bluuebunny/crossref_metadata_2025_split huggingface dataset:
Rock-Fluid Characterization Using OBM Contaminated Samples Issues, Challenges, and Solutions
Authors: Nagarajan N. R. , Honarpour M. M. , Purpich A. J. , Arasteh F. 
Published: February 2011

Abstract
Acquisition of representative rock and fluid data from deepwater reservoirs is challenging and costly but is critical for the successful reservoir evaluation. It is common practice to use oil based mud, OBM, for drilling, particularly in deepwater offshore environment. Without proper mud additives and under excessive overbalance, OBM often invades the reservoir and contaminates cores and fluids. Measurements conducted on contaminated samples result in non-representative rock and fluid properties. Therefore, every effort should be made to minimize contamination in the samples. In fluids, mathematical corrections are needed to remove contamination effect and ensure representative fluid properties. In rocks, measurements on samples with minimum contaminations should be validated with those on cleaned samples.
High OBM invasion in several cores showed elevated apparent in-situ water saturation as identified by visual examination, CT density mapping, residual brine analysis, and total liquid saturation calculation. Electrical resistivity measurement on "as-received" samples and simultaneous capillary pressure and resistivity measurements on cleaned samples provided correct in-situ water saturation determination.
Customized sampling procedures with reliable fluid quality monitoring helped obtain minimally contaminated samples. In addition, novel mathematical techniques allowed correcting fluid samples to calculate representative fluid properties. Field examples are provided to demonstrate the success of these techniques for improved rock and fluid characterization.
The results of this study demonstrate the need for reservoir engineers to be closely involved in fluid sampling, coring, and data acquisition stages employing rigorous QA/QC protocols. Customized sampling and coring programs were essential to obtain minimally contaminated rock and fluid samples and rigorous methodologies were critical to correct the data measured on the contaminated samples and determine representative rock and fluid properties.
Quantifying Source Rock Maturity From Logs: How To Get More Than TOC From Delta Log R
Authors: LeCompte B. , Hursan G. 
Published: February 2011

Abstract
Thermal maturity is the primary factor that determines whether a source rock will produce oil, gas, or condensate. Two new methods for estimating the thermal maturity of source rocks from log data have been developed. First, the delta log R equation has been re-arranged to solve for level of maturity and correlated to vitrinite reflectance. Second, a method to determine kerogen density from log and core data is presented. Examples from the Barnett and Woodford Shales of North America show how changes in kerogen density and delta log R relate to source rock maturity and predict whether the formations will produce oil, gas, or condensate.
Utilization of Rotary Steerable Technology for Field Development and Drilling Shallow-TVD Horizontal Wells
Authors: Peytchev P. , Crighton A. , Upadhyay A. , Govind B. , Malik S.D. , Suryadi H. , Saha S. , Kale S. 
Published: February 2011

Abstract
Cairn Energy India Private Limited (CEIL) started development in Mangala field with aggressive target of drilling 60-70 wells/year (7days/well). Therefore, the focus was to reach high drilling efficiency which will ultimately reduce the well cost. Some of the challenges faced were placing wells in greatly faulted zones, high uncertainty in shallow TVD reservoir, requirement of tangent for installation of ESP, smooth hole to avoid problem running screen and collision risk due to closely spaced wells. RSS was generally used only in complex, high-cost offshore projects where the savings realized were significant. The industry has been slower to adopt the use of RSS for onshore directional drilling applications however CEIL took a step ahead by deploying RSS for Mangala field development. RSS was utilized in directional wells to optimize drilling performance and deliver smoother hole profile. Advanced LWD services such as bed boundary detection tool along with RSS have brought value in successful landing and placement of horizontal wells in the best reservoir strata. Application of near-bit gamma ray and other LWD measurements to identify the top of reservoir as early as possible has helped to avoid the requirement of drilling pilot holes. This paper discusses such application in detail and presents its benefits.
The result was a noticeable improvement in well delivery time, reduced drilling cost, and improved hole quality. This paper compares the drilling performances with PDM vs RSS in the same field and presents the lessons learnt in the process of field development. RSS delivered less tortuous hole which result in a problem-free liner or screen run. Hole cleaning was improved which allowed to drill at faster ROP without taking risk of well complication. Time versus Depth analysis clearly indicated that RSS was both technically and economically, a sound approach for drilling the wells in Mangala field. This paper showcases a case study where RSS application proven to be cost-effective solution even in low-margin onshore field development.
Flow Instability in Deepwater Flowlines and Risers - A Case Study of Subsea Oil Production from Chinguetti Field, Mauritania
Authors: Takei J. , Zainal M. Z. , Ramli R. , Matzain B. , Myrland F. , Shariff A. M. 
Published: February 2011

Abstract
The Chinguetti field located west of the Mauritania coastline has recently experienced a slugging condition in its flowline and riser systems. A study was undertaken in which integrated production system models of Chinguetti wells, flowlines and risers were developed using OLGA® transient multiphase flow simulator. The field is at a water depth of ∼800m and was developed with subsea wells, manifolds, 2 flexible flowlines and lazy "S" shaped risers tied back to a permanently moored turret Floating Production Storage Offloading (FPSO) located 6km away from the furthest drill centre. The main objective of the study was to assess slugging and potential methods to improve flow stability in the Chinguetti systems.
An extensive field validation and benchmarking exercise was performed by tuning the models to match field pressures and phase flowrates in the systems. The goal was to validate the models as closely imitating the conditions in the field. However, uncertainties in the field data made it difficult to reach satisfactory results in the benchmarking exercise. Simulations were then performed to examine the impact of various changes in operating conditions on flow instability. These included changes in well routings, gas lift injection rates and location of injection points, riser and wellhead choke openings. The degree of fluctuations in liquid arrival rates and the characteristics of liquid slugs (length and frequency) were used to categorize the severity of flow instabilities for a range of operating conditions.
Results from field implementation of recommended changes in operating conditions indicated improvement in flow stability. The success of this study was found to be dependent not only upon the inputs and assumptions made in the production system models but also on the outcome of the field validation exercises, and the understanding of pertinent governing factors influencing slugging behavior. The study highlights the methodology and analysis used to assess flow instability, outcome of field implementation, challenges faced and solutions proposed to minimize the flow instability of a deepwater oil field development.
Modeling World Oil Supply: Its Peak Production Rate and Time – Model Validation
Authors: Nashawi I. S. , Malallah A. , Al-Bisharah M. 
Published: February 2011

Abstract
Modern civilization as it is known to us heavily depends on hydrocarbon fluids and their byproducts. So far, the industrialized nations have completely presumed for granted an uninterruptable supply of cheap crude oil. Petroleum liquids are exhaustible resources; thus, a good forecasting scheme of oil supply will be crucial to all parties involved in the petroleum business such as oil companies, financial institutions, public policy planners and makers, and oil exporting and importing countries. Such a model will also help bring stability and security to the crude oil market. Over the years, accurate prediction of oil production was confronted by fluctuating ecological, economical, and political factors, which imposed many restrictions on its exploration, transportation, and supply and demand.
The objective of this paper is to illustrate the advantages of the multi-cyclic Hubbert model. We will demonstrate the effectiveness of the proposed model for the cases where the production rate fluctuates with time. We will also illustrate the effects of new discoveries or additional reserves due to innovative technology on peak oil rate and time and show how the multi-cyclic model accommodates these changes. Furthermore, we will demonstrate the flexibility of the proposed model to history match any future fluctuation in the production data. Historical production data of 47 countries around the world are used to predict the peak oil. The production rates of the last four years (2006-2009) are used to validate the accuracy of the model.
Physico-Chemical Characterization of Non-Aqueous Colloidal Gas Aphron-Based Drilling Fluids
Authors: Shivhare S. , Kuru E. 
Published: February 2011

Abstract
The colloidal gas aphron (CGA) based drilling fluids are designed to minimize formation damage by blocking the pores of the rock with microbubbles, which can later be removed easily when the well is open for production. Aphrons behave like a flexible bridging material and form an internal seal in a pore-structure.
Size and concentrations of the bridging materials are very critical to the fluid's ability to seal the high permeability zones. Proper sizing of the microbubbles with respect to pore size distribution is essential for developing an aphron drilling fluid with effective sealing ability. The physico-chemical properties (i.e., viscosity, density, fluid loss, etc.) of the CGA base drilling fluids also need to be understood in order to drill with these fluids more effectively.
Aqueous CGA based drilling fluids systems have been fairly well characterized and successfully implemented in high-angle and horizontal wells drilled in low permeability as well as highly depleted reservoirs. Effectiveness of pore blocking by colloidal gas aphrons is expected to be improved even more, if we can replace water with non-aqueous base fluid such as mineral oil.
An experimental study has been conducted to determine the effect of base fluid composition (i.e., surfactant and polymer concentration) on the microbubble size and stability. The surfactant and polymer concentrations required for optimum formulation of mineral oil base CGA drilling fluids were determined.
The physico-chemical properties of non-aqueous CGA drilling fluids are also investigated. The results of rheology, filtration loss and density measurement tests are also presented.
Experimental Investigation of Solvent Co-Injection in Vapor and Liquid Phase To Enhance SAGD Performance
Authors: Li Weiqiang , Mamora Daulat D. 
Published: February 2011

Abstract
Coinjecting solvent with steam under a steam-assisted gravity drainage (SAGD) process to reduce the required steam amount for heavy oil production has gained importance in recent years. The objective of this experimental study was to investigate the drainage mechanism for solvent co-injection in the vapor and liquid phases to improve production performance.
A 2D cross-sectional low-pressure scaled physical model was constructed. The model represented a half-symmetry crosssection of a typical SAGD drainage in the Athabasca formation. Using an infrared camera, we visualize and record expansion of the steam chamber and temperature distribution. The fluid injection rate, pressure, and temperature, and produced liquid volumes were also recorded.
The results show that the relative condensation time of solvent and steam results in different production performance. Solvent delivered in the vapor phase to the entire fluid interface reduces the bitumen viscosity along the whole vapor chamber boundary, but it may build a thick gas blanket that may reduce the heat transfer from the high-temperature vapor chamber to the surrounding low-temperature bitumen. Co-injecting a suitable multi-component solvent mixture, including a liquid solvent, can enhance the production performance by altering the condensation dynamics of the light hydrocarbons.
The conclusions from this study can be used to design suitable solvent mixture and coinjection strategies to deliver higher production rate, higher recovery factor with lower cumulative steam required to oil ratio (CSOR), and lower cumulative energy required for oil production (CEOR) from SAGD performance.
Upgridding Method for Tight Gas Reservoirs
Authors: Kelkar Mohan , Atiq Mustafa 
Published: February 2011

Abstract
Low permeability sandstone reservoirs in western US produce gas and water. Their geologic history indicates the development of non primary drainage equilibrium. Hence, one does not observe transition zone but trendless variation in multiphase fluid saturations throughout the formation. These varying multiphase fluid saturations will affect the effective permeability available to gas and water phases. Since the flow potential of a well is directly related to effective permeability, we propose a novel upgridding method to combine grid blocks having similar effective permeabilities which will implicitly take into account upscaling of multiphase fluid saturations in these tight gas systems.
Our algorithm groups vertical layers in a way such that the heterogeneity loss of an appropriately defined static property is minimized within layers. We define this static property of a grid block as the product of its net volume, its absolute permeability and relative permeability available to a phase within that grid block. The upgridding approach is essentially a sequential coarsening algorithm that starts from a fine scale model and merges the two adjacent layers that results in a minimum heterogeneity loss of defined static property.
To determine the optimum number of up-gridded layers for efficient numerical flow simulation of these detailed geological models, we define criteria such as removal of heterogeneity from a model at a particular coarsening step and design factor which will help preserve the critical level of heterogeneity. We compare our upgridding method with proportional upgridding and traditional variance based methods for synthetic and field cases of tight gas reservoirs, and the results demonstrate that our proposed layer combinations can better capture dynamic flow behavior of the fine scale model.
Design Optimization of Slotted Liner Completions in Horizontal Wells of Mumbai High Field
Authors: Kumar Avinav , Srivastava A. K. , Kumar Ravi 
Published: February 2011

Abstract
An efficient and cost-effective completion is very critical in the mature brownfield of Mumbai High. Horizontal and multilateral wells are strategic completions in this oil reservoir because of their high productivity and larger drainage area. This paper deals with design optimization of slotted liner for horizontal wells in Mumbai High field of India.
A good horizontal completion must maintain the mechanical integrity of the wellbore without posing a significant flow restriction. In this respect, slotted and perforated liners are cost effective solutions in horizontal wells because they provide uniform reservoir drainage, wellbore stability and control of solid production. A slotted liner completion is preferred, because it results in better solid control and lesser flow convergence. However, the compounded effect of formation heterogeneity and formation damage on pressure loss is severe in these completions. A good design is essential to minimize pressure loss due to flow restrictions and to maintain the long term productivity of well.
The major challenge is to have an optimum slot size and geometry that minimizes slot plugging and near wellbore flow convergence losses. A keystone slot design with consideration for convergence loss is arrived to address this problem. The effect of parameters such as slot size and slot density on flow convergence pressure loss was taken into account for design optimization.
This paper covers the design, optimization and application of slotted liner completions with an objective to address solid control, completion economics, well productivity and long term well performance.
Maximizing the Oil Recovery through Immiscible Water Alternating Gas (IWAG) in Mature Offshore Field
Authors: Tewari Raj Deo , Riyadi Slamet , Kittrell Charles , Kadir Farihan Bt , Bakar Mohamad Abu , Othman Tg Rasidi , Banu Nazrin 
Published: February 2011

Abstract
This paper discusses an enhanced oil recovery study of a multilayered mature offshore oil field in Baram Delta. Multiple reservoirs of the field have varying rock and fluid properties.The shallower accumulations contain oil of low API gravity of 19º with very low solution gas-oil ratios, while API gravity increases with depth to 24º in middle formations and 37º in the deepest sands. Upper sands are poorly consolidated with resultant high porosity and permeability. Most of the reservoirs are undersaturated. Initial field development comprised primary depletion with gas lift through vertical and directional wells - mostly dually completed. Field development strategy implemented measures like gravel packing wells to meet the challenges and possible problems during the course of field exploitation.
Field performance indicates that the current development strategy and practice may lead to moderate recovery lower than average recovery in Baram Delta fields through primary production. Detailed reservoir characterization has been carried out to capture the reservoir heterogeneity and multiple realizations have been made to understand the major uncertainties of the field. Screening studies for maximizing the recovery from the field suggests gas based EOR techniques may find application. The EOR method of Water Alternating Gas injection (WAG), both immiscible and miscible, is gaining significant interest for improving the oil recovery in offshore fields. The improvement in recovery due to WAG injection is attributed to contact of the upswept zones and modification of residual oil saturations and targeting the attic oil. The advantage of the process is that combination of water and gas injection provides the improved displacement efficiency of gas flooding with improved macroscopic sweep efficiency due to water injection. The result is improvement in recovery compared to separate gas or water injection. Also three phase flow (oil, water and gas) is better in displacing the residual oil compared to two phase flow water and oil or gas and oil.
Parameters which are critical for impacting the WAG enhanced oil recovery process are studied thoroughly. These parameters include WAG ratio, injection rates, cycle, well spacing, sweep efficiency and conformance control. WAG is planned for AB, C, D, and EF reservoirs which have low to moderate recovery. The study suggests that improving the well spacing and proper injection volume provides improvement in recovery factor of the order of 8-10%. The paper also discusses the mechanism of the process through mechanistic modeling and laboratory studies for injection water compatibility, rock- fluid interaction, gas mobility control using Nanofluid/Foam which is expected to provide the better sweep and upside potential.
Successful Applications of Expandable Sand Screen in Persian Oil Fields, Part 2
Authors: Deilami Fatemeh , Salehi-Moorkani Reza , Ghasemzadeh Amir 
Published: February 2011

Abstract
In some Persian oil fields hydrocarbon recovery is mainly from sandstone reservoirs and sand production is a major problem in these fields. Main reason of sand production in these reservoirs is due to unconsolidated sandstone layers. The common method to decrease this problem is achieved by installing mechanical sand control systems. Previously, some techniques of sand control have been used in Persian oil fields, such as gravel packing, slotted liner and chemical consolidation. The results which have been obtained through these methods are not remarkably good enough in some cases.
Expandable sand screen (ESS) is a new technique in sand control that can result in lower skin and consequently improves reservoir inflow performance. Field tests in various conditions have shown very satisfactory results in both open and cased hole applications. This paper will discuss economic aspects of ESS and analyses well pressures. In addition it provides ESS comparison with other sand control systems through real cases and well modeling. Finally, it talks about the candidate selection step and its significance on ESS performance.
Well Treatment Fluids Prepared With Oilfield Produced Water: Part II
Authors: Li Leiming , Ezeokonkwo Chucks I. , Lin Lijun , Eliseeva Ksenia , Kallio Wade , Boney Curtis L. , Howard Paul , Samuel Mathew M. 
Published: February 2011

Abstract
As fresh water becomes more expensive, production and service companies have been trying to use low-quality water such as produced water. Broadly defined, produced water may include any unclean oilfield water that often contains bacteria and high salinity/hardness. Preparation of polysaccharide-based well treatment fluids with produced water frequently results in poor viscosity even when the water is pre-treated with biocides, possibly due to the polysaccharide degradation by bacterial enzymes in the water. This paper presents our continuous success in solving the produced water reusing problems, and discusses the chemistry and case histories of the treatments in North America.
A new fluid stabilizer has been developed recently that dramatically extends the lifetime of polysaccharide when used in produced water containing bacteria, possibly because the stabilizer denatures bacterial enzymes. This stabilizer has made it possible to prepare a variety of treatment fluids with produced water.
Since its introduction, the fluid stabilizer has brought greatly enhanced performance for the borate-crosslinked polysaccharide fracturing and sand control fluids, as reported in SPE 124212. In this paper we continue to explore the new and broader applications of the stabilizer. The polysaccharide fluids with metal crosslinker have been successfully prepared with the stabilizer-treated produced water. The fluids can endure higher temperatures. At the same time, the fluid pH can go below 4, making it possible to energize the fluids with carbon dioxide. The stabilizer has also been used to treat water contaminated with high counts of bacteria, which in turn has been successfully made into crosslinked polysaccharide fluids with improved high-temperature stability.
The expanded applications of this fluid stabilizer have further lowered the operating costs for the production and service companies. This new technology has also contributed to the environmental improvement by saving fresh water and recycling produced water in oilfield operations.