bluuebunny/crossref_metadata_2025_split huggingface dataset:
Compositional Surveillance Program for Assessing Prudhoe Bay Vaporization Process
Authors: Bharat Jhaveri , Becky Steen , Michael Connolly 
Published: December 2014

Abstract
Prudhoe Bay field, the largest oil and gas accumulation in North America, has a large gas cap in communication with the oil rim. In addition to the liquid condensate held in the gas phase, the original gas cap contains relict oil that exists in the liquid phase at low saturations and is remnant of the oil migration - spill history of the reservoir. One of the key recovery mechanisms at the Prudhoe Bay field is the use of lean gas injection to increase recovery through vaporization of relict oil and dropped-out condensate in the original gas cap, and residual oil in the expanded gas cap. The lean gas vaporization project was implemented with an initial installed gas handling capacity of 2 BCF/D which was successively expanded to 8 BCF/D in several Gas Handling eXpansion (GHX) projects making it the largest hydrocarbon gas injection project in the world. After processing the produced gas to manufacture NGLs and Miscible Injectant, the lean gas is reinjected into the Prudhoe Bay gas cap for pressure support and vaporization of liquid phase hydrocarbons. In addition to estimates of black oil benefits, design and commercial evaluation of each stage of the gas handling expansion required accurate prediction of vaporization benefits from lean gas injection.
A compositional surveillance program was designed and implemented to assess the efficiency of the vaporization process in the field. This paper describes the surveillance program in which the routine separator tests conducted at the specified well locations for fluid allocation and production optimization are modified to include additional measurements of extended separator gas compositions and separator oil API gravity. The paper also presents details of an analytical procedure in which the measured compositional information from the well tests is used together with other relevant field data to deduce the effectiveness of the vaporization process. The compositional surveillance data analysis procedure is demonstrated by application to the gravity drainage area of the Prudhoe Bay field. Deliberate application of the compositional surveillance data acquisition and analysis by the Prudhoe Bay Reservoir Management team will significantly impact the optimization of the vaporization process in the field.
Integrated Asset Modeling of a Gas Condensate Field Operating Under Gas Recycling Mode
Authors: Torrens Richard , El Gohary Mohamed , Al Bairaq Ahmed , Kumar Arun 
Published: December 2014

Abstract
An integrated asset model (IAM) was constructed for an onshore carbonate gas condensate asset in Abu Dhabi. The strategic priority of the field is to optimize recovery of liquids and, therefore, the field is operated under gas recycling. After processing, dry gas is reinjected for the purpose of maintaining reservoir pressure to maximize condensate recovery. However, gas is a critical natural resource, and so a strategic decision was taken in 2011 to assign a portion of the produced gas for sales and use nitrogen as a makeup fluid to maintain reservoir voidage. The long-term implications of this decision will be the need for installation of nitrogen rejection units to ensure produced gas meets sales specifications after the field blows down.
The IAM brought together reservoir, well, pipeline, and facilities domain models into an integration platform that provides an increased level of modeling fidelity by removing some of the simplifying assumptions and enabling cross-discipline collaboration to achieve understanding of the asset's problems and objectives. The model itself is complex and comprises a multimillion-cell reservoir simulation model, production and injection pipeline models, and a simplified model of the gas processing facility, all of which utilize a fully compositional approach to fluid modeling. The model was validated over a period of 6 months of production history by comparing calculated rates and pressures with measured field data from the field at the facility, trunkline, and well level. Once the validation phase was completed, the IAM was used to predict life of field performance.
The IAM approach provided critical information not available from traditional standalone modeling. Firstly, more accurate accounting for the backpressure impact on the production and injection wells resulted in significant differences in production and injection profiles. Secondly, the inclusion of a facility model to update the injection composition resulted in major differences in nitrogen production. Finally, as a result of collaboration with facilities production, operations, and facilities teams during the project, the historical match to condensate production was considerably improved.
Successful Application of Intelligent Completions in Al Khalij Field
Authors: Briz-Quintero X. , Sofyan M. , Pouget P. , Le-Roch J. , Authier J. , Deffous Y. , Gurses S. F. , Gulamov E. , Mukashev N. , Jaafar M. R. , Abul-Hamd I. , Al-Naimi A. R. 
Published: December 2014

Abstract
The first successful field wide application of intelligent completion technology in TOTAL worldwide has been installed in Al Khalij field wells. The Al Khalij field, located offshore Qatar, was discovered in 1991 and put into production in 1997. The field is formed of a highly heterogeneous carbonate reservoir with significant remaining dynamic uncertainties, making reservoir management a challenge. Moreover, given the currently high field water cut (WCT = +/- 90%), any operation to decrease it, without a detrimental impact on the productivity, can have a large impact on its oil potential.
The standard Al Khalij oil producer well architecture has around 3000 m of horizontal drain across the reservoir, of which half is completed on 7″ or 6 5/8″ cemented and perforated liner and half is a 6″ or 5 3/4″ openhole extension. All the oil producer wells are lifted with electrical submersible pumps (dual ESP standard). Since 2007, Total E&P Qatar started deploying intelligent wells for reservoir zonal control, monitoring and enhanced management. Currently 28 intelligent completions have been installed in the field, with a low misrun rate (1 out of 29). Such completions have allowed selective down hole flow control without any additional heavy intervention (i.e. shift sliding sleeves in horizontal well). In the year 2011 and 2012, for the first time in TOTAL Group, a number of 3 Flow Control valves have been installed in two Al Khalij wells.
Given the ease of manipulating multi-position flow control valves, the Al Khalij intelligent completions can be manipulated regularly in order to acquire inflow information (Low-cost PLT) and optimize the well behavior. In 2013, the control valves operations brought extra oil of up to +/-5% of the field production.
This paper details the design, planning and execution of the intelligent completion technology in the Al Khalij field and covers the value generated value for field development.
Phased-Development Strategy to Mitigate Subsurface Uncertainties and Risks in Developing a New Gas Field: A Case Study in the ADCO Fields, UAE
Authors: El Bahri Sami , Al-Shaarawy Osama , Chouaibi Mohieddine , Ghorayeb Kassem , Amanov Batyr , Stojic Slobodan 
Published: December 2014

Abstract
In a new field development plan (FDP), it is essential to identify and assess both static and dynamic reservoir uncertainties. Therefore, an integrated field development study was conducted on multilayered, thin, and relatively tight rich gas-condensate reservoirs in one of the Abu Dhabi Company for Onshore Oil Operations (ADCO) fields. The study identified new potential areas where very limited data were available. Therefore, drilling appraisal wells was essential to confirm the potential of these areas, narrow down the uncertainties, and minimize the development risks.
The phased field development strategy made it possible to appraise the new identified potential areas before embarking on facility construction and drilling development wells. The phased-development plan consists of two major phases:
Phase I
•Drill appraisal and development wells onshore and on existing artificial islands.
•Drill appraisal and development wells by extension of existing artificial islands.
•Collect data, mainly consisting of coring and special core analysis and additional fluid sampling.
•Use long-duration tests to assess performance and sustainability of each reservoir.
Phase II
•Construct new artificial islands in confirmed areas.
•Drill development wells on new artificial islands.
The phased field development strategy takes advantage of a continually changing and improving reservoir model in addition to accelerating the time of first gas production and project revenue and minimizing the associated development risk.
Numerical Temperature Modelling for Quantitative Analysis of Low-Compressible Fluid Production
Authors: Aslanyan Arthur , Aslanyan Irina , Salamatin Andrey , Karuzin Andrey , Fesina Yulia , Zaripov Ilnaz , Skutin Vasiliy , AL Ghafri Zaaima , AL Yarabi Mohamed , AL Maharbi Abdulaziz 
Published: December 2014

Abstract
Temperature logging is an efficient technique to locate inflow intervals in the reservoir, evaluate inflow rates in them and the drawdown pressure that creates temperature disturbance, detect cross-flows in the wellbore and/or behind casing and check for casing, tubing and the bottom-hole leakages. Temperature logging can detect wellbore flows with rates way below the mechanical spinner's threshold. Another impressive application of temperature logging is picking flow zones behind unperforated casing that develop through behind-casing channelling. Such findings can be verified or discarded through numerical simulation of temperature logs. This paper presents the TSMp solver module of the TERMOSIM simulator that can reproduce complex hydrodynamic flow patterns and the associated thermodynamic effects, taking place during fluid flows through a multi-layer reservoir towards the wellbore and their blending in it, including heat exchange between reservoir and wellbore flows and the surrounding rocks.
The TSMp solver takes into account possible inter-reservoir communications both inside and outside casing caused by the pressure difference between formation units, as well as short-term and long-term lateral flows that can disturb the temperature at any depth, and calculates fluid rates for each formation unit and temperature profiles for the wellbore and for any distance from it.
This paper describes the general physical and mathematical models and user interface of the TERMOSIM TSMp simulator for producers and presents modelling results for two production wells of Oman. For each well, the TSMp simulator has been employed to create a best-fit individual thermohydrodynamic model and match downhole pressure and temperature records for different production rates. The well log analyses based on temperature modelling presented in these case studies open the way to (a) identify actual reservoir inflow intervals, (b) evaluate formation pressure in flowing units, (c) evaluate inflow rate from each flowing unit and (d) distinguish between wellbore cross-flows and behind-casing channelling.
The case studies presented in this paper are focused on low-compressible, mostly single-phase fluids with high water or oil and low free-gas contents (while multiphase flows with abundant free gas will be covered in a separate paper).
A New Method for the Characterization of Heavy Oil and Bitumen using Distillation Curve Data
Authors: Azinfar Bahareh , Zirrahi Mohsen , Hassanzadeh Hassan , Abedi Jalal 
Published: December 2014

Abstract
Fractionation and characterization of heavy oil and bitumen are essential steps for phase behaviour modeling and the simulation of bitumen production, refining, and upgrading processes. Typically, the bitumen is divided into several pseudo-components in order to tune an equation of state (EoS) and then utilize it for the process modeling and reservoir simulation. The interaction coefficients and critical properties of the pseudo-components are commonly tuned using experimental laboratory oil PVT data. Measuring of this data is very expensive and time consuming, especially for heavy oils. Characterization based on experimental distillation data has the potential to eliminate the need for time consuming laboratory oil PVT data.
In this study, we present an effective model for the characterization of heavy oil and bitumen using experimental distillation data. Batch distillation without reflux is modeled to regenerate the experimental distillation curve using the residue curve map method. The Peng-Robinson equation of state (PR-EoS) and NRTL activity model are applied to calculate the fugacity and activity coefficients in the gas and liquid phases, respectively.
The proposed model was able to accurately regenerate the experimental distillation curve. The properties of the characterized fractions and the binary interaction coefficients obtained from the model were used to estimate solubility of light solvents (CH4, C2H6, CO2, N2) in the Athabasca bitumen. Good agreement between the experimental and the estimated solubilities reveals that the proposed approach is a reliable predictive tool for heavy oil and bitumen characterization.
The proposed model provides an accurate and simple method for characterizing heavy oil and bitumen. The only data required is the experimental distillation curve. Since this model does not require experimental oil PVT data, it can be applied quickly and inexpensively compared to other methods available in the literature. The presented approach will find many applications and has potential to become the superior method for phase behaviour studies of heavy oil and solvent systems.
Challenges on Sampling and Characterization of Heavy Oil in Deep Exploratory Wells: A Field Case Study
Authors: Rajkhowa Anupam , Al-Bader Haifa , Hameed Waleed Ahmad , Al-Nabhan Abdul Razzaq , Subban Packirisamy 
Published: December 2014

Abstract
Exploration activity on heavy oil is steadily gaining momentum in the state of Kuwait. Recently, discovered heavy oil in deeper low permeable Lower Cretaceous reservoir from exploratory wells drilled in two different fields of West Kuwait area at around 11,000 ft. depth. Drill stem testing method was applied to test these exploratory wells. During testing, there was inflow of heavy oil of API 21-22 deg, but the well could not be produced naturally in spite of repeated attempts. Matrix acid stimulation treatment was done to improve the productivity of the reservoir. Well-flowed heavy oil and then gradually ceased to flow. Due to viscous nature, low mobility and low reservoir energy, self-flow could not be sustained. These pose significant challenges for well cleanup, flow studies and collection of representative sample for PVT analysis and fluid characterization.
As no other lifting methods were available, Coiled Tubing was lowered and the well was lifted continuously with nitrogen for cleanup and to assess production behavior. Surface Sampling was not favorable due to mixing with lifting nitrogen gases and only alternative method available was to collect Bottom-Hole Samples (BHS). However, proper cleanup was an issue for sampling operation. Therefore, compositional analysis was done on the lifted sample to quantify the contamination level in the produced fluid before lowering the down-hole sampler in order to capture representative samples. As a result of this approach, representative samples could be captured and fluid characterization could be carried out with quality results which will add value to future reservoir study and modelling. Based on the successful results, it has been planned to use similar approach for sampling in such conditions.
Methodology adopted to overcome challenges faced for sampling and characterization of heavy oil in deep as well as in low permeability reservoirs will be presented in this paper.
A Case Study of Hydraulic Fractures Optimization in Heavy Oil
Authors: Bo Cai , Yunhong Ding , Yongjun Lu , Yonghui Wang , Xin Wang , Chunming He , Liao Wang 
Published: December 2014

Abstract
With high oil demand and prices, and production of most conventional-oil reservoirs in decline, industry focus in many parts of the world is shifting to exploitation of heavy oil, extra-heavy oil and bitumen. Hydraulic fracturing stimulation is also an important technology for some tight heavy oil formations with low porosity and ultra-low permeability in the Songliao and Bo haiwan basin in North China, while application of conventional fracturing technology in the recovery processes of heavy oil reservoir will meet some problems such as high viscosities, poor flow properties and high densities in compared to conventional oil. This paper describes a successful case of proppant fracturing on an ultra-low peameablity and high viscosity (17.6API) sandstone heavy oil reservoir in eastern China. Several technologies including pre-pad fluids, hydraulic fractures numerical simulation for enhancing heavy oil drainage area, tip screen-out (TSO) fracturing in order to improve fracture conductivity, multi-step slurry injection schedule, low damage gel were used.
More than 33 treatments with new technologies in Huabei, Liaohe oil field have been performed with encouraging results, 88.5% efficiency with accumulated incremental oil of 213,050 ton and the average post-fracturing rate reach to 25.9m3/d satisfied as expected, which is three times of before stimulation, while in the past, there were many treatment failures. It has a great significance not only in improving fracturing treatment effect in above mentioned heavy oil formations but also in perfecting low damage fracturing technique as well.
Polymer Flooding for Extra-Heavy Oil: New Insights on the Key Polymer Transport Properties in Porous Media
Authors: Rodriguez F. , Rousseau D. , Bekri S. , Djabourov M. , Bejarano C. 
Published: December 2014

Abstract
Primary cold production in extra-heavy oil reservoirs (7-12° API) is currently a low percent of the OOIP, as for some oil fields in La Faja Petrolífera del Orinoco (FPO), Venezuela. EOR studies are being conducted in order to increase recovery factors primarily in those thin bedded reservoirs which host up to 35% of the OOIP. Thermal EOR is usually the first option implemented to increase recovery. However, thermal methods are not suitable for thin pay zones and involve high water consumption which can create environmental issues. For these reasons, chemical EOR is becoming a feasible tool for mobility control and mobilization of residual oil.
Polymer flooding applied to extra-heavy oil may require rather high concentration polymer solutions. The objective of this study is to contribute to a better understanding of the specific mechanisms involved in this context. Transport properties of polymer in porous media are investigated through a set of corefloods tests performed on model sandpacks, the high permeability (4 Darcy) and the temperature (50°C) being representative of the conditions of the FPO. Polymer transport is analyzed versus injection concentration in terms of the key petrophysical parameters controlling the performance of a polymer flooding operation, namely: retention and inaccessible pore volume, in-depth propagation and injectivity.
Results show that all parameters strongly depend on polymer concentration. Specifically, the concentration dependence of polymer retention, inaccessible pore volume and in-depth propagation behavior cannot be interpreted by conventional models. Injectivity is also strongly affected by concentration: both rheo-thinning and rheo-thickening effects become more marked when concentration increases. This set of experimental data are the key for modeling the transport of high concentration polymer solutions in porous media. They also provide direct information needed, through reservoir simulation, to sanction the technical and economical feasibility of polymer flooding for extra-heavy oil.
Using Cyclic Steam Pilot Performance to Address Reservoir Description Uncertainties
Authors: Sanyal Tirtharenu , Waleed Al-Khamees , Abdulraheem Hadeel Faisal , Amal Al-Sane , Abdulla Al-Balam 
Published: December 2014

Abstract
In a thermal Enhanced Oil Recovery project of Kuwait, the static reservoir description uncertainties were identified based on initial static description. The associated development impact and possible risks to the project is then evaluated using a commercial uncertainty analysis tool through simulation studies. Field dynamic testing results from the ongoing Cyclic Steam Stimulation(CSS) pilots and other dynamic testing data were then used to evaluate the static description uncertainties, for an improved reservoir description.
The observation from the study is extremely important in not only having an improved understanding of the reservoir description of the subject field but has wider implications in similar reservoir set ups in other parts of the globe. The observations from the pilot operation and simulation history matching clearly demonstrates that local reservoir set up plays a crucial role in each thermal project and understanding them is extremely important for success of the project. The results of the study demonstrate the importance of integrating dynamic cyclic steam stimulation testing results with preliminary static description, to arrive at an improved reservoir description.
The technology of thermal Enhanced Oil Recovery (EOR) is an old concept but its application in different reservoir set ups give rise to new learning that widens the knowledge base in the industry. The reservoir being developed in Kuwait is considered a challenging one from many of the classical screening concepts. The success of some of the experiments tried in this project and the learning from their success has wider potentials in similar complex thermal developments.
De-risking a Heavy Oil Development - A Case Study of the Bentley Field, UKCS Block 9/3b
Authors: Brennan B. H. , Lucas-Clements C. , Kew S. , Dempsey P. F. 
Published: December 2014

Abstract
The Bentley Field, located on the UK continental shelf in block 9/3b in 110 m of water, contains approximately 900 MMstb in-place of heavy (10 to 12 oAPI) viscous (1500 cP) crude. The field is four-way dip closed at uppermost Palaeocene, lowermost Eocene, Dornoch sandstone level, and covers an area of about 16 Km by 5 Km.
An appraisal programme culminating in the 2012, 9/03b-7, 7Z extended well test (EWT), has addressed the key technical concerns associated with developing the viscous crude in an offshore environment. The programme demonstrated how sustainable commercial flow-rates can be achieved through the selection of a suitable completion design, including a downhole electrical submersible pump (ESP), a downhole diluent injection strategy, and through keeping within an appropriate operating pressure and temperature envelope. It further demonstrated that the movement of water from the underlying aquifer into the production bore proceeds in a predictable and manageable way, that produced water and oil can be separated even though emulsions are created in the ESP, and that water can act as a carrier fluid within the export pipeline.
The information from the EWT has been used to define and de-risk the field development design which is currently estimated to deliver 257 MMstb of 2P Reserves over a 35 year production period. In addition it is estimated that 48 MMstb of 2C Contingent Resources could be commercially extracted beyond the end of the currently planned facilities life. Investigations are underway to accelerate this tail-end production, with initial studies indicating that a polymer flood, enhanced oil recovery scheme, could be attractive.
This paper describes the appraisal programme, the lessons learnt and how these have been applied in designing the field development plan.