bluuebunny/crossref_metadata_2025_split huggingface dataset:
Source Rock Characterization of the Hanifa and Tuwaiq Mountain Formations in the Arabian Basin, Based on Rock-Eval Pyrolysis and the Modified Delta Log R Method
Authors: Alyousuf Taqi , Algharbi Waleed , Algeer Rania , Samsudin Azman 
Published: May 2011

Abstract
The Tuwaiq Mountain and Hanifa formations contain both significant hydrocarbon reservoirs and world-class hydrocarbon source rocks. This paper focuses on the characterization of the source rocks within the formations by integrating core-derived geochemical data and well-log responses. The hydrocarbon source rock potential of these stratigraphic intervals in the Arabian intrashelf basin was evaluated using Rock-Eval pyrolysis and the Delta Log R method. Organic geochemical analyses of core samples for S2, total organic carbon (TOC), and hydrogen and oxygen indices were used to determine the quality of organic matter. Most of the source rocks are thermally mature and contain oil-prone Type-II kerogen. The Delta Log R method was used to obtain calculated TOC values to increase the coverage across the zone of interest (uncored intervals) and laterally at the uncored wells. Level of maturity (LOM) is one of the key required inputs for the Delta Log R method. The LOM was derived from predicted vitrinite reflectance values using heat flow distribution within the entire basin. A comparison of TOC values derived from the Delta Log R method with actual laboratory-measured TOC values from core samples shows a very good agreement. This allows confident application of this technique in calculation of TOC values in wells for which no core samples are available. The TOC and effective thickness fairway maps of the Tuwaiq Mountain and Hanifa source rocks generated from this method offer great insights for defining the source rock characteristics.
Single-Sack Fibrous Pill Treatment for High Fluid Loss Zones
Authors: Darugar Qusai A. , Szabo Joseph J. , Clapper Dennis K. , McGuffey Gary 
Published: May 2011

Abstract
Lost circulation is a leading cause of downtime in drilling operations and is encountered in most drilling jobs. It can result in complete loss of the hole along with costly drilling equipment. To successfully prevent losses of drilling fluid, it is vital to rapidly prepare and place a lost circulation treatment into the loss zone when losses are encountered. A fibrous lost circulation pill has been developed to address common operational concerns that exist with current lost circulation materials and applications. This one-sack product does not require any activators, retarders, set time calculations, or temperature activation. It has been specifically designed for rapid mixing and pumping with minimal equipment.
Laboratory testing has demonstrated the ability of the fibrous pill slurries to rapidly dewater/de-oil and form a sealing plug on both ceramic filter discs and slotted metal discs. Testing also shows that the product forms a sealing plug in depleted sand formations. This pill can easily be weighted using barite to help control hydrostatic pressures. The fibrous product is suitable, and has been tested, with a wide range of fluids including freshwater, brines, and base oils. This product also meets strict environmental requirements for use in both the Gulf of Mexico and Norway. It can be rapidly mixed and pumped on location using standard rig equipment and only requires base fluid, barite and the product. The pill formulation is compatible with all mud systems and is easily removed using standard solids control equipment.
This new approach to control severe losses has been successfully applied in several field tests, which have reflected a variety of lost circulation conditions. A few of these field applications will be discussed in detail.
Utilizing Fiber Optic Enabled Coil Tubing Telemetry in Extended Reach Horizontal Well Mechanical Rigless Water Shut-Off (WSO) Operation (Case Study)
Authors: Shawly Alaa S. , Al-Buali Mohammed H. , Dashash Alaa A. , Haldar Surajit , Olarte Jorge E. , Burov Anton 
Published: May 2011

Abstract
In many fields, high water production can cause adverse effects on the reservoir performance, which can result in production losses. To mitigate this situation, it is crucial to utilize water management to reduce water production, optimize oil production, increase the well life and revive dead wells. One of the options is utilizing a workover rig to isolate the water entry zone by running swellable or inflatable packers. This option is costly and time consuming, taking into consideration the time required to prepare the location for the rig, stripping out and returning back flowline and cleaning wells prior returning to production. To overcome this challenge, it was essential to look for an alternative solution that requires less time and cost. One of those solutions is isolating the water producing zone by rigless water shut-off (WSO), using mechanical isolation. This kind of operation is more challenging for extended reach horizontal wells.
This paper highlights the mechanical rigless WSO method used to mechanically isolate a water contribution zone by utilizing fiber optic enabled coiled tubing (FOECT) telemetry and setting an inflatable packer combined with a capped with cement. This successful WSO treatment positively impacted the overall performance of a dead horizontal oil producer with 4,000 ft of reservoir contact. The WSO resulted in decreasing the water cut from 68% to 0%, and revived the dead well with 10 thousand barrels per day (MBOD) oil gain.
Real-time downhole temperature, pressure (inside and outside the coil tubing) and casing collar locator (CCL) measurements, obtained by FOECT was utilized to get accurate packer setting depth, confirm packer setting and ensure the suitability of cement recipe slurry design. The whole cycle of candidate selection, job design, execution challenges, post job evaluation, lessons learned and the experience gained to optimize the similar future jobs are covered in this paper.
Deviation from Darcy's Flow in Fractured Tight Gas Sand Reservoirs
Authors: Khlaifat Abdelaziz , Qutob Hani , Arastoopour Hamid 
Published: May 2011

Abstract
Unconventional gas resources will significantly affect the future of the energy sector worldwide in the coming years. The importance of non-Darcy flow has been highlighted in the literature in the context of highly productive fractured gas wells. The low gas flow rates from typical tight gas wells contradict this assumption. Neglecting the non-Darcy flow effect in tight reservoirs will lead to an overestimation of production and other misleading facts about tight gas reservoirs behavior. The interpretation of deviation from Darcy's flow through tight sand porous medium is addressed, in this work, by conducting a series of single phase gas flow experiments. The considered porous medium sample was slot-and-solution pore type tight sand collected from the Travis Peak Formation at a depth of 2654 m with permeability in microdarcy range and porosity of 7%. Two gases, nitrogen and helium, were used. Single-phase gas experiments were carried out at different pressure drops and overburden pressures. The experimental results showed that the examined slot-and-solution tight sand porous media is very sensitive to overburden pressure. Pore size distribution measurements, by mercury intrusion porosimetry and sorption isotherm, showed the existence of a wide range of pore size distribution (from 0.4 to 400 nm). The analysis shows that single phase gas flow through tight gas sand particularly at low pressure is of Knudsen diffusion type. Thus, the gas molecules may slip at the wall of the capillary and the Klinkenberg formulation may be the approach to describe the deviation from Darcy's law when the pore size and particle size are almost the same.
An Alternative Approach to Modeling Non-Darcy Flow for Pressure Transient Analysis in Porous and Fractured Reservoirs
Authors: Al-Otaibi Ajab , Wu Yu-Shu 
Published: May 2011

Abstract
Non-Darcy flow is an important factor affecting productivity of gas and high production rate oil wells and the analysis of pressure-transient well tests in porous media. The motivation for this study to investigate, validate and extend the Barree-Conway model (BCM) for pressure-transient analysis of wells involving hydraulic fractures and naturally fractured reservoirs. Numerical models based on finite control-volume method were developed according to not only the Forchheimer equation and, for the first time in the literature, but also the Barree-Conway model specifically for pressure-transient analysis of single-phase fluid flow in porous and fractured reservoirs. The developed numerical models are capable of simulating all near wellbore effects coupled with the non-Darcy flow behavior in porous and fractured reservoirs.
This study shows that the BCM can be applied, similar to the Forchheimer model, to analyzing and interpreting pressure-transient responses of non-Darcy flow in porous and fractured reservoirs. The BCM predicts similar pressure-transient responses of non-Darcy flow as predicted by the Forchheimer model. The parameter of characteristic length among the BCM model parameters is more sensitive than the minimum permeability. The minimum permeability is only sensitive at low values of characteristic length or at extremely high flow rates. Numerical simulation results indicate that the value of characteristic length must be low for significant effect of non-Darcy flow and it is related to small effective radius. The non-Darcy flow parameters of the BCM may not be all estimated from single-rate tests in single-porosity reservoirs using conventional analysis approaches. However, they can be estimated by a fitting process based on non-linear optimization algorithm incorporated into the numerical model. Type curves generated by the BCM are provided to demonstrate a methodology for analyzing the effect of non-Darcy flow on pressure-transient tests in porous and fractured reservoirs. As application examples, numerical models of non-Darcy flow are used to model and interpret actual field pressure-transient data from high production rate oil wells in Kuwait.
A Novel Technique for Log-based Pore Volume Compressibility in Complex Carbonates through Effective Aspect Ratio
Authors: Saxena Vimal 
Published: May 2011

Abstract
Pore volume compressibility is a critical parameter to evaluate the reservoir potential and recovery factor. It is ideally determined through uniaxial core measurements, but may also be inferred through conversion of hydrostatic core analysis to ‘effective’ uniaxial values. Alternatively, determination of pore volume compressibility (PVC) through logs offers the option to devise an early PVC strategy for field development without extensive SCAL. While some successful siliciclastic case studies are available for log-based PVC estimation, little is established for similar techniques in carbonates due to its complex pore network. Devising a truly log based method that can serve equally well in carbonates is a challenge to the industry. This paper describes a new technique for log-based estimation of PVC.
The evaluation of dry frame bulk compressibility and matrix bulk compressibility are the basic pre-requisites for PVC determination in a rock poro-elastic model. Volumetric log analysis is utilized to determine relative components of complex matrix volumes and porosity. Hashin-Shtikman (HS) bounds are adopted to determine matrix elastic properties of a composite system. To determine the dry frame elastic properties, the present technique utilizes a Differential Effective Medium model and adopts the concept of effective aspect ratio that simulates the rock elastic behavior. It employs the assumption of constant rock shear compressibility under wet and dry conditions to predict dry rock behavior. In an iterative procedure, the approach predicts effective aspect ratio, dry frame bulk compressibility and in-situ pore volume compressibility for the each log depth. The shear compressibility input for DEM analysis is derived through sonic and density logs.
Thes technique is implemented in dolomite dominant complex carbonates in the south of the Sultanate of Oman. The model is validated in test wells where excellent match is observed between log-computed PVC and uniaxial core values. It is observed that pore volume compressibility is strongly dependent upon the effective aspect ratio and the porosity. This study delineates this relationship. For comparison, an inverse Gassmann's equation was used to determine dry bulk compressibility and found to highly underestimate pore compressibility.
A Novel Turbidity-Based Method to Determine the Insoluble Residue in Polymer Samples
Authors: Sabhapondit Anupom , Loveless David , Harris Phillip C. , Nanda Jajati K. 
Published: May 2011

Abstract
Water-soluble polymers are used to viscosify water-based fracturing fluids. This facilitates the growth of fractures and the placement of proppants. After placing proppants, polymers are removed to maximize productivity. To achieve optimum residual-polymer removal, it is essential to break the polymer gel to a low-viscosity fluid. Internal breakers or an acid flush are commonly used to break the polymer gels. Any insoluble or unbreakable residue can block pore spaces, leading to lower productivity. Therefore, it is very important that the polymers used for fracturing applications contain a minimum amount of insoluble residues or no insoluble residues.
In the widely used gravimetric method for determining residue, the polymer is first hydrated and then degraded before using gravimetric techniques. A standard gravimetric method takes more than 24 hr for one polymer sample. The accuracy of the results depends on consistency of laboratory techniques, such as filtration and weighing. Therefore, it was considered worth examining if a turbidity-based method could be developed to determine the insoluble residue quickly.
A linear correlation was found between turbidity and acid-insoluble residue of guar. The acid-insoluble residue, after keeping the guar sample in an aqueous fluid at pH 1.0 and 110°F for 24 hr, bears a linear correlation with the turbidity of the solution. The turbidity of guar solution after 2 hr of hydration at pH 7.0 also bears a linear correlation with the acid-insoluble residue. However, the turbidity did not bear any correlation with the total water-insoluble residue.
This study led to the development of a turbidity-based method to determine the acid-insoluble residue in guar after approximately 2 hr. This is possibly the first study to correlate turbidity with acid-insoluble residue in guar and has the potential to be used for other polymers as well.
Devonian Spore Assemblages from the Jubah, Jauf and Tawil Formations at Southern Ghawar Field, Eastern Saudi Arabia
Authors: Al-Ghazi Abdulla , Al-Ruwaili Mansour , Miller Merrell 
Published: May 2011

Abstract
An apparently complete representation of palynozones from D2 through D4B was recorded throughout the studied section. D2 was recognized from interval 1 and is indicative of the occurrence of ?Frasnian-late Eifelian. D3A spanning the Jubah/Jauf formational boundary occurs from interval 2. D3B, which caps the jauf reservoir, occurs within interval 2 (D3A and D3B are late Emsian to Eifelian in age). Palynozones D3/D4-D4A of Emsian-Pragian age are present in intervals 2 and 3 and span the Jauf/Tawil formational boundary. Lochkovian D4B was recognized in interval 3 and suggests the presence of the Tawil. The three lowermost samples from interval 3 were barren of palynomorphs.
When Should We Use Chelating Agents in Carbonate Stimulation?
Authors: Mahmoud M. A. , Mohamed I. M. , Nasr-El-Din H. A. , De Wolf C. A. 
Published: May 2011

Abstract
Carbonate reservoir stimulation has been carried out for years using HCl-based fluids. High HCl concentrations should not be used when the well completion has Cr-based alloy in which the protective layer is chrome oxide, which is soluble in HCl. HCl or its based fluids are not recommended either in shallow reservoirs where the fracture pressure is low (face dissolution) or in deep reservoirs where it will cause severe corrosion problems.
Different chelating agents have been proposed to be used as alternatives to HCl in the cases that HCl cannot be used. Chelating agents such as HEDTA (hydroxyethylenediaminetriaceticacid), and GLDA (L-glutamic acid −N, N-diacetic acid) have been used to stimulate carbonate cores. The benefits of chelating agents over HCl are the low reaction and corrosion rates. In this study, the effect of core length on the volume required to create wormhole was investigated using Indiana limestone cores of an average permeability 3 md and core lengths from 1 to 20 in. Chelating agents were tested at pH value of 4 and a concentration of 0.6M and their performance was compared with that of 15 wt% HCl.
Experimental results showed that the volume of HCl required to create wormholes increased when core length was 20 in. This effect was different from that noted when chelating agent were used. Increasing the core length for chelating agents decreased the volume required to create wormholes in the carbonate cores at the same conditions. This is because of the increased contact time by increasing the core length. Chelating agents can be used to stimulate shallow reservoirs where HCl causes face dissolution. They can be used in deep reservoirs where HCl can cause severe corrosion to well tubulars.
A New Wireline Rotary Coring Tool: Development Overview and Experience from the Middle East
Authors: Rourke Marvin , Torne Juan 
Published: May 2011

Abstract
The prediction of reservoir quality and producibility from petrophysical measurements in carbonates is a well-known challenge. A detailed reservoir characterization requires a suite of petrophysical logs, including imaging, nuclear magnetic resonance, capture spectroscopy for mineralogy, and formation testing logs. These logs are integrated with and often calibrated to measurements made from core analyses. Conventional cores that are cut while drilling are typically time consuming and expensive to acquire; they also require good geological control to pick the required coring depths. Conversely, wireline coring is faster; it provides precise depth control, and core plugs can be selected from a wide range of formations, which would not be practical for conventional coring.
In this paper, we introduce a new wireline rotary sidewall coring tool (RSCT™) device that can be used to selectively drill lateral core plugs from the formation. These core plugs are of sufficient size and quality for conventional and SCAL analyses. Recent improvements in the technology enable better core plug quality by providing digital interactive control of the downhole drilling process, which makes the new tool more reliable and less dependent on the experience of the operator.
This paper reviews experience and examples in which wireline acquired cores were drilled in various carbonate and silica-clastic reservoirs of the Middle East. The cases include carbonates with oomoldic porosity and brittle-fissile shales.
An Innovative One-Trip Optimized Wellbore Solution for Non-Cemented Liner, Wellbore Cleanup, and Sand Screen Placement Completion
Authors: Xu Yang , Duncan David , Paul Darren 
Published: May 2011

Abstract
An innovative optimized wellbore solution (OWS) has been developed to change how the industry completes lower or intermediate completion installations. In an openhole, non-cemented liner and sand screen type of completion, traditionally two trips are required. The production packer area is cleaned, the wellbore fluid is filtered, and fluids are displaced in the first trip. In the second trip, the sand screen with liner hanger will be deployed. Sometimes a third trip is run with a retrievable packer to perform negative liner top inflow test.
This optimized wellbore solution allows for setting the lower completion, cleaning the wellbore, and enabling displacement from drilling fluid to completion fluid in the wellbore in a single trip. On wells where there are concerns over equivalent circulating densities (ECDs), the optimized wellbore solution would include tools to isolate tubing pressures to the formation. This method would use the wellbore test packer (inflow test packer) and drillpipe shut-in valve while conducting the upper clean up and fluid displacement. It significantly reduces operating cost without impacting operating efficiencies.
A number of wells have been completed by this system. One completion was conducted for a major operator west of Shetland. An integral wellbore clean up string, along with the liner hanger and sand screen, were successfully deployed and helped the operator achieve their commercial goal of reducing operating cost. The saving was a reduction of approximately 32 hours.
In this paper, the one-trip optimized wellbore solution will be presented, along with the case history west of Shetland.
A Case Study: Production Management Solution "A New Method of Back Allocation Using Downhole Pressure and Temperature Measurements and Advance Well Monitoring"
Authors: Rasoul Reda Rabiee 
Published: May 2011

Abstract
Production allocation is of utmost importance for optimum reservoir development and production optimization. The need for quality oil, water and gas rate allocation has been increasing for determining the hydrocarbon delivery history for each well. The allocation becomes more complex when no periodic well test, no reservoir pressure recorded during pump shut in period, Malfunction of the pump sensors (Intake Pump pressure (Pi), Discharge Pump pressure (Pd)), Chock sizes per each well are not recorded with time, no surface gas/oil rate measurements or even the majority of well tests were conducted in commingle mode.
This paper presents an iterative methodology for oil and gas rate allocation. It combines the inflow performance relationship and vertical lift performance with real time wellhead data to create the flow model for each well. Furthermore, by combining the down-hole sensor data from ESP pump with Gilbert choke equation using the upstream and downstream pressures, accurate oil and gas rate allocation can be predicted. This methodology provides the hydrocarbon delivery of the well to give the chance for production optimization. This methodology was applied on a field case from western desert in Egypt for oil and gas production rate allocation and it is verified against sporadic well test points