bluuebunny/crossref_metadata_2025_split huggingface dataset:
Assessment of Leakage Pathways Along a Cemented Annulus
Authors: Deremble L.. , Loizzo M.. , Huet B.. , Lecampion B.. , Quesada D.. 
Published: February 2011

Abstract
Well integrity is one of the major concerns when assessing the containment of a geological CO2 storage. Whereas defect-free cement sheaths provide reliable barriers that prevent vertical migration or leakage of the stored CO2, significant leakage can occur if pathways appear in the cement seal: the stored fluid can flow through and alter their initial properties. A simulator has been built to numerically investigate the leakage rate of CO2 rich fluid through a pathway along a cemented annulus. Careful analysis of the physics and characteristic dimensions of the phenomena allows coupling of the flow, the mechanics of any defect and the chemical reactions that take place in the materials (fluid and cement). Results of the simulation, besides predicting the instantaneous flow rate and hydraulic conductivity of the defect, show different mechanisms of flow rates variation with time: in particular, coupling between flow along the defect and chemical reaction between cement and CO2 can lead to the deposition of minerals within the defect space. This may lead to a total plugging of the pathway – a self-healing of the cement. Based on dimensional analysis and semi-analytical solution, a criterion is defined in order to assess the long-term stability of the pathway.
Overview of the Midwest Geologic Sequestration Consortium Pilot Projects
Authors: Frailey S. M. , Finley R. J. 
Published: February 2011

AbstractAs part of the US DOE's Regional Carbon Sequestration Partnership program, the Midwest Geologic Sequestration Consortium has four active field demonstrations: two EOR pilots, one S/ECBM pilot, and one brine-saturated formation CO2 injection pilot.The S/ECBM pilot injection period was seven months which ended in mid-January 2009. The pilot included four wells completed in a coal seam at 900 ft. The injection well and three monitoring wells are oriented in the face and butt cleat directions. About 100 tons of CO2 were injected at 0.50-0.75 tons/day. Results indicate the enhancement of methane gas production and sequestration of CO2 through competitive desorption. Presently, post-CO2 water injection pressure transient tests are being completed to identify changes in cleat permeability resulting from CO2 adsorption.An immiscible (gas) CO2 EOR flood was started in May 2009 in a sandstone at 1900 ft. The injection rate was 20-25 tons/day. A water injection well was converted to a CO2 injection well. The well is centrally located between eight oil producing wells. CO2 injection ended in May 2010 with cumulative injection of about 7,200 tons. Twelve months of water injection are planned after CO2 injection. Several 100 barrels of incremental oil recovery have been measured; less than 5% of the injected CO2 has been produced.A liquid CO2 EOR, inverted 5-spot pilot was started in September 2009 and injection continued through January 2010 until winter road restrictions were enforced. During this time 2,860 tons were injected at 25-30 tons/day. While road travel was restricted, 13,000 barrels of water were injected. CO2 injection resumed in May 2010 and is planned to continue through the summer. At the end of the first CO2 injection period, the pattern’s oil production rate increased 200% from its baseline.The injection well of the deep saline formation test was drilled and completed in 2009. A verification well is scheduled to be drilled later in 2010. Injection is planned for 2011. The UIC permit process is near completion. This one million ton injection project will be in the Mt. Simon sandstone, the deepest sedimentary formation in the Illinois Basin. Injection rates of 1,100 tons/day are anticipated.
CO2 EOR From Representative North Sea Oil Reservoirs
Authors: Akervoll I.. , Eirik Bergmo P.. 
Published: February 2011

Abstract
Estimating the EOR potential in producing oil fields is an important input to decision making if large scale CO2-EOR is going to be employed in the North Sea. This paper describes the results from simulations of CO2 injection into conceptual reservoir models representative of water flooded oil fields in the North Sea.
Enhanced oil recovery (EOR) by CO2 injection is an attractive option because it has the potential to increase the oil, gas and condensate recovery of producing fields. In the North Sea a majority of the oil reservoirs have been subject to massive strategic and efficient water flooding resulting in high recoveries for most of the cases. However, more advanced tertiary recovery methods are sought to increase the recovery. Using CO2 as injection fluid has several advantages. Most oil compositions in the North Sea are miscible with CO2 at reservoir conditions something that will enable miscible displacement of the oil targeting residual (capillary trapped) oil after water flooding. The density of CO2 at reservoir conditions is in most cases lesser than the injected water and it may therefore reach other parts of the reservoir and consequently improve the sweep efficiency.
The North Sea shows a great variation in type of oil reservoirs and traps ranging in geological age from the Late Paleozoic to the Cenozoic. To cover the range of different geological classes, traps and recovery strategies a large number of scenarios has been simulated on conceptual sector models. Conceptual live reservoir oil is composed to represent fluid properties of a selection of 55 water flooded oil reservoirs in the North Sea that are considered potential candidates for CO2 injection. The selected reservoirs comprise 30 reservoirs in the UK sector, 20 in the Norwegian sector and 5 reservoirs in the Danish sector. The conceptual fluid model is composed and tuned to reflect the hydrocarbon pore volume (HCPV) weighted average properties of these 55 oil reservoirs.
Representative petrophysical properties and fluid compositions have been used in the models in order to schematically account for heterogeneities and phase behavior of the different reservoir types. Different injection schemes including CO2 injection with and without recirculation of CO2 breakthrough gas and CO2-WAG have been evaluated.
Sulfate Precipitation during CO2 Sequestration in Carbonate Rock
Authors: Mohamed I. M. , He J.. , Nasr-El-Din H. A. 
Published: February 2011

Abstract
Carbon capture and storage (CCS) has been proposed to mitigate the accumulation of CO2 in the atmosphere. Water alternating gas (WAG) technique is used in the industry to inject CO2 into underground formations either in sequestration or in EOR. CO2 dissolves in water, generating carbonic acid, which dissolves carbonate rock. The composition of the water is a critical factor that affects the rock permeability during sequestration. Sulfate content of the injected water can cause precipitation of calcium sulfate, which can negatively affect the rock permeability. This paper addresses potential formation damage due to sulfate precipitation during CO2 sequestration.
A core flood study was conducted using limestone cores. CO2 was injected at pressure greater than 1300 psi and temperatures (70 and 200°F). CO2 and brines were injected in WAG cycles under injection rates of 2 and 5 cm3/min. Seawater and formation brine were examined in this study. Core effluent samples were collected and concentrations of calcium and sulfate ions were measured to assess calcium sulfate precipitation. Core permeability was measured before and after the experiment.
The results show that temperature is the main parameter that affects sulfate precipitation during CO2 sequestration. Injection rate doesn’t have a significant effect on the core permeability. At high salinity calcium sulfate precipitation occurs even with low sulfate concentration present.
Solving Deep, Hard/Abrasive 16" Application Challenges with New PDC Technology Saves Operator 13 Days Rig Time, Kuwait
Authors: Al-Saeedi Mohamed , Al-Fayez Fayez , Sounderrajan Mahesh , Al-Mudhaf Mishary N. , Al-Kandary Abdul Q. , Mishra Manoj , Maliekkal Harish , Ghoneim Osama 
Published: February 2011

AbstractDrilling the deep vertical 16" hole (starting at 9,300ft) in northern Kuwait is challenging due to the complex stratigraphic section that contains abrasive Zubair sand (with pyrite), reactive Ratawi shale, hard Ratawi, Minagish, Makhul limestones and Hith anhydrite (UCS 10-30kpsi). Completing the 16" section typically requires around 45 days of rig-time and four polycrystalline diamond compact (PDC) bits on a positive displace motor (PDM) driven bottom hole assembly (BHA). However, inconsistent PDC bit performance/durability and lack of downhole stability was causing premature bit/motor failure. The operator required new PDC technology that could efficiently drill the abrasive, Zubair and continue as far as possible into the Ratawi without premature cutter failure at acceptable rates of penetration (ROP). The PDC bit would also need to possess improved stability characteristics to reduce PDM failures/trip hours.An engineering team was assembled to analyze the latest drilling/PDC technologies, optimize BHA design, and determine the best practices to enable reaching section TD with two PDC bits/runs. A finite element analysis (FEA) based engineering system was utilized to predict the dynamic behavior of each BHA component. The resulting information led to greater bit stability when drilling in lithologies comparable to the specific field application. The development of a new abrasion resistant cutter was considered important to improving durability and maintaining cutting efficiency.The in-depth study and PDC design changes/advanced cutter technology produced a new nine-bladed PDC bit. The new bit was run on a performance motor in Raudhatain field and set new PDC footage and ROP records for drilling through Zubair (1,200ft) in northern Kuwait (Figure 1). Historically, the Zubair alone required three/four TCIs or two/three PDCs to complete the formation interval. Next an eight-bladed PDC, fitted with the new cutter technology, drilled 2,508ft from Ratawi to section TD for the first time in Kuwait. The improved performance reduced rig hours by an average of 13 days for a total savings of approximately $390,000USD compared to the closest two PDC offset runs.
Application of Outcrop Analogs to Characterize Carbonate Reservoirs in the Pricaspian Basin
Authors: Kenter Jeroen A. , Playton Ted , Harries Paul (Mitch) , Katz David , Bellian Jerry 
Published: February 2011

AbstractSlope systems flanking high-rising isolated carbonate platforms and dominated by "deep-reef" microbial boundstone are heterogeneous due to a spectrum of depositional processes that cause a high degree of vertical and lateral variability. In addition, they are conceptually complex as a result of their poorly understood depositional controls and insensitivity to sea level fluctuations.The nature of the margins and slopes of the giant carbonate reservoirs of the Pricaspian Basin remains a controversial topic. Among the reasons is the poor quality of seismic data due to overlying salt as well as the lack of depositional models explaining their spatial distribution and seismic response. The use of analogs, in particular those from the Carboniferous of Spain, the Permian of New Mexico and Texas (USA), the Devonian of the Canning Basin (Australia), and the Triassic of the Dolomites (Italy), provide highly valuable depositional models.Intact and seismic-scale outcrops in northern Spain, USA and Italy proved the existence of deep-reef microbial boundstone slopes that characteristically display high progradation rates, propensity for fracturing and collapse, and insensitivity to sea level. Cores from the Tengiz and Karachaganak fields, when tied with reflection terminations and log character, confirm the presence of such slopes, leading to a radical change in the depositional and reservoir models. Results from the Canning Basin and Permian Basin provided models for margin styles and the detrital portions of slope systems that were successfully applied to portions of the fields. Seismic geomorphology and stratigraphic interpretation, guided by understandings from outcrops, allowed for the subdivision into multiple styles of clinoforms, slope and basin sediment wedges, margin configurations, and secondary features (i.e. reentrants). These revised subdivisions better conform to and explain the observed trends in reservoir properties and connectivity of the fields.Thus, integration of depositional models derived from outcrop analogs with seismic facies analysis, cores, log character and static and dynamic data is a critical step in reducing uncertainty and improving reservoir characterization, especially in cases where seismic response is obscured and well data is limited.
A New Method to Measure the Excess of H2S Scavenger in the Karachaganak Field
Authors: Ramirez Mario A , Casadiego Efrain , Spates Mary , Thekkabylov Almaz 
Published: February 2011

Abstract
The Karachaganak Field, which was discovered in 1979, is located in north-west Kazakhstan on the northern margin of the Pre-Caspian Basin. Production from this field contains 4 - 4..5% H2S. The Kashagan field, located offshore in the North West part of the Caspian Sea, averages 10-12% H2S concentration. An environmentally friendly H2S scavenger has been used in the Caspian area since 2006 in the invert emulsion drilling fluid systems. The operators had a standard practice of maintaining an excess of lime (2.5 kg/m3) as a supplementary sulphide removal additive and also raised concerns regarding the lack of a testing procedure to monitor concentration. This issue was regarded as being very important on the grounds of the significant risk that existed in the absence of more accurate method of monitoring scavenger concentration other than just mass balance calculations. The lack of ability to measure scavenger concentration more precisely in the invert emulsion fluid returned to the liquid mud plant (LMP), led to increased cost for the operator to maintain a safe concentration.
This paper discusses the design of a new method to be used in both OBM and WBM during field applications of the scavenger. The method is now used to monitor the excess scavenger in all the wells drilled in the Karachaganak field and to design subsequent treatments. The method has also contributed to improving the level of safety in the operation. The use of the proper scavenger concentration in combination with excess lime provides a primary and secondary barrier for protection against the influx of H2S
A Simple-to-Use Matlab-based Computer Program for Prediction of Formation Water Properties
Authors: Bahadori Alireza , Al-Haddabi Mansour , Vuthaluru Hari , Bahadori Meysam 
Published: February 2011

Abstract
Production of wet crude due to the raise in oil-water contact in many oil fields has been a growing field problem and consequently production of salty wet crude affects the quality of crudes. In this work, a simple computer program using Arrhenius-type function and Vandermonde matrix is presented for estimation of formation water properties for temperatures above 30°C and salt contents between 5 and 25 percent by mass. An Arrhenius type function has been selected because it is easier than existing approaches, less complicated with fewer computations and suitable for engineers. These expressions have been programmed using Matlab computational technical language and it can then be incorporated into further calculations that require predictions of formation water properties as functions of temperature and salt content. Estimations are found to be in excellent agreement with the reliable data in the literature with average absolute deviation varying between 0.08 to 2.7 %. The method developed in this study is of immense practical value for petroleum engineers and practice engineers for a quick check on the formation water properties at various conditions without opting for any experimental measurements. In particular, chemical and petroleum engineers would find the proposed approach to be user-friendly with transparent calculations involving no complex expressions.
One Well Evaluation in Low Permeability Gas Sandstones from Nuclear Magnetic Resonance (NMR) Logs
Authors: Wen Tang 
Published: February 2011

Abstract
It is difficult for petrophysicists in evaluating reservoir porosity, permeability and irreducible water saturation in low permeability because of the complicated pore structure. NMR logs have the advantage in this aspect. In this paper, with the analysis of a well with low permeability sandstones, we proposed the models to calculate reservoir porosity based on three parameters models from conventional logs, the parameters of classic SDR and Timur-Coates models are calibrated from 36 core samples, from this, the permeability estimation models from NMR logs are obtained. At the same time, the relationship between pore structure index (K/ϕ) and irreducible water saturation are established for bound water saturation calculation. The application of this well shows that these methods and models are usable in low permeability sandstones.
Online Production Model
Authors: Narain M.. , AL-Nabhan T.. 
Published: February 2011

Abstract
The objective of this paper is to discuss the development of a computer code based "Online Production Model" and to demonstrate its potential for optimizing Well Production or Equipment capacities of Oil & Gas handling facilities, in any oilfield.
The input data required for the model include the average dry and wet well production rates, GOR’s, capacity of each equipment within the oil & gas handling facilities, capacity limitations of the common facilities handling oil, gas & water of entire field and Laboratory data such as crude water cuts within the facilities.
Prior to development of this computer programme, calculations were limited to a fixed set of input data and a specific objective function.
With the availability of this model, the user has the freedom to modify (online) any input values (such as dry and wet well production rates, water cuts) to obtain the outputs for different sets of input data and objective functions on a single excel worksheet. On account of its modular structure, this model can be customized for input data from any oilfield.
The output of this model has been validated using KOC’s field data (averaged out over a period of several months) as input. However, for the purpose of confidentiality, the capabilities of the model shall be illustrated on fictitious field and laboratory data.

Technical Contribution
This model can be used for carrying out a "What if analysis" to predict future production trends (for e.g. at different production rates and varying GOR’s / water cuts) with the existing facilities.
It aids in determining bottlenecks of each facility as well as those of the common facilities to identify actions required to enhance production.
Performs an Online predictive analysis to calculate the equipment capacity upgrades (required under the best and worst case operating scenarios) at minimum additional costs to maximize yields.
Critical Evaluation of Shale Gas Reservoir Simulation Approaches: Single-Porosity and Dual-Porosity Modeling
Authors: Li James , Du C. Mike , Zhang Xu 
Published: February 2011

Abstract
Hydraulic fractures play a paramount role in the economical production of gas from shale gas formations. In the context of representing these formations as either single-porosity (SP) or dual-porosity (DP) media, different approaches have been used to represent the fractures in reservoir simulation models; for example, bi-wing planar planes, planar fracture networks, local grid refinements (LGR), discrete facture networks, hydraulic propped zones, and mircoseismic-based fracture networks. With their relatively short production histories, and because of the single-phase (gas) or two-phase (gas and water) nature of their production, most simulation models can reasonably history match the performance of any shale gas production well.
This paper reviews the evolution of different reservoir simulation models (SP-planar fracture, SP-planar fracture network, DP, DP-LGR, and DP-microseismic-based fracture network). Differences in SP and DP models are discussed, and examples demonstrate a match of the actual production from a shale gas well with the long-term prediction of each model.
Application of Production logging and Noise logging for Well Leak Detection, Case Study in Persian Wells
Authors: Salehi-Moorkani Reza , Mohamadipour Maryam 
Published: February 2011

Abstract
There are a variety of methods available to detect the source of downhole leak points include Production logs, down-hole cameras, thermal decay logs, and noise logs. However, many of these methods are not so much effective specially in case of very small leaks and can result in gathering data that requires a significant amount of logging assurance to interpret. Continuous logging has proven to be significantly more efficient in locating anomalies than static logging techniques commonly used in noise logging operations. Identification of the source of pressure communication between well tubing-casing and casing-casing annuli presents a huge challenge to petroleum engineers.
This paper presents a brief description of two technologies for leak detection and the findings from the field trial. In this well two type of logging techniques are used: Production logging and Noise logging. These tools were run in an oil well with a history of leaking oil 600 meters away at surface. Analytical work prior to the trial had established that the wellhead seals and burning pit flow line were not the source of leak. The paper describes the interpretation of the results that indicated a possible casing leak. The results show that in Noise logging the source of leak is clearer than production logging. In some cases two logs have read the same values.
LCA Application for Casing Design Well Integrity: Case Study Aquifer External Corrosion Attack in Middle East
Authors: Nengkoda Ardian , Priyandoko Pajang , Soejoso Mia Wimala 
Published: February 2011

Abstract
For many years, casing has reported failed rapidly in some Middle East oil and gas wells due to external corrosion casing. Repairs of casing failures are not efficient and costly. Mitigation of external corrosion as a part of well integrity on well casing is important to prevent from such water attack, H2S bacterial activity, electrolytic effects, and cathodic reaction. The alternative solutions based on LCA (Life Cycle Analysis) have been studied with objective to understand the casing leak and failure based on statistical data and to see the economic solutions over the life of the well by option of the use of coatings, dual casing or increase the thickness of casing materials. Casing corrosion will result not only in the loss of the casing but also in the interruption of production, loss of the well, or even permanent damage to the reservoir. Some of the statistic from study showed that 60% of single casing wells failed within less than 8 years while the external corrosion confirmed as an evidence from corrosion log run in some wells, due to shallow aquifer corrosivity. The studied summarized that coated casing is attractive solution for life of the well and the field trial to see the abrasion and water corrosion resistance showed this conclusion. Future sidetracking and surveillance need to be considered for the coating protection.