bluuebunny/crossref_metadata_2025_split huggingface dataset:
Multiscale Modeling of Carbonate Acidizing Using Continuous Time Random Walk Approach
Authors: Kang Kang , Abdelfatah Elsayed , Pournik Maysam , Shiau Bor Jier , Harwell Jeffrey 
Published: October 2017

Abstract
Matrix acidizing is an extensively used stimulation technique to improve oil recovery in carbonate reservoirs. The interplay between transport and reaction of acid is highly affected by heterogeneity at different scales. The existing experiments and models have difficulties to capture effect of heterogeneities across pore-scale, core-scale and field-scale. The objective of this paper is to provide an efficient multiscale model using continuous time random walk approach to predict acidizing behavior at macroscopic scale considering the effect of microscopic scale heterogeneity.
Instead of solving traditional advection-diffusion-reaction equation (ADRE), the continuous time random walk (CTRW) incorporating with particle tracking (PT) is a probabilistic approach to model fluid transport in heterogenous porous media. Here, the CTRW-PT describes motion of acid particles as random spatial and temporal increments at pore scale which follow independent distributions whose characteristic probability density functions (PDF) are derived. The transport of acid particles is simulated by particle tracking first and chemical reaction is included using the midflight approach. CTRW-PT simulation yields macroscopic plume of acid which creates wormholes at core scale. The core-scale wormhole propagation at different injection rate and concentration agrees qualitatively with the experimental results. Nevertheless, CTRW-PT also demonstrates the effect of heterogeneity that may increase the minimum pore volume to breakthrough. Using CTRW-PT approach is more efficient than solving ADRE in large-scale modeling.
The utilization of CTRW-PT approach on acidizing modeling captures the wormhole propagation of hydrochloric acid in limestone cores. This probabilistic and stochastic approach provides an efficient way to model carbonate acidizing and one can consolidate the lab-scale understanding with field prediction to optimize the acidizing treatment design.
Core Characterization and Numerical Flow Simulation in Representative Rock Types of the Raudhatain Field in Kuwait
Authors: Dernaika Moustafa R , Sahib Mohammad Raffi , Gonzalez David , Mansour Bashar , Al Jallad Osama , Koronfol Safouh , Sinclair Gary , Kayali Anas 
Published: October 2017

AbstractDetailed core characterization is often overlooked in the sampling process for core analysis measurements. Random core sampling is usually performed and the selected plugs are not associated with rock types or the reservoir heterogeneity. The objective of this study is to obtain representative samples for direct simulation of petrophysical and fluid flow properties in complex rock types.A robust sampling strategy was followed in reservoir cores from two successive heterogeneous carbonate and siliciclastic formations in the Raudhatain field in Kuwait. The sample selection criteria were based on statistical distribution of litho-types in the cores to ensure optimum characterization of the main reservoir units. The litho-types were identified based on porosity and mineralogy variations along the core lengths utilizing advanced dual-energy X-ray CT scanning. High resolution micro-CT imaging and subsequent segmentation provided 3D representation of the pore space and geometric fabric of the core samples. Primary drainage and imbibition processes were simulated in numerical experiments using a pore-scale simulator by the Lattice Boltzmann Method. Capillary pressure (Pc) and relative permeability (Kr) curves together with water and oil distributions were investigated for complex geometries by the different rock types.The dual energy CT density was compared with wireline log and provided accurate calibrations to the downhole logs. The different rock types gave distinct capillary and flow properties that can be linked to the rock structure and pore type of the samples. The Lattice Boltzmann based pore-level fluid calculations provided realistic fluid distributions in the 3D rock volume, which are consistent with pore-scale physical phenomena.This characterization method by the dual energy CT eliminates sampling bias and allows for each cored litho-type to be equally represented in the plugs acquired for subsequent petrophysical and fluid flow analyses. It also provides accurate calibration tool for downhole logs. The digital analysis gave reliable SCAL data with improved understanding of the pore-level events and proved its effectiveness in providing advanced interpretations at multiple scales in relatively short timeframes.
Stimulation of High Temperature Carbonate Reservoirs Using Seawater and GLDA Chelating Agents: Reaction Kinetics Comparative Study
Authors: Abdelgawad K. Z. , Mahmoud M. A. , Elkatatny S. M. 
Published: October 2017

Abstract
Hydrochloric acid (HCl) as a stimulation fluid of deep oil and gas carbonate reservoirs is very common practice in the industry. Using HCl acid during matrix acid treatment in carbonate acidizing has the limitations of; rapid tubulars corrosion, formation face dissolution due to fast uncontrolled reaction rate especially at high temperature reservoirs and low injection rates, and induced formation damage due to sludge formation in presence of crude oil with high asphaltene content. There is also a difficulty of using HCl in stimulating multilateral and horizontal wells due to its fast reaction with the reservoir rock. With the intensive care given to the environment in the 21 century, chelating agents were introduced as alternatives to HCl to alleviate the problems associated with HCl. GLDA (Glutamic acid diacetic acid) chelating agent was used previously to stimulate carbonate reservoirs at high pressure and high temperature (HPHT) conditions. GLDA was prepared in fresh water to stimulate these reservoirs.
In this paper, the effect of dilution using seawater on the reaction kinetics of low pH GLDA (3.8 pH) with different carbonate rocks under HPHT conditions was investigated using the rotating disk apparatus (RDA). The reaction experiments of GLDA solution with carbonate rocks in both fresh (GLDA/DI) and seawater (GLDA/SW) were carried out at the same conditions. Indiana limestone and Austin chalk carbonate rock samples were used to investigate the effect of rock facie on the reaction.
The reaction regime of GLDA chelating agent with calcite is identified to be mass transfer limited in both seawater and fresh water. Also the overall reaction rate and calculated diffusion coefficient showed a high dependency in the temperature. At 200°F and 1000 psi the diffusion coefficient calculated for the reaction of GLDA/SW with Austin chalk is an order of magnitude higher than the reaction of the same fluid with Indian limestone.
The reported diffusion coefficients can be used to simulate for the optimum injection rate required for stimulating high temperature carbonate formation. Highlighting the effect of porosity facies in the acid reaction with carbonate rock will lead to better understanding of the overall reaction of stimulation fluids with carbonate rocks of the same lithology but different porosity facies.
Protecting Offshore Oil Terminals from Wave Action using Innovative Floating Breakwaters
Authors: Neelamani S.. 
Published: October 2017

Abstract
Loading into or unloading of oil and gas from very large crude carrier (VLCC) normally happens in the open sea, since water depth of about 18 to 22 m are needed for such vessels, and ports to accommodate such vessels are not available everywhere. For example, in Kuwait, oil loading terminal is located at a distance of 12 km from the coast at a mean water depth of 20 m. The waves at this location are predominantly approaching the mooring vessels from northwest and southwest and are moderate most of time, with wave heights less than 1.0 m for more than 85% of the time in a year. Wave height exceeds more than 2.0 m for up to 15 days in a year. During such wave climate, oil loading operation is risky. Stopping one day of oil loading operation means revenue loss of about 100 million US $ to the country. Hence it is required to reduce the wave climate around the loading terminal. Construction of any fixed wave barrier like offshore rubble mound breakwater will be out of question for few reasons. It will be prohibitively expensive (for example, each m run of the offshore breakwater will consume more than 1000 m3 of stones, which will cost about 20,000 KD/m run and hence for say 1000 m length of an offshore rubble mound breakwater, it will cost about 20 million KD); presence of such fixed structure is a navigational hazard; reorientation is not possible when the incident wave direction changes significantly from one season to another season. Kuwait Institute for Scientific Research has carried out studies on Floating breakwaters (FBW). The wave transmission and mooring forces were measured for a wide range of wave conditions. Studies were carried out on conventional pontoon breakwaters and then on FBWs with different number of skirt walls fixed at the keel of the pontoon FBWs. Wave transmission is found to be reduced significantly (to the order of 25% to 60%) by adding three or five skirt walls.
However, mooring forces are increasing to an extent of 20% to 30%. A basic design and cost analysis is carried out for the floating breakwater and is compared with the rubble mound offshore breakwater. For the floating breakwater with skirt walls, the volume of material required is less than 10% of the material for rubble mound breakwater and cost saving to the tune of 50% to 70% is possible. The cost for construction and installation of such floating breakwater for 1 km length will be about 3 million KD, which is about 10% of the earnings/day of export operation. The results of this study can be used for cost effective design of floating wave barriers and loading of crude oil can be done for the whole year with less risk induced by the wave actions.
Production Optimization from a Short Lateral Horizontal Well in a Braided Fluvial Deposition System: A Case Study from Greater Burgan Field, Kuwait.
Authors: Naik Vinay , Bahman Hussain , Al-Haddad Saud , Ali Farida 
Published: October 2017

Abstract
Greater Burgan Field has been producing from more than 60 years and brings many challenges. The majority of the production comes from Wara and Burgan reservoirs. The Cretaceous Burgan sands are divided into five main reservoirs; two reservoirs consist of stacked, massive fluvial channels, while remaining three mostly consist of delta distributary channels and bays in a tidal delta setting grading to shallow marine. BGSM reservoir is one of the five reservoirs of Burgan reservoirs, which is deposited mostly by braided fluvial systems and is one of the major producers of the Greater Burgan Field. Some of the areas where remaining oil column of BGSM reservoir has become less; the optimization of production has been a challenge. This is due to the fact that due to less oil column; the production shortly becomes water wet and well ceased to produce by vertical or deviated well.
To produce from BGSM reservoir, one horizontal well was drilled in a low potential area for the first time where nearby wells were water wet with short self-flow production life. The planning of this well required to complete the well on the top of reservoir with short later section. To assess the potential of this area, a pilot well drilled and which confirmed around 35 ft. of remaining oil. Based on this horizontal well was planned and drilled with a short lateral. Geo-steering services was used throughout the landing and lateral sections while drilling. The Open Hole Horizontal section completed with 5 1/2″ completion equipment with 26 ICD zones.
The well was drilled successfully with a short lateral of around 650ft. and was completed on top of BGSM reservoir with 5 ½" Advance ICD in open condition with an option to produce in future in BGSU2 reservoir. The well is producing with sustained production of 1200 blpd with 12% water cut for the last one year. The well started to flow to the gathering center with high wellhead pressure.
For the first time horizontal well drilled in a low potential area of BGSM reservoir. The well drilled successfully with an advanced ICD completion. Also for the first time Advanced ICD's where sliding sleeves in BGSU & part of massive BGSM sand were lowered in closed condition (could be opened in future by rig less CTU operation) whereas lowered in Open position in another BGSM Interval which is structurally at higher position and at hill side of the lateral section. The well is producing with sustained production rate and minimum water cut percentage for the last one year. This process will help in future to benefit for all types of horizontal producer wells.
Regional Variations in Water Quality - A Key Factor Influencing Water Injection
Authors: Badusha S.. , Al-Tahou Y.. , Qamber A.. , Al-Jasmi A.. , Juma M. A. 
Published: October 2017

Abstract
Natural dumpflood injection is used for pressure maintenance in a good channel sand holding considerable reserves. The layer is on depletion drive with very weak aquifer support. Natural dumpflood injection was modeled based on success in a similar layer in an adjacent field. Due to the high mud weight used during drilling, the layer is usually damaged. Dumpflooding experience in the analogue field suggests that injection is initiated only after matrix acid stimulation. Therefore, it was not a surprise when the layer did not take in any water initially. However, once the usual stimulation attempts did not achieve the desired results, possible causes and alternates were evaluated.
A comprehensive lab study was designed to assess all the potential problems associated with injection. Fluid-fluid interaction issues like scaling, possible formation of oil-in-water emulsion, fluid-rock interaction such as clay swelling, fine migration related to water incompatibility, all impacting efficiency of water injection on oil mobility and recovery were studied. To simulate every possible field condition all the major water sources were sampled and taken for study. For fluid rock interaction studies, core plugs from the layer was used.
Scale tendency was studied using Jar test and predictions at reservoir conditions were made through ChemScale software. The scaling products from Jar test was analyzed with SEM confirming the results. Routine core analysis was performed to measure porosity and permeability in the coreplugs. XRD was done to understand the mineralogy of the layer. After measuring the baseline permeability, the plugs were subjected to flooding with source waters. One set of coreplugs were fully saturated with target water and flooded with source waters. Flooding was repeated on core plugs saturated with oil at irreducible water saturation until it reached residual oil saturation. An investigation of emulsion formation was conducted between oil and source waters. Study results gave an indication of many potential issues like self scaling tendency of source waters and permeability reduction due to fine migration and scale formation. Out of the many factors, the presence of considerable concentrations of sulphate forming cations was identified as the primary issue to focus on. Sulphate reducing chemicals are being evaluated for injection along with the source water.
Injection water quality is one of the primary factors to consider for effective injection. This is even more crucial in case of dumpflooding, wherein water is sourced from sub-surface. Due to the wide extent of the field and possible diagenesis effect there could be regional variations in water quality. Due diligence needs to be paid to these regional variations in water quality and choose prudently among alternate source water reservoirs.
First Successful Multistage Completion Paves the Way for Optimized Field Development of the Jurassic Formations of North Kuwait
Authors: Ahmed Zamzam , Al-Otaibi Yousef , Bloushi Taha , Fidan Erkan , Sharma Siddhartha , Pradhan San Prasad , Al-Mutairi Mubarak , Al-Failakawi Abdul Aziz , Shaikh Ahmed Karim , Quint Edwin 
Published: October 2017

Abstract
The HPHT, sour, deep, fractured and not so fractured carbonate Jurassic formations within the North Kuwait cluster of fields present extraordinary challenges in driving towards an optimized field development that maximizes liquid recovery and meet the gas production aspirations for the state of Kuwait.
The Middle Marrat reservoir has been developed to date with cased and perforated liner completions across the 500- 700ft pay. However due to the high permeability contrast between the different reservoir flow units, the low permeability zones are typically not contributing. This is further exasperated with the inability to effectively acid stimulate large proportion of the net pay with a single stage bullhead treatment especially when the contrast in permeability between the various flow units is higher than one order of magnitude.
Key to successful reservoir management of the Middle Marrat whilst maximizing well capacity to meet the production aspirations is to implement a completion and stimulation strategy that maximizes flow contribution from as much of the net pay as possible. Single stage bullhead matrix acid stimulation treatments like those executed in the past will only stimulate the top decade of permeability. The current 4-1/2" cemented completion ‘plug and perf’ standard will require intensive well intervention to set and drill out plugs in order to selectively stimulate individual zones.
To develop an alternative completion and stimulation strategy for developing Middle Marrat, the first 4-1/2" multistage ball activated sleeve completion system has been deployed successfully in a Middle Marrat deviated development well. 2 out of 3 stages installed have been acid stimulated and flow tested showing excellent results. The operational experience and learnings acquired from the project have provided the necessary confidence to the organization to deploy the technology in tight gas and unconventional reservoirs within North Kuwait, but also challenge the existing cemented ‘plug & perf’ completion and stimulation approach for the development of the more conventional Middle Marrat reservoirs.
Successful Installation of 1st 15K Multistage Completion System in North Kuwait Gas Well
Authors: Al-Mutairi Abdulaziz , Baqer Hussain Ali , Dhabria Akshaya Kumar , Rook Gert-Jan , Shaik Ahmed Karim , Al-Mutairi Bandar , Hii King-Kai , Hadi A. A. 
Published: October 2017

Abstract
The optimum development of the Deep Carbonate reservoirs in North Kuwait is key to achieve KOC's gas production targets. To optimize (future) production and accessibility of the various Flow Zones within the Target MT formation, KOC has selected a 4.5" mono-bore design to complete the North Kuwait Gas wells. To further improve understanding of production contribution from different flow zones and to enable selective stimulation and effective testing of flow zones, a trial was conducted in a new well to install a 4.5" 15K rated open-hole Multistage Completion (MSC).
The well trajectory was designed with all directional work done before the reservoir section. The deviated reservoir section was drilled successfully to the planned TD. A three stage MSC with a long tail string (for future access to deeper reservoirs) was successfully installed. The bottom and middle stages were successfully stimulated and production tested. Stimulation and testing of the upper stage is planned for the future.
To build on the success of this first trial another candidate well has been identified and a second 15K MSC system is expected to be installed in the second half of 2017.
This paper describes the best practices and the learning in planning and installation of a first successful open-hole MSC in a High Pressure gas well in Kuwait, as well as recommendations for future MSC installations in deep high pressure gas wells with large variations in reservoir caracteristics.
Experimental Evaluation of the Swelling Behavior of Unconventional Shale Formation at and Near the Wellbore in the Presence of Various Drilling Fluid Systems
Authors: Alouhali R. A. , Soliman M. Y. , Emadi H.. , Amanullah M.. 
Published: October 2017

Abstract
No two shale plays are the same. Experimental and field data shows that shale formations act differently when exposed to similar conditions. The instability of shale formation is considered one of the major problems facing drilling operations. Bit balling, cutting dispersion, washouts, and stuck pipes are some of the problems faced when drilling shale formation. Only recently, shale formation became a target for hydrocarbon production. Shale plays are the new frontier for drilling and development. When the oil price was high, it was economical to drill and produce from shale formation. Now that the price of oil is relatively low, drilling and producing from shale formation might not be that lucrative. To reduce the cost of developing shale plays, we need to understand the producing shale geomechanical properties. There have been many studies on conventional shale formation and it has helped reduce potential drilling problems in those formations. However, not all shale formations are the same, and solutions that worked with one will not necessarily work with others. That is why we need to conduct studies focused on producing shale. Two producing shale formations were used in this study they are Marcellus shale and Arabian Peninsula (AP) shale. This study is exploring the difference in swelling behavior between the one side of shale core sample that is in direct contact with fluid with the other side of shale that is not in contact with drilling fluid. This is meant to represent the swelling at the wall of the wellbore and the swelling near the wall of the wellbore. Six samples from Marcellus shale and six samples from AP shale were used in this study. Two samples from each formation were used to collect the mineralogy data using XRD/XRF tests and the remaining four samples were used in the swelling tests. For the swelling tests, the samples were half submerged in various drilling fluids where half of the core sample is inside the fluid and the other half hangs above the fluid level. Strain gauges attached to both side collect the swelling behavior continuously for seven days. Results shows that at low swelling levels the back side of the wellbore (near well bore) shrinks while the wall of the wellbore swells. However, at high swelling rate both the wall of the wellbore and near the well bore increase in size following a similar swelling profile.