2. Therefore, corrosion behaviour of a RuO2-IrO2-TiO2/Ti oxide anode was investigated during an accelerated life test (ALT) in NaCl solution by use of cyclic voltammetry (CV), electrochemical impedance spectroscopy (EIS) and SEM/EDS. The service lifetime of IrO2 doped oxide coating is compared with RuO2/Ti and RuO2-TiO2/Ti anodes and a systematic evaluation is presented.
The life test indicated that the improved oxide anode has a long lifetime and appropriate activity. It was concluded that RuO2-IrO2- TiO2/Ti anodes last up to ten times longer than Ir-free anodes. An impedance model is then developed for this corrosion system and the model simulation compared to the experimental data. The model is shown to be in reasonable agreement with the experimental data. A comprehensive deactivation mechanism of titanium anodes has been proposed by the growth of an insulating TiO2 layer at coating-substrate interface.
The results presented in this paper are very promising and reveal that RuO2-IrO2-TiO2/Ti anode has a good potential to be used as mixed metal oxide anode in oil/gas and petrochemical industries.
A New Approach to Deformable Fractured Reservoir Characterization: Case Study of the Ekofisk Field
Authors: Shchipanov A. A. , Kollbotn L. , Surguchev L. M. , Thomas K. O. 
Published: July 2010

Abstract
Production from a fractured reservoir is generally governed by the fracture network conductivity, which may be altered by changes in reservoir pressure. A new approach to naturally fractured reservoir description accounts for the variation in the fracture properties caused by the effective stress change. The basis of the proposed approach is a compressible discrete fracture network (CDFN) model with stress dependent fracture aperture and hence porosity and permeability. The new approach allowed us to develop a workflow to evaluate the stress dependent fracture properties. This workflow includes inverse and direct problem solutions. The inverse problem consists of interpretation of pressure transient well tests and production history integrating geomechanical effects. The results of core analyses, production logging and wellbore imaging provide important information for the CDFN characterization. The direct problem consists of numerical flow simulation focused on calibration of the obtained fracture properties to match well test data. Using the workflow, one can determine stress or pressure dependent fracture parameters to be used in single and dual porosity reservoir simulations.
Using available field data, the proposed approach allowed us to improve characterization of the Ekofisk fracture network. The seafloor subsidence and chalk compaction observed at Ekofisk have initiated extensive studies of the reservoir geomechanics. The geomechanical effects were integrated in the reservoir characterization using the developed workflow. A decrease in well productivity and fracture conductivity due to pressure decline was obtained from the pressure transient and production analyses. This allowed us to describe the dynamic behavior of the fracture permeability and porosity. These fracture properties were then used in reservoir simulation. The simulation results have given evidence that dynamic reservoir behavior has an effect on multiphase flow comparable to well placement and relative permeability effects.
A New Computer Assisted History Matching Method
Authors: Abrahema Fathe A. , Heinemann Zoltán E. , Mittermeir Georg M. 
Published: July 2010

Abstract
This work presents an automatic history matching approach called Target Pressure and Phase Method or TPPM. In a conventional history matching approach the model wells are fixed and one seeks for a reservoir model, in which the historical rates, well pressures, WC and GOR are provided over the entire time. The presented method does the opposite. The reservoir model is given and the computer automatically places wells, which can do what they should do – namely correctly reproduce the measured data. These pseudo wells are perhaps at different locations and connect to other layers as the real wells but the overall material transfer will be correct for the entire time period. If such wells cannot be placed, then the static model is fundamentally wrong and must be replaced. Stochastic realisations can be screened at this level already. Supplementary, water is added into the model boundaries, ensuring that the average pressure in any chosen region closely follows the historical pressure. After the global match has succeeded, the pseudo wells are shifted towards the real ones and the reservoir and perforation properties will be tuned step by step, partly automatically partly manually. The history match is completed after all pseudo wells have been replaced by the model wells.
The method is implemented in PRS, a fully developed not commercial user friendly tool. It can be used standalone but also as a pre-processor to ECLIPSEc. The tool needs some command lines added to the ECLIPSE input only. PRS writes out a modified SCHEDULE file containing the actual settings of the pseudo wells and the parameters for the Fetkovich and Carter-Tracy analytical aquifer models (replacing the boundary injections) for the next ECLIPSE run. The paper describes the concept, the corresponding algorithms. The applicability is demonstrated on a small scale example and additionally with a successful field case.