bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Next Opportunity To Improve Hydraulic-Fracture Stimulation
Authors: Vincent M.C. 
Published: June 2014

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering.
Abstract
Forty years ago, most people in our industry would have claimed that producing economic flow rates from nanodarcy formations was simply impossible. Thirty years ago, tax incentives were introduced by the US Congress to encourage drilling of ’unconventional’ tight gas reservoirs in which the permeability was near 0.1 md. Today, our industry is voluntarily drilling into formations that are 1/1,000 as permeable, and making tremendously profitable wells! The technology that facilitated this ’impossible’ feat is hydraulic fracturing-specifically, the opportunity to initiate multiple transverse fractures from horizontal wells.
While hydraulic stimulation has provided tremendous advances in our ability to develop lower-permeability resources, the corresponding challenges have not been addressed fully. This article summarizes one perspective on future opportunities that will allow even more-thorough and more-cost-effective recovery of hydrocarbons from tight reservoirs.
Reservoir Contact
In highly permeable formations, conventional wells may be completed without stimulation. The borehole and perforations provide sufficient reservoir contact to achieve profitable hydrocarbon production. However, more than 90% of the wells currently drilled in North America require fracture stimulation to recover reserves from low-permeability formations at economical rates. Hydraulic fracturing involves pumping a fluid at sufficiently high rates and pressures to extend cracks into the formation surrounding the wellbore. Granular materials are injected to prop the created fissures open to delay their collapse. These created fractures can increase the contact between the wellbore and reservoir dramatically and are the key that has unlocked tremendous hydrocarbon resources contained in tight formations.
Effect of Surfactant Partitioning Between CO2 and Water on CO2 Mobility Control in Hydrocarbon Reservoirs
Authors: Ren Guangwei , Zhang Hang , Nguyen Quoc P. 
Published: June 2014

AbstractThis paper presents a systematic study of the effect of surfactant partitioning between supercritical CO2 and water on surfactant transport and foam propagation during two-phase flow. A series of corefloods were conducted on Silurian dolomite cores with different non-ionic and anionic surfactants that represent respective wide ranges of partition coefficients and solubility in supercritical CO2. Foam robustness and displacement efficiency were related to these surfactant properties. Coreflood results and all measured surfactant properties were used in a commercial reservoir simulator to determine the variation of surfactant partitioning effect from laboratory to field scale. Optimization of surfactant partition coefficient for field-scale foam process was performed with different injection strategies.The results from this study enable us to tailor properties of CO2 soluble surfactants (i.e. partition coefficient) to a wide range of reservoir conditions and optimal injection strategies. The understanding of surfactant partitioning effect is also important in overcoming technical challenges encountered in the injection of surfactant in CO2.The partition between CO2 and water phases was much more sensitive to surfactant structure than temperature and pressure. Strong foam development was observed for all non-ionic and anionic surfactants while an increase in surfactant partition coefficient lowers the rate of foam propagation. Field-scale foam simulations indicate that foam performance and surfactant transport was governed not only by constrained injection strategies, but also surfactant partition coefficient. For a given injection strategy, the latter could be optimized to improve injectivity and sweep efficiency.The optimal partition of the surfactant between the CO2 and aqueous phases minimize wasting expensive surfactant in water that is never contacted with CO2. This novel CO2 soluble surfactant concept diversifies injection strategies with respect to operational constraints, broadening the application of foam process.
Applications of Accurate In-Situ Fluid Analysis in the North Sea
Authors: Achourov Vladislav , Gisolf Adriaan , Kansy Andreas , Eriksen Kåre Otto , O'Keefe Michael , Pfeiffer Thomas 
Published: June 2014

Abstract
As we strive to complete more complex reservoirs, we are challenged to better understand the nature of the fluids contained within. In the North Sea, classical "black oils" are still encountered; however scenarios where volatile fluids that exhibit a bubble point are found in close proximity to fluids with dew points are not uncommon. In addition, knowing the CO2 content is paramount to completion engineering and facility design with high penalties incurred when CO2 quotas or production limits are exceeded.
Characterizing these fluids is difficult. Typically wireline formation testers with fluid analyzers are used for early fluid characterization and sampling. However, with the increasing fluid complexity subtle differences need to be understood. This requires comprehensive compositional analysis, high resolution answers and quantified accuracy.
This paper describes the technology and answers provided by an accurate in-situ fluid analyzer. Several case studies are discussed. In the first example oil is sampled from two depths, only a few meters apart. The in-situ fluid analysis data from these two depth, including C1, C2, C3-C5, C6+ CO2, GOR and density are compared, indicating excellent tool resolution. In addition these data are compared to laboratory sample analysis result with observed differences falling well within the quoted tool accuracies. A second example involves several closely stacked reservoirs. An in-situ compositional analysis was obtained for each reservoir fluid. By changing the flow rate of the formation tester downhole pump the flowing pressure was manipulated. This allowed to measure different ranges of bubble point pressures for each fluid. Only a few meters below a second fluid exhibiting a dew point was encountered. An indication of the fluid dew point pressure was detected by again manipulating the flowing pressure. Fluid analysis revealed compartmentalization and fluid grading through the different reservoirs in this well.
The Cumulative Risk Assessment Barrier Model
Authors: Blacklaw Alan , Ward Al , Cassidy Kevin 
Published: June 2014

Abstract

Description
The Cumulative Risk Assessment Barrier model – a methodology that simply demonstrates performance against Safety Critical Barriers and communicates key risks in basic terms to workforce and management.

Application
The Cumulative Risk Assessment Barrier Model has been used within BG Group’s UK Upstream asset as a highly effective and visual communication and decision-making tool for the past 18 months.
This tool has been further enhanced and automated with the introduction of Barrier Model Dashboard. This has enabled a more detailed, accurate and interactive approach to cumulative risk management.
The Barrier Model Dashboard links to live data from the Permit to Work (PTW) and Computerised Maintenance Management System (CMMS). Information is extracted from PTW and CMMS on key risk areas including: initial risk from impaired systems and systems where maintenance is overdue;residual risk from these systems after mitigation measures have been taken into account; andsafety-critical element reliability information (providing information on the statistical likelihood of hidden failures and the potential for systems to fail when called upon in an emergency).
This data is combined to provide a traffic-lighted risk profile for each installation, based on the series of barriers in place to prevent Major Accident Hazard events and prevent their escalation.

Results, Observations, Conclusions
The interactive display provides visual cues for operations and maintenance teams whilst providing real time information on the safety of continued operation. This enables clear understanding of risks and provides prioritisation on the remedial works that will have the greatest impact on reduction of cumulative risk. Local teams can ‘zoom’ into specific locations within a site, while management teams can get an overview of the status across multiple sites and can trend cumulative risk profiles over time.

Significance of Subject Matter
The tool is of significance industry-wide as it provides transparent measures based on collected corporate system data which is then merged with "soft" measures such as the human/environmental elements, all of which are collected, clearly presented, and stored. The information is updated on a daily basis and provides up-to-the minute, accurate information.
Intelligent Exploration and Appraisal Program for a Multiprospect Development
Authors: Delfiner Pierre 
Published: June 2014

Summary
While many companies are hunting for elephants, exploration results in deep offshore plays over the past years show the increasing trend away from giant-field discoveries toward smaller fields in the 50-100 million bbl range, which tend to be geographically dispersed. These resources need to accumulate to a critical mass, a global threshold, to justify an economically viable development. This is not only a question of volume but also of geographic location of the discoveries, and the threshold, of course, also depends on economic factors.
A methodology is proposed to evaluate the potential of a block to lead to a multiprospect development and to optimize exploration and appraisal. It is illustrated by a real deepwater case study including five discoveries and four prospects, 10-30 km apart. The practical approach taken is to define circles or ellipses on a map representing potential hubs and their catchment areas. For each area, a global resource threshold is defined by analogy with other regional developments or by a detailed economic study of representative cases (not discussed in the paper).
A probabilistic model of the resource base is derived from the geological assessments of discoveries and prospects. It is entered into Monte Carlo simulation to generate a large number of scenarios representing exploration outcomes and discovery volumes, which are stored in a scenario database. This allows a probabilistic evaluation of the performance of an exploration and appraisal program, using specially developed indicators such as the cumulative discovered P50. Intelligence is introduced in the process by evaluating after each well the probability of meeting the threshold with the remaining wells. If it is low (10% or less) the program is stopped, which has a great impact on risked economics.
The main results of the analysis are the economic decision tree with the probability of a development decision and the P90/ P50/P10 of the developed resources; the number of wells in the dry branch of the tree, which actually is not a fixed number but a probability distribution; the definition of a firm and contingent well program; and an optimum drilling order, which may also reduce the well count.
Lattice Boltzmann Simulation of Non-Darcy Flow In Stochastically Generated 2D Porous Media Geometries
Authors: Newman M.S.. S. , Yin X.. 
Published: June 2014

SummaryIt is important to consider the additional pressure drops associated with non-Darcy flows in the near-wellbore region of conventional gas reservoirs and in propped hydraulic fractures. These pressure drops are usually described by the Forchheimer equation, in which the deviation from the Darcy's law is proportional to the inertial resistance factor (β-factor). While the β-factor is regarded as a property of porous media, detailed study on the effect of pore geometry has not been performed. This study characterized the effect of geometry on the flow transition and the β-factor using lattice Boltzmann simulations and stochastically constructed 2D porous media models. The effect of geometry was identified from a large set of data within a porosity range of 8–35%. It was observed that the contrast between pore throat and pore body triggers an early transition to non-Darcy flows. Following a quick transition where the correction to the Darcy's law was cubic in velocity, the flows entered the Forchheimer regime. The β-factor increased with decreasing porosity or an increasing level of heterogeneity. Inspection of flow patterns revealed both steady vortices and onset of unsteady motions in the Forchheimer regime. The latter correlated well with published points-of-transition. In developing a dimensionally consistent correlation for the β-factor, we show that it is necessary to include two distinctive characteristic lengths to account for the effect of pore-scale heterogeneity. This finding reflects the fact that it is the contrast between pore bodies and throats that dictates the flow properties of many porous media. In this study, we used the square root of the permeability and the fluid-solid contact length as the two characteristic lengths.
Removing Formation Damage and Stimulation of Deep Illitic-Sandstone Reservoirs Using Green Fluids
Authors: Mahmoud M. A. , Nasr-El-Din H. A , DeWolf C. A. 
Published: June 2014

Abstract
Illitic-sandstone reservoirs are very sensitive to HCl-based fluids. When HCl contacts illitic-sandstone it breaks down and causes fines migration and formation damage. The migration of fines through the porous media will block the pores, reduce permeability and decrease the production rate of oil and gas wells. Literature showed that all clay minerals are essentially unstable in HCl at temperatures greater than 300 °F. In turn, there is an essential need to look for stimulation fluids other than HCl to stimulate deep sandstone reservoirs.
Alternative fluids to HCl/HF mud acids were introduced to stimulate and remove the damage from illitic-sandstone reservoirs. These fluids are chelating agents such as EDTA (ethylene diamine tetraacetic acid), HEDTA (hydroxyl ethylene diaminetriacetic acid), and GLDA (glutamic acid-N, N-diacetic acid). In this study, sandstone cores with different illite contents were examined. Illite content of 1, 10, 14, and 18 wt% of the sandstone cores were used in the coreflood experiments at 300 °F. Different combinations of GLDA/HF were tested to determine the optimum ratio of GLDA/HF. CT scan and permeability measurements before and after the treatment were used to assess the effectiveness of each fluid in removing the damage and stimulation of sandstone cores.
Our results showed that 15 wt% HCl caused severe damage to sandstone cores with different illite contents. GLDA, HEDTA, and EDTA showed a good compatibility with the illitic-sandstone cores at 300 °F. Permeability measurements and CT scan results showed that GLDA performed better than HEDTA and EDTA at pH of 4. The optimum ratio of GLDA/HF concentration was found to be 20 wt% GLDA/1 wt% HF, which gives the maximum increase in core permeability. The three fluids tested in this study showed good compatibility with illite. They can be used to stimulate illitic-sandstone reservoirs alone or in combination with HF acid. GLDA was found to be compatible with the sandstone cores that contained up to 18 wt%. No sands deconsolidation was noted with any of the three fluids. The results obtained from this study will significantly improve the outcome of acid treatments in illitic-sandstone reservoirs at high temperatures.
Developing Oil in Monobore Well Completion Using Permanent Coil Tubing Gas Lift Application
Authors: Kramadibrata Ari Taufiq , Sumaryanto Sumaryanto , Panjaitan Pahala 
Published: June 2014

Abstract
VICO Indonesia has operated the Sanga-Sanga PSC in East Kalimantan, Indonesia, since 1968. More than 750 development wells have been drilled to date in the complex Mahakam Delta in East Kalimantan. The mature reservoirs are predominantly gas, extremely depleted and have an average recovery factor of about 70%. To optimize the development cost VICO changed the completion from multi string and multi packers to monobore in 1997 and furthermore to dual monobore in 2005. VICO has also focus to optimize oil production and recovery. The current oil recovery factor is relatively modest and needing further detail study and optimization.
A multi-disciplinary team was performed to further evaluate oil potential in all VICO fields including review of historical performance, geology and development opportunities. These reservoirs were also evaluated using material balance to understand the initial volumes in place, the drive mechanism and the opportunity to maximize production and oil recovery through the existing wells.
One of the challenges in maximizing oil recovery is artificial lift system in monobore completion. VICO has evaluated and selected gas lift as optimum artificial lift method. There are two possibilities to gas lift oil wells (1) using a side pocket mandrel in the conventional dual string completion and (2) inject gas lift through coil tubing in the monobore completion.
The paper describes innovative gas lift system in monobore completion where gas lift mandrels were not pre-installed. This technique has been implemented, by running 1.5" coil tubing into a well through a special tubing hanger attached to the top of the Christmas tree. This technique allows gas lift to an oil reservoir in monobore well completion without requiring rig for recompletion. This application is known as "Permanent Coil Tubing Gas Lift" or PCTGL. This technique has been implemented in "MUT-X" well that was not capable to flow naturally, and then PCTGL was installed to resume oil production. The well was flowing 600 BOPD initially and now is continue flowing at 350 BOPD.
In summary, PCTGL is a proven favorable and simple method for artificial lift application in monobore completion to maximize oil production and recovery. Furthermore, this technique has helped VICO in synergizing gas and oil development to maximize value of the assets.
Optimization of Equity Redeterminations Through Fit-for-Purpose Evaluation Procedures
Authors: Worthington Paul F. 
Published: June 2014

Summary
Equity redetermination is most commonly encountered where a straddling field is developed as a discrete entity through a process of unitization. It is enacted through evaluation procedures that prescribe the technical methodology for requantifying different license shares, or tract participations, in a field unit as more data become available. The formulation of these procedures usually takes place at unitization, it is based on appraisal data, and, therefore, it is guided by simplified perceptions of reservoir character. For this reason, many such technical procedures have been found to be lacking when they are applied later at the equity redetermination stage. These shortcomings can take the form of ambiguous wording, misleading definitions, technically inappropriate specifications, contradictory prescription, or simply a lack of sufficient detail to render the intended process meaningful. They have impeded the determination of revised tract participations by triggering interlicense disagreements that might otherwise have been avoided.
With the objective of reducing this unhelpful impact, experience of redetermination situations is used to illustrate the nature and consequences of poorly constructed procedures for the recomputation of tract participations. The analysis is then flipped to generate a framework of key elements of technical procedures together with indications of how they are best implemented. These matters form the basis for a high-level set of protocols for a more efficient and effective redetermination of equity that would avoid the previously encountered shortcomings. The protocols encompass the proper incorporation of data character, a sound technical basis for redetermination, a balance between under- and over-prescription, an auditable deterministic ethos, and adherence to good international petroleum practice. They constitute recommendations for a better approach to the compilation of fit-for-purpose evaluation procedures within those unitization agreements that make provision for a future redetermination of equity. The recommendations are equally applicable to domestic and international unitizations. The principal benefit lies in an enhanced efficiency of the equity-redetermination process, which feeds through to a greater collective asset value.
A New Approach To Simulate the Boundary Layer in the Vapour Extraction Process
Authors: Nourozieh Hossein , Kariznovi Mohammad , Abedi Jalal , Chen Zhangxing John 
Published: June 2014

Summary
The vapour extraction (VAPEX) process, as a nonthermal process, may be suitable for the recovery of heavy oil and bitumen. In this process, the injected solvent diffuses into the heavy oil/bitumen, reduces its viscosity, and drains it to the producing well. The VAPEX process is more acceptable than other processes because of its environmental friendliness, low capital and operating costs, and suitability for thin reservoirs.
Most of the efforts in the modelling of the VAPEX process have concentrated on the application of fluid-flow equations to the solvent and the diluted oil inside each gridblock used in the simulation of the VAPEX. This is adequate when very fine gridblocks are chosen to simulate the process in which the boundary layer (transition zone) occurs over a number of gridblocks. Fine gridblocks, however, require a large amount of simulation time, which is not applicable for field-scale simulation even with today's computing power. To deal with this problem, a new approach is introduced that is based on the application of the fluid-flow equations to three phases: solvent, diluted oil, and heavy oil/bitumen. With this approach, it becomes possible to have mobile solvent, mobile live oil, and immobile or slow-moving heavy oil/bitumen inside a gridblock. The main feature of the proposed model is its ability to capture the boundary layer within a gridblock, making very fine gridblocks unnecessary in the simulation of the VAPEX process. In addition, this approach can be applied to model the viscous fingering inside gridblocks.