bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Approach for Optimization of Long Horizontal Wells’ Performances
Authors: Al Qahtani Abdullah , Al Hashim Hasan , Al Yousef Hasan 
Published: December 2015

AbstractInitially, it was believed that a horizontal well should be drilled as long as possible. This was motivated by the advancements in horizontal well drilling, which allows horizontal wells to be drilled several thousands of feet long. However, field experience and flow meter surveys in long horizontal drain-holes revealed that the frictional pressure loss in the wellbore is an important factor limiting the effective length of long horizontal wells and consequently hindering the full use of the entire length of the horizontal wells. Flow meter surveys revealed that the productivity of long horizontal wells is not proportional to well length because the increase in the length of horizontal section results in significant frictional losses in the wellbore. The frictional pressure losses may be comparable with the drawdown at the producing end of the well rendering a portion of the horizontal drain-hole unproductive.This paper presents a new approach to maximize the use of the full length of long horizontal drain-holes by producing these long horizontal wells from both ends (heel and toe) and/or intersecting the second half of the horizontal well at an optimized location. This approach is supported by development of a rigorous semi-analytical model for the transient pressure analysis and well productivity evaluation for the horizontal well producing from both wings at the desired rates from both wings. The model incorporates the impact of wellbore hydraulics into the solution and used to calculate the flux distribution and pressure profile along the horizontal section. The developed model can also be used to evaluate the impact of reservoir parameters on the horizontal well performance. Furthermore, the model can be used as an optimization tool to optimize the production of long horizontal well by producing the well at the desired flow rates from both wings. Also presented, are some results showing the impact of wellbore hydraulics on the flux profile along the horizontal wells. These results show that the flux profile is a function of combination of reservoir flow characteristics and well conductivity. Wellbore hydraulics changes the flux distribution (flow ingress profile) along the wellbore and, thus, results in additional pressure drop in the well. The proposed method is found to be superior to the conventional horizontal well in terms of productivity and flux profile.
First True Two-Stage Cement Treatment Using an Expandable Liner Hanger
Authors: Jaramillo Andres , Jackson Tance 
Published: December 2015

Abstract
As wells increase in complexity, new challenges must be addressed in order to produce hydrocarbons in the best way possible. Some wells should be cemented in two stages because of the risks of fracturing the lower zone. Running a long casing string increases the equivalent circulating density (ECD) and also increases the chance of damaging that zone, so running a liner is the best option.
Cementing liners in two stages has been performed with conventional liner hangers for some time because of their capability to run an inner string and their capacity for manipulation after the hanger is set. Now, new technologies allow those treatments to be completed with expandable liner hangers (ELH).
The ELH provides a premium liner top seal (Williford, Smith, 2007) and excellent tensile capabilities. They also help to improve the cement bond by allowing the movement of the string while the cement is being pumped in place. ELHs have proven to be a reliable tool (Jimenez, C., et al., 2009), and every year their popularity increases tremendously.
This paper discusses the first true two-stage cement job with an ELH performed in Kazakhstan. The use of the ELH helped the operator reach total depth (TD), cement the two zones without issues, and create a premium barrier at the top of the liner.
Reservoir Filling Paths Revealed By Kinetic Modeling of Biodegradation at Basin Scale
Authors: Haeseler F. , Levache D. , Lamirand B. 
Published: December 2015

Abstract
This paper presents a methodology contributing to describe the filing of petroleum reservoirs based on the quantification of fluid alteration processes.
Biodegradation of hydrocarbons in oil reservoirs is one of the important alteration processes of petroleum. Described by Bastin in 1926, it is a widespread mechanism. Hydrocarbon degrading microorganisms have been found until 4 km depths and temperatures ranging up to 80 °C . The alteration of oil leads to an increase of sulphur and metal compounds, and also to the increase of acidity, viscosity and density. The level of biodegradation is classically described by the presence of biomarkers presenting specific resistivity to biodegradation (Peters and Moldowan, 1993). Haeseler et al. proposed in 2010 a quantitative numerical model based on stoichiometric equations, describing, step by step, the evolution of hydrocarbon composition and physical properties in biodegraded oils.
This tool was applied successfully to different African Basins (Lower Congo Basin, Niger Delta Basin and Albert Lake Basin) showing excellent correlation between the computed and the analysed composition of oils presenting increasing biodegraded grades. The biodegradability coefficients of the different hydrocarbon classes were shown to follow always the same rules. In the present paper, we applied the dynamic version of this model. In addition to the compositional data, parameters provided by Basin simulators like expulsion history from the source rock, reservoir temperature curves, reservoir volumes… were integrated. Applied to a biodegraded play located offshore Africa, this biodegradation model allowed various parameters describing the filling history of the Oligocene and Miocene reservoirs to be determined:
total quantities of hydrocarbons lost by biodegradation,
total quantity of methane generated. This allowed to calculate the methane losses over geological times by taking into account presently measured GOR and GOR expected from the numerical simulation,
gas loss fluxes: providing a geological description of reservoir sealing efficiency,
the kinetic parameters of the biodegradation for each compound class,
oil filling path in the reservoirs. The oils from the Miocene reservoirs must have previously been stored (and altered) in the Oligocene reservoirs. A direct arrival in the Miocene reservoirs from the source rock was excluded,
the storage time of the oils in Oligocene and Miocene reservoirs.
This multidisciplinary work allows to be optimistic about the possible existence of a general law governing the kinetics of the biodegradation and applicable for sedimentary Basins. It also showed that a qualitative and quantitative description of an oil alteration process contributes to a better understanding of fluid paths and the nature of fluids in place. It builds a strong scientific base for the description of fluid differences at reservoir scales that can be applied for various geochemical applications.
Challenges in Uncertainty Management: Scenarios vs. Realizations and Their Impacts on Projects - How to Deal With That?
Authors: Tawile E. , Schirmer P. , Rolando J-P 
Published: December 2015

Abstract
In an uncertainty evaluation process, making sure that critical uncertainties are captured is crucial. This paper aims at showing the difficulties in defining critical uncertainties because 1) definitions are not necessarily clear and 2) capturing the whole range of uncertainties is impossible. Indeed, if we place ourselves in the appraisal and development screening phase of an E&P project , the main objective is to reduce uncertainties and hence risk to an acceptable level which then allows triggering investments in such a project.
Shallow Geohazards Assessment Study for Field Development Projects, Lake Albert Basin
Authors: Matovu G. R. , Kibirango J. , Bidgood T. , Busingye L. , Cryan J. , Dawson K. 
Published: December 2015

Abstract
This paper presents the use of good quality field appraisal data to assess the shallow geohazards in locations planned for development well pads placement. For any hydrocarbon development, understanding the integrity of the surface and near-surface is important in the decision process of well pad placement and pipeline routing. The objective of this study was to assess risk of surface faults and the presence of shallow gas below the proposed surface facilities locations using available good quality 3D seismic, a high resolution digital elevation model and gas log data to analyse the shallowest 150m of the overburden in the development project area. The project area lies in the northern extent of the Albertine Rift basin, a tectonically active intracontinental rift system, with seismic activity in the region of 800 events per month.
By detailed interpretation and analysis of the 3D seismic, the study provided an insight into the structural architecture of the near surface and occurrence of shallow gas. The seismic data was of such high quality that attributes such as Variance and Dip Azimuth were used to interpret both basement and sediment propagating normal faults that extended to surface. The majority of the faults were found to align with changes in the surface topography or drainage pattern seen on the high resolution digital elevation model. Using a fault proximity zone of 200m the pad locations were categorised with regard to probability of surface fault hazard, as low, medium or high risk. Out of the 27 well pads that were screened, 5 pads locations were found to be in the high risk category, with proposed pad locations falling within the defined 200m fault proximity. This formed an important decision criterion on choice of the surface facilities location.
The work has demonstrated and identified high risk areas due to shallow faulting, with resulting pad moves whilst ensuring that environmental and social impact is minimised. In the studied area, no anomalously bright amplitudes were seen on the seismic in the shallow section. Also from the gas logs, no shallow gas was encountered in all 25 the exploration and appraisal wells in the area. The findings will also be taken into account in the pipeline routing process in order to minimise the traverse of major faults.
Development of the hydrocarbon resource in the project area will involve drilling of about 200 wells and hundreds of kilometres of excavation for inter-field pipelines. Use of the 3D seismic has demonstrated to be effective in this setting with early detection of high risk areas due to near surface faults. This desktop study resulted in a significant reduction of the scope of additional surveys and therefore a significant reduction in the cost of pre-development.
Analysis of Reservoir Scale Fracture Sets in Southern Italy's Carbonate Reservoir Analogues, Monte Faito, Sorrento Peninsula (Southern Italy)
Authors: Corradetti A. , Girundo M. , Tavani S. , Iannace A. , Parente M. , Mazzoli S. , Strauss C. , Torrieri S. , Pirmez C. , Giorgioni M. 
Published: December 2015

Abstract
Hauterivian-Barremian dolomitized carbonates of the Monte Faito ridge (Sorrento peninsula, Italy) rep-resent a good analogue for the Lower to middle Cretaceous portion of the reservoir units of the Southern Italy oilfields. In order to gain a better understanding of the distribution of reservoir-scale, flow-controlling ‘fracture corridors’ and of the nature of the mechanical boundaries con-trolling their vertical propagation, an integrated sedimentological, petrographic and structural study has been performed on a 200 m-thick succession of alternating dolostones and limestones. The fracture analysis, performed on a 3D model generated from photogrammetry with the help of an Unmanned Aer-ial Vehicle, identified a clear mechanical stratigraphy for large-scale fracture corridors and fault damage zones. The following stratigraphic survey established that the position of the main mechanical interfaces is controlled by: (i) tens of meters-thick bed packages dominated by fine- to medium-grained dolomite abutting a package of thick calcareous or calcareous-dolomitic beds; and (ii) packages of thin laminated dolomitic beds, representing thinning upward cycles deposited during the late highstand of lower order cycles. The rather regular stacking pattern resulting from the superposition of several orders of shallow-ing-upward cyclicity may be used to obtain a predictive tool for fracture distribution and impedance.
The Importance of Chemical Compatibility in Corrosion Inhibitor Performance
Authors: Xiong Y. , Li C. , Desai S. , Pacheco J. , Ciecko E. , Orhue D. , Mboho E. U. , Monahan C. 
Published: December 2015

Abstract
An important element that is often overlooked during chemical qualification and application is the compatibility between oilfield chemicals (OFCs), which can critically impact the ability of the chemicals to meet their desired function in the field. In the area of corrosion control, one important example of this is the interference of oilfield chemicals on corrosion inhibitor effectiveness. In this study, we aimed to identify the primary sources of inhibition failure during the simultaneous use of a corrosion inhibitor with scale inhibitor, drag reducing agent, and biocides under particular field conditions. Results show that one type of biocide completely rendered the corrosion inhibitor ineffective, while other OFCs had no significant impact on corrosion inhibition. The findings in this study highlight the necessity for chemical compatilibty checks during corrosion inhibitor qualification, or when there is a change in other OFC formulation/application, to ensure proper corrosion protection is maintained. Additional work is ongoing to improve the fundamental understanding of chemical compatibility.
A Portfolio of Commercial Scale CCS Demonstration Projects
Authors: Maas W. , de Nier M. , Wiwchar T. , Spence B. 
Published: December 2015

Abstract
Shell is progressing a portfolio of commercial-scale carbon capture and storage (CCS) demonstration projects covering an array of technologies that target applications of close relevance to the wider oil and gas industry. The portfolio includes projects such as Peterhead, Quest, Technology Centre Mongstad and Gorgon. A number of key learnings on both the technology deployment and critical project development aspects for the different project phases have been obtained. This paper provides an overview of these learnings with a specific focus on the issues faced by CCS project developers.
CCS is currently recognised as the only technology available for mitigation of carbon emissions from large-scale fossil fuel use. Before the process can be widely adopted it must be demonstrated at scale end-to-end. Learnings for all different project phases from early assess through to operations of these demonstrators need to be captured and communicated. As additional facilities to existing hydrocarbon operations, CCS projects require an approach similar to the development of other oil and gas projects.
To help enable and support other CCS projects, Shell is also committed to knowledge sharing from the projects, often agreed as part of the Knowledge Management provisions of the projects.
One of the key observations provided from the demonstration portfolio is the need for regular and informative engagement with both the public and regulators as the project progresses. Early and successful demonstrations can provide the evidence required for regulators, project developers and the public to have the confidence to proceed with future CCS projects.
It is also recognised that cost reduction will be key in driving commercial ‘deployability’ of CCS. The Quest and Peterhead projects are ideally placed to enable follow-on projects to learn and further reduce costs. The Shell portfolio of projects has also demonstrated that the drivers for technology optimisation can differ depending on the end user of the CCS technology. There is a need to demonstrate different technology aspects, for example flexibility or availability.
This talk will focus on how these issues are being addressed in two of the different projects within the Shell CCS portfolio, and highlight the key lessons learned. Furthermore, the cost-related issues of CCS will be addressed.
Innovative Drilling Methodology by Integrating an Advanced Simulation Approach for Recovery Optimization of Horizontal Wells
Authors: Salim D. , Couto P. , Alves J. , Freitas E. , Haq S. , Denichou J. M. 
Published: December 2015

Abstract
After the progressive advancement of the drilling technologies, such as mud motors and afterward rotary steerable systems, the successful execution of high angle wells became a common practice in the oil industry. Although the associtated costs have much superior magnitude when compared to the ones related to vertical wells, the production factor is normaly improved by multiple times, turning such trajectory design very suitable. However achiving the key performance objectives, e.g., consistent and effective net pay interval along the horizontal section, can be extremely difficult. There are many geological and geophysical reasons, such as the lateral discontinuities of the reservoirs and intrinsic seismic uncertainties. To overcome such challenge, Well Placement technique is used to interactively position the well based on geological and seismic criteria together with real time Logging-While Drilling data. Despite the fact of covering the technical disciplines of drilling, geology, petrophysics and geophysics, most Well Placement approaches rarely take into consideration reservoir engineering aspects when geosteering horizontal wells.
Therefore the project objectives were to evaluate the impacts in the productivity generated by the geometrical changes in the trajectory through numerical reservoir simulation. The research work was then divided into two parts. The first one was the creation of a representative 3D synthetic reservoir model where numerical simulations were applied for each trajectory design. A detailed sensitivity analysis was made by comparing the results among the different trajectory cases in order to identify the relationship between well positioning and its productivity response.
The second part consisted of a real geosteering case study. Around both planned and executed wellbores, it was created a detailed reservoir model enhanced by LWD inputs. Afterwards, reservoir simulations were performed in order to evaluate the impacts caused by trajectory variations, demonstrating the expected productivity results versus the actual.
This research study shows that there is a productivity impact in all reservoir fluids when well trajectory is subjected to geometrical variations. Thus it reinforces that predictions related to reservoir production should not only be performed on planning stage, but most importantly during or after well conclusion using relevant inputs, such as the actual well path, LWD logs, and formation pressures while drilling, which all combined provides an enhanced reservoir model, and so a more accurate forecast analysis.
Successful Startup And Operation Of World Scale Fully Integrated 1.1 BCF AGRU & TGTU For The Giant Qatargas LNG Plant
Authors: Normand L. , Streicher C. , Laborie G. , Perdu G. , Al Hatou O. I. 
Published: December 2015

Abstract
Qatargas Operating Company Limited (QATARGAS) has executed a major debottlenecking of its existing facilities at QATARGAS 1. This Project is known as the Plateau Maintenance Project (PMP). Its purpose is to maintain the Liquefied Natural Gas (LNG) production, while coping with increased levels of H2S and CO2 in the inlet feed gas streams. Revamp of LNG trains adds new pretreatment AGRU, upstream of the existing gas sweetening facilities an additional Sulphur Recovery Unit (SRU) and Tail Gas Treatment unit (TGTU).
This paper details the challenges of the PMP project which involves the construction of an additional Acid Gas Removal Unit (AGRU) treating in a single train 1,100 MMSCFD of natural gas, an associated Sulphur Recovery Unit (SRU) and Tail Gas Treatment Unit (TGTU) within the minimum plot area allocated to the green field part of the Project. It focuses on the AGRU with integrated amine section of TGTU which was considered as the most effective solution to install a new compact plant inside the existing facilities of QATARGAS 1 LNG plant in Ras Laffan, Qatar.
The design selected by QATARGAS after an international bidding phase uses the AdvAmine™ MDEAmax technology based on open market MDEA solvent. This reliable and original design features a fully integrated AGRU + TGTU amine section unit that meets multiple process requirements with high operational flexibility: jointly to H2S and CO2 removal specifications assigned to the 1,100 MMSCFD inlet gas, the plant cleans up the H2S from tail gas installed downstream the new 880 tpd SRU to meet the environmental emissions regulation. It secures the H2S, RSH and BTX content in the acid gas (by a dedicated preflash column) in order to satisfy the design of the SRU furnace section. The final acknowledged benefit of this giant unit is the decrease of the solvent circulation and of the solvent regeneration duty achieved by the recycle of semi lean solvent from TGT column to HP absorber.
Performance tests took place at the beginning of 2015 and all the guarantees associated with the operation of AGRU and TGT Amine section at design & turndown capacities have been demonstrated without operational issues. Operators have reported the simple management of the acid gas H2S content by the preflash column, the easy adjustment of the AGRU and its stability.