bluuebunny/crossref_metadata_2025_split huggingface dataset:
"The Seven Pillars of Well Integrity Management": The Design and Implementation of a Well Integrity Management System
Authors: Sparke S. J. , Conway R. , Copping S. 
Published: September 2011

Abstract
Today and industry wide, management of well integrity is a common issue, and relates to both old and new producing fields. It is apparent that many fields were not designed with the concept of 'well lifecycle management' and were probably constructed for a life of about 15 - 20 years. A producing well that is 30 years old is quite common (e.g. North Sea production started in 1975) and for wells in locations such as the Middle East some fields are more than 40 or 50 years old.
In line with its expansion and transition to becoming a major independent oil company through its recent discoveries of very large oilfields in Ghana and Uganda, Tullow Oil needed to broaden its existing well integrity policy and practices. This is to fit with a projected 4 to 5 fold increase in oil production in the next few years and increase its well count to over 500 wells.
In order to evaluate the processes in-place, the "Seven Pillars of Well Integrity Management" were defined as the fundamental requirements of an ideal system. These were used to identify gaps in existing practices which were systematically and thoroughly addressed by Tullow.
Tullow now has one centralized well integrity management process that is described in detail through a company policy. This incorporates a software system to collect and manage key construction and operational data from all operated wells. Though monitored and audited from a corporate perspective, the integrity system is run by each asset to suit local operational demands and requirements.
This paper documents the learning process that was experienced by Tullow in their path to deliver a company wide system that would suit varying production scenarios in four different operating environments, with a broad range of cultures and technical challenges and ultimately be expandable to suit the growth of the company.
The Role of Diffusion for Non-Miscible Gas Injection into a Fractured Reservoir
Authors: Yanze Yannick , Clemens Torsten 
Published: September 2011

Abstract
To improve oil recovery from pervasively fractured reservoirs, gas injection can be considered. In such reservoirs, the fractures typically provide the flowpaths but contain a limited amount of the oil whereas the matrix often has orders of magnitude lower permeabilities but contains the oil.
To improve oil recovery from such reservoirs, gas/oil gravity drainage can be applied. In this process, a gravity stable displacement can be achieved.
If gas is injected which is not in equilibrium with the oil, the non-equilibrium gas components diffuse from the fracture system into the matrix and the components of the oil diffuse towards the fracture system. This results in a modification of the properties of the oil affected by diffusion and gravity drainage rates accordingly.
The effects of non-equilibrium gas injection into a pervasively fractured reservoir were studied at the example of an Austrian reservoir. This type of gas injection results in a zone of decreased oil viscosity for gases such as CO2 and CH4 at the interface of the gas and the oil in the matrix. This zone of lower oil viscosity increases the gas/oil gravity drainage rates.
The results show that the effect of diffusion can increase cumulative oil production up to 25 % compared with a case neglecting the effect of diffusion. The effect of diffusion could be determined for various parameters such as permeability, porosity, fracture spacing and matrix block height. While for some of the parameters, the effect of diffusion scales with the square root of time (e.g. permeability), for others an exponential relationship has been determined (fracture spacing).
The results derived for the example reservoir can be used more generally to screen whether the effect of diffusion should be incorporated into reservoir studies concerning non-equilibrium gas injection and how large the error could be in case that diffusion is neglected.
Water Injectivity Tests on Multilayered Oil Reservoirs
Authors: Barreto A.. , Peres A.. , Pires A.. 
Published: September 2011

Abstract
Completion of water injection wells directly into production oil zone has become a common practice on offshore development projects. Hence, injectivity tests started to play an important role for reservoir management of these fields. In an injectivity test a single phase (water) is injected continuously for a certain period of time in an oil saturated zone followed by a falloff period. Though single-phase flow of a slightly compressible fluid analysis methods are well documented in literature, transient two-phase solutions and analysis techniques need further development. Analytical solutions that model pressure behavior during a single layer injectivity test were recently presented in literature. This paper presents a new analytical solution for a vertical water injection well completed in a layered oil reservoir of infinite extent. To the best authors’ knowledge, the proposed solution was not presented before.
Two phase immiscible displacement of oil by water in a multilayer reservoir is modeled by a system of partial differential equations. This system is weakly non-linear and can be decoupled by assuming steady-state conditions in the two-phase region. The solution is then obtained by the method of characteristics on the two-phase region coupled with the infinite acting single phase radial flow solution valid for the oil region. The solution derived in this work can be used to compute the wellbore pressure, injection rates and the water front for each individual layer without resorting of a numerical flow simulator. Parameter estimation from field data can be obtained from the proposed solution if a production logging rate profile is available.
Two synthetic examples are used to verify the solution derived in this work. The first example considers the behavior of a two-layer reservoir whereas in the second case a reservoir with seven layers is analyzed. The wellbore pressure is compared to a finite difference simulator. An excellent agreement is obtained for both examples.
Thin Bed Sand Shale Sequences Decoded by NMR Answers
Authors: Potts Robert , Smith Charles H. , Ramakrishna Sandeep 
Published: September 2011

Abstract
The Tesnus sandstone was deposited during the late-Mississippian/early-Pennsylvanian time in clastic debris flows. In general, it consists of a series of sand/mudstone turbidite sequences that are deposited in thicknesses varying from a few hundred to several thousand feet overall. The uppermost Tesnus consists of amalgamated and thinly-bedded sands that contain poor–good vertical connectivity and tend to have better ultimate recoveries. The lower sands are layered sands consisting of thin interbedded sandstone and shale sequences with poor vertical connectivity.
These sands present an analysis problem for conventional open-hole logs, as standard porosity interpretation is not directly related to well performance as a result of the high clay content and poor permeability. Hydrocarbon production from the Tesnus is primarily natural gas with a varying amount of CO2 content, ranging from 1—30%, and very minor amounts of formation water. Sand and shale sequences can be as thin as 1–2 in. These thin zones could have high permeability zones next to zones of no permeability. Thin bed logging approaches were used, but could not adequately measure the volume nor evaluate the quality of the reservoir.
Magnetic Resonance logs were added to the typical logging program in an attempt to gain a better understanding of this complexity. The Bray-Smith bin permeability equation was used with the T2 (relaxation) response to accurately define permeability. The presence of hydrocarbon was clearly indicated by the T1 (polarization) response. These answers allowed completions to be targeted in the more productive parts of the Tesnus and enhanced the calculation of net pay. This paper summarizes the results of using these measurements to design completions in this difficult reservoir. This approach can be applied in many difficult evaluation situations.
Magnesium Peroxide Breaker for Filter Cake Removal
Authors: Mahapatra Shrikant K. , Kosztin Bela 
Published: September 2011

Abstract
Commonly used Drill-in Fluids (DIF) are typically comprised of starch, xanthan and sized calcium carbonate. Although, DIF is inherently less damaging than the conventional drilling mud, relatively impermeable filter cakes are still deposited on the borehole walls. The polymer in the mud provides cohesiveness and encapsulates the bridging solids (CaCO3). Consequently, the polymers in the cake retard the dissolving of the bridging particles and therefore, must be decomposed to allow a complete and even dissolution of the soluble solids in the filter cake. A common practice to minimize such damage is the application of acids (External Breaker) or strong oxidative breaker (Internal Breaker) system to dissolve filter cake solids and biopolymers.
Magnesium Peroxide is an internal breaker. It is a classified oxidizer which slowly decomposes to release oxygen. Since magnesium peroxide is a powdered solid, it becomes an integral part of the filter cake. Due to the extremely low solubility of Magnesium peroxides it remains stable for extended periods of time in alkaline environment and within the filter cake. The magnesium peroxide, when exposed to an acidic solution, it releases hydrogen peroxide which degrades the polysaccharide type polymers and open-up the external filter cake.
In an effort to evaluate the effect, laboratory experiment was carried out. Due to the wide range of possible mud system, a pragmatic range was selected for evaluation. A total of six different drill in fluid were formulated, based on practical application in the field. The laboratory experiment shows that magnesium peroxide influences the acid clean up. Subsequent field trial in three horizontal wells in South Oman field showed excellent stability of the mud and clean up after soaking in 15 % hydrochloric acid.
Quebrache Field: Evaluations to Date of this Natural CO2 Reservoir
Authors: Gachuz-Muro Heron , Sanchez-Bujanos Jose L. , Castro-Herrera Israel , Rodriguez-Pimentel Jose A. 
Published: September 2011

Abstract
In the search for oil and gas during the past century, other gases have been encountered. These gases had little or no economic value and areas known to contain them were avoided during drilling.
Deposits of CO2 rich gas (&gt;50 %) are present worldwide but in limited areas – USA, mainly. Few studies of natural CO2 reservoirs are currently available to determine and analyze its accurate exploitation. CO2 concentrations ranging between 71 and 98 % have been discovered in the Northeast of Mexico. Preliminary evaluations (SPE-107445) of the available data for Quebrache field indicated potential gas reserves.
Complementary analyses to date have shown that on balance, the Quebrache field offers a significant opportunity for developing Enhanced Oil Recovery (EOR) projects. This new study divides the field into tree important areas. This paper presents: a) recent reservoirs discovered b) estimated reserves for all tree areas with CO2 sources (Central Area, Northern Area and Southern Area), c) efforts made to evaluate its potential d) opportunities to invest in and operate a world-class CO2 reservoir, etc. The Central Area reveals 2 important reservoirs. These reservoirs are relatively continuous and could produce and drain reserves during long period. Original Gas-In-Place (OGIP) volumes are likely conservative because in its calculation it is assumed a gas-water contact (there is contact apparent in the well logs). The Quebrache field would provide strategic value to CO2 injection programs.
The CO2 accumulations described in this paper could play a major role in recovering additional oil from fields in the North of Mexico. Thus, CO2 accumulations in the right place and at the right time may become production targets in the future.
Holistic Optimization Approach Improves Economic Viability of Bakken Shale Play
Authors: Ibrahim Hani , Gidh Yashodhan , Purwanto Arifin , Bits Smith 
Published: September 2011

Abstract
The Bakken Shale is one of the largest, unconventional crude oil plays in the United States covering as much as 25,000 sq miles in the Williston Basin. The formation underlies portions North Dakota and Montana and is found at depths ranging from 9000ft to 10,500ft. Reserve estimates vary but the United States Geological Survey (USGS) has calculated risked undiscovered resources of up to 4.3 billion barrels of recoverable oil and bbl/cu ft equivalent using current technology. At this time the field is being developed with single, dual and triple-leg horizontal wells with laterals extending 4500ft to 9500ft into the formation.
However, drilling activity in the area has fluctuated as a result of changing oil prices. Accordingly, reducing overall operation costs is essential to the economic feasibility of each drilling project. Because of the significant impact on drilling costs, the correct selection and utilization of drilling equipment including bits, drilling fluids, hydraulics and downhole tools is paramount. To optimize operations, a holistic approach was adopted to create a drilling "road map" utilizing several application software systems. These software tools enable engineers to envision the specific drilling environment and tool/BHA interaction before the bit goes in the hole.
A recent Bakken project included expert drill bit selection, rock mechanics analysis, shock studies, drilling fluids and hydraulics optimization. The directional well plan was optimized with wellbore simulation software. In order to circumvent deficient options prior to and during actual drilling operations, multiple scenarios are simulated using a collection of detailed geological and offset drilling information. These results were studied, analyzed and assessed as the optimum drilling solution prior to submitting them to the operator. Finally, the service provider monitored and implemented the recommended engineered solutions.
The initial results were encouraging: Drilling days on Well 1 were reduced by 30% which represents a cost savings of $572,000USD while achieving the drilling target and delivering a high-quality wellbore. Building on this initial success, second and third wells confirmed the value of holistic optimization saving the operator 13 days ($676,000USD) and 16 days ($832,000USD) of rig time respectively.
Downhole Safety Valve for Well-Intervention Operations: Design, Testing, and Successful Case History
Authors: Ehtesham A. , Reesing D. , Giles J. 
Published: September 2011

Abstract
As things progress each year in the oil industry, there is a much greater emphasis on safety. Live well-intervention operations are challenging because of inherent risks and require detailed risk analysis and appropriate mitigation, such as redundant safety devices. This paper presents details of the development, testing, and successful field deployment of a newly designed safety valve that can be used on coiled tubing (CT), jointed tubing (JT), and CT-JT hybrid string applications.
This safety valve, located at the junction of the CT and JT, is a key component of the CT-JT hybrid string. Once the CT is connected to the JT, the valve can be pressure actuated to close or open the flow path to the wellbore. This allows the hybrid string to be run in hole (RIH) and pulled out of hole (POOH) with complete wellbore-pressure control. Various methods can be used to activate the valve, such as using surface hand pumps, pressuring between blowout preventers (BOPs), or remotely with pressure differential downhole.
Double-flapper check valves have typically been part of a standard well-intervention bottomhole assembly (BHA). However, integrity of these valves is always in question after heavy pumping operations, especially with sand-laden fluids. This new safety valve incorporates a protective sleeve that keeps the flapper assembly covered and in pristine condition in its normally open position, helping to ensure a more reliable seal on closure. Chemical compatibility of elastomers, along with low- and high-pressure sealing reliability, are some of the challenges involved with conventional designs. Considering these limitations, the new safety valve offers a true metal-to-metal, non-elastomeric, spherical-to-spherical, flapper-closure mechanism with low- and high-pressure sealing capability based on ISO 10432/API 14A specifications. The flapper valve is designed and manufactured based on award-winning subsurface safety-valve technology.
The safety valve was virtually tested using computational fluid dynamics, followed by functional testing on a full-scale prototype. Validation testing for functional, pressure, and sealing capabilities was conducted at an API type test facility. The safety valve was subsequently deployed and successfully passed field-trial operations.
Experimental Investigation of Fracture Interaction between Natural Fractures and Hydraulic Fracture in Naturally Fractured Reservoirs
Authors: Zhou Jian , Xue Chengjin 
Published: September 2011

Abstract
The interaction between natural fractures and hydraulic fracture was observed in multiple naturally fractured blocks by a series of physical model tests. The effect of natural fractures and in-situ stress on fracture geometry was revealed. Three types of fracture geometry were observed due to a change of in-situ stress contrast. Besides, pressure profiles could also reflect different characters of propagating behaviour. Random small natural fractures could lead to high frequency of pressure fluctuating during fracture propagation. Also natural fractures with strong network could lead to more smooth pressure during injection. Hydraulic fracture tended to be a dominating fracture with random multiple branches at high differential horizontal stress. It tended to be partly vertical (one wring), planar fracture with branches at a lower difference of horizontal stresses. Random natural fractures could dominate fracture geometry alone in condition of extreme low in-situ stress difference. In present of random natural fractures, mini-fracturing is still reliable if fracture geometry is a partly vertical, dominating one (even one wing).
Reservoir Characterization through Automatic History Matching of Underbalanced Drilling (UBD) Data in a Horizontal Well
Authors: Wu Zhan , Suryanarayana P. V. 
Published: September 2011

Abstract
During under-balanced drilling (UBD) of a horizontal well, down-hole pressure and temperature, as well as surface rate and pressure data are acquired. Theoretically, estimation of reservoir permeability profile can be achieved by quantitative analysis of these data. However, in practice, not only is a fine-grid reservoir simulator required to simulate the drilling schedule change due to tripping, completions, workovers, increase of well length with drilling and fluid flow in reservoir, but also an effective inversion approach is needed to estimate the reservoir parameters. The problem of reservoir characterization using UBD data has been studied by several previous workers. At current state of the art, neither analytical models nor commercial reservoir simulators are completely suitable for modeling the coupled system of UBD and reservoir fluid flow.
In this paper, we focus on the development of an automatic history matching technique to interpret the measured oil rate and down-hole pressure data while drilling. Our contributions are three fold. Firstly, a two-phase 3D reservoir simulator was developed in which the UBD drilling process was coupled into the reservoir simulator. Next, the reservoir simulator is applied to simulate the entire drilling process from penetrating the pay-zone until the well is complete. Secondly, a least square method is applied to match the down-hole pressure and oil rate data. The inversion for a synthetic UBD data set and realistic UBD data are demonstrated on a multi-zoned reservoir model. The results show that permeability and initial reservoir pressure can be obtained by matching down-hole pressure or oil rate in a short time of exposure to the reservoir section. Finally, we offer the details for implementing the UBD process in the simulator and discuss the practical issues of the application of UBD data in reservoir characterization through this automatic history matching technique.
Simulation of Parameters Derived from Nuclear Magnetic Resonance Log Using Conventional Well Logs and Fuzzy Logic
Authors: Maximiano C.. , Carrasquilla A.. 
Published: September 2011

Abstract
Nuclear Magnetic Resonance (NMR) technique is currently used in well logging to provide important informations so that the interpreter can analyze the physical properties of oil reservoirs. This tool provides informations, in a more effective way than the conventional logs on free and irreducible fluids, total and effective porosity, and permeability, which allows a better reservoir interpretation and the consequent hydrocarbon evaluation. One of the ways to make this is using artificial intelligence approaches as Genetic Algorithm, Fuzzy Logic, Neural Network, etc., to synthesize porosity and permeability parameters derived from NMR log, using as input only conventional logs of petroleum industry, such as natural gamma ray, spontaneous potential, caliper and resistivity. This process is justified because NMR log is currently expensive and, for this reason, it is not done at all wells and can not be obtained in cased holes, but provides physical characteristics of the reservoirs which are hardly obtained by other means, either through conventional geophysical logs or formation evaluation techniques. Initially, we developed an algorithm, using Fuzzy Logic Tool of MATLAB software, with log data of East Texas, aiming to see the influence of the number of membership functions in clustering. When three linguistic classes were selected, the results were not satisfactory because the synthetized logs showed a box form. Then, when we removed the middle linguistic class, an improvement was observed in the synthetized logs, however, still having a box pattern. Finally, using the ISODATA algorithm of MATLAB, a better fit with the real porosity and permeability curves was obtained, eliminating box shape and promoting a more careful division of clusters. In this form, we demonstrated the feasibility of the simulation of parameters of NMR log through Fuzzy Logic.