bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Technology Provides Zonal Pressure Maintenance in Single Trip Multizone Completions
Authors: Hamid Syed , Jannise Ricki , Garrison Greg , Coffin Maxime 
Published: October 2017

Abstract
This paper describes the development and testing of an innovative downhole zonal pressure maintenance device (PMD) developed for open and cased hole well completions. This PMD will be deployed as an integral tubular component in a generation IV single-trip multizone sand control system (STMZ) currently run in deep water and in other unconsolidated soft-rock applications. It will significantly increase the system's capability and provide proven time-saving benefits of such technology into the soft-rock formation arena.
Typical generation IV systems currently used isolate the discrete zones from one another and the wellbore. The operational steps include setting the top-most packer first. This process isolates the zones from the hydrostatic overbalance pressure, creating an opportunity for uncontrolled crossflow among zones with differing bottomhole pressures. This crossflow can, and will, move hydrocarbons as well as formation sand into the wellbore therefore certain limitations are placed on the existing STMZ system. The PMD maintains the initial hydrostatic pressures on each zone independently to help prevent uncontrolled crossflow and its detrimental effects. The PMD construction is totally mechanical and fully autonomous, not requiring any signals from the surface for its operation. It has built-in intelligence to sense the array of initial hydrostatic pressures in various zones and to store them for subsequent use.
Prototype tools were developed and tested in the laboratory, simulating near realistic multizone completion operations. The PMD design enables the amount of fluid leakoff into the formation to be minimized, thereby reducing formation damage. This capability is accomplished by automatically adjusting the PMDs to the respective zones to reflect the individual differences in reservoir pressure; it is particularly useful for completing wells wherein significant differential pressure exists between compartments because of the depletion that has occurred in some reservoirs.
The paper illustrates expected results on a multizone completion and displays the pressure maintenance behavior resulting from the use of this device.
Tests were conducted in the laboratory to validate the tool performance under extreme conditions of high leakoff rate in conjunction with an abrasive fluid with plugging tendency (oil-based mud). Another condition simulated relatively high pressure differential (2,000 psi) while reversing out after a "frac pack" operation.
The tool design incorporates state-of-the-art technologies, such as 3D printing and hydraulic miniaturization using implementation techniques unique to oilfield applications. Generation IV single-trip multizone system technology has been a key enabler for formations, such as those found in the Lower Tertiary of the Gulf of Mexico. The PMD provides a novel tool to extend these multizone applications to unconsolidated formations and to multizone reservoirs with high reservoir pressure differentials.
Injection and Remote Real-Time Monitoring: Slurry Injection Case Study, Onshore USA
Authors: Guo Y. , Mohamed I. M. , Abou-Sayed O. , Abou-Sayed A. 
Published: October 2017

Abstract
Remote life monitoring of field operations, such as injection, has been very restricted although real-time data is often collected at field sites. The difficulties lie in the data access and limitations to obtain computing resources for data analysis, which restricts the engineers' abilities to provide useful and timely remote assessment and assurance to the operations. Cloud computing combined with web-based apps, however, makes it much easier and cheaper to remotely monitor field operations and parameters in real-time from anywhere around world.
The current work provides our first attempt to apply the cloud computing and web-powered apps to monitor slurry injection at one injection site in Texas, USA. The site provides real-time injection data including flow rate and surface treating pressure, as it is recorded and stored automatically in a cloud database. The data can then be accessed and analyzed through a web-based app from any web-enabled device. Monitored injection pressure and rate, provide the basis for pressure fall off analysis to evaluate injection formation pressure and stress change, estimate fracture skin, and determine injection-induced fracture geometry at the end of each slurry injection batch. If the fall off analysis yields an unanticipated fracture geometry, advanced fracture simulations would be conducted to model fracture growth in three-dimensions under real injection conditions in order to gain a better understanding of the effects of a specific injection on fracture geometry.
The real-time monitoring of the slurry injection is a critical component for the long-term assurance of fracture containment and injection well integrity. The results of remote real-time data analysis set up early warnings to alert both onsite and offsite staff ahead of operational upsets. The analyses are also critical to optimize injection parameters, maximize injectivity, extend well life and minimize risks of creating unexpected fractures.
Compared to traditional desktop applications and isolated local data servers, cloud computing and web-based apps provide a more convenient and cost-effective way to monitor field operations in real-time. The technique and workflow presented here may be also applicable to monitor other field operations, such as drilling, water injection and production.
Gas Injection for GOM Deepwater Wilcox Trend Fields Development: Challenges and Recovery Potential
Authors: Oghena Andrew , Zhou Dengen , Fitzmorris Robert , Chawathe Adwait , Colina Julio De , Orribo Jose , Gentry Michael 
Published: October 2017

Abstract
Huge oil resources have been discovered in the Wilcox Trend fields of Deepwater Gulf of Mexico (GOM). The Wilcox Trend fields are ultra-high pressure and high temperature, highly undersaturated, low permeability reservoirs typically with moderate to high oil viscosities. As a result of the unfavorable rock and fluid properties coupled with anticipated large well spacing due to high well cost, the estimated primary recovery factor with artificial lift is on the order of 10 – 15%. Incremental recovery factors from water injection are forecast from 2 – 5% due to anticipated limited injectivity increasing the total oil recovery factor (primary plus secondary) to 12 – 20%. Miscible gas was thoroughly studied to determine if it could significantly increase the oil recovery factors forecast for secondary recovery.
We have carried out detailed miscible gas injection studies for six Wilcox Trend fields. Results from these field case studies demonstrate that miscible gas injection has the potential to increase the total oil recovery factor to 15 – 25% or 5 – 10% incremental above that forecast for primary depletion with artificial lift. The increase in the oil recovery from gas injection is from the improved reservoir processing rates and high local recovery efficiency of miscible displacement processes. In addition, the increase in oil recovery is due to higher oil production rates because of gas injection supporting reservoir pressure and providing natural gas lift. The GOM Wilcox field gas injection displacement process will be implemented as a secondary recovery process (before waterflood) rather than tertiary method (after waterflood).
This paper will report a new systematic workflow for integrating ultra-high pressure laboratory PVT and slim tube data and high resolution mega static earth-models into compositional reservoir simulation models for assessing gas injection displacement processes in these reservoirs. Wilcox reservoir simulation performance results will be presented for primary depletion with artificial lift, water flooding, gas injection, and gas followed by water injection and vice versa. The major uncertainties and their effect on incremental oil recovery from gas injection, resolutions to barriers to Deepwater gas injection projects, and key enabling technology developments for the ultra-high pressure miscible gas injection process will be discussed. We will end our presentation with a description of future plans for a number of GOM Deepwater Wilcox trend fields under consideration for gas injection development.
Production Optimization of Shenzi Field in the Deepwater Gulf of Mexico
Authors: Ashton P. , Cooper D. , Akajagbor C. , Politte J. , Lo S. 
Published: October 2017

Abstract
A 20% increase in production rate was achieved through a production optimization program in the Shenzi field in the deepwater Gulf of Mexico at little to no cost. The Shenzi Field lies approximately 120 miles from the Louisiana coast in the Gulf of Mexico. It was discovered in 2002 and first oil was produced in 2009 from the Shenzi TLP.
In 2012, the production engineering, surface engineering and operations teams initiated a production optimization program to maximize the production from existing well stock. Production optimization was achieved through a number of key activities including: advances in asphaltene management, gas lift and well configuration optimization, minimum bottom hole pressure reduction and deferral reduction.
Using integrated production modelling as the primary evaluation tool, each opportunity was evaluated technically and economically. Asphaltene management was improved through real time detection of asphaltene deposition, which allowed adjustment on inhibitor rates to reduce cost and timely treatments. Automatic well configuration modelling allowed for optimized production scenarios and gaslift injection rates. Validating completion limits ensured drawdown on wells were maximized. Development of more efficient well test programs ensured accurate well data while reducing deferrals. Field production was increased by 20% by executing these activities for minimal additional cost.
This paper summarizes a novel use of integrated production modelling techniques in real time in order to evaluate and implement key optimization activities. A variety of data will be presented including the identification of opportunities using modelling outcomes, optimization process and production improvement realized.
Design and Operational Experience with Horizontal Steam Injectors in Kern River Field, California, USA
Authors: Buell R. S. , Gurton R. , Sims J. , Wells M. , Adnyana G. P. , Shirdel M. , Muharam C. , Gorham T. , Riege E. , Dulac G. B. 
Published: October 2017

Abstract
A horizontal steam injection pilot project has been underway for the last four years in the Kern River heavy oil field located in the southern San Joaquin Valley of California. This pilot project was designed to address the following four prioritized learning objectives for horizontal steam injection in a mobile heavy oil reservoir, which were:What is the mechanical reliability and operability of horizontal steam injectors?Can acceptable steam conformance control along the horizontal section be achieved?Can steam conformance along the horizontal section be quantified with surveillance?What is the reservoir response and longer-term operability with horizontal steam injection?
The 12-acre pilot area on the northwest flank of section 24 of the Kern River field was equipped with two horizontal steam injectors and nine vertical producing wells. The pilot area also had 12 vertical temperature observation wells (TOW) to understand steam conformance around each of the injectors and in the far-field reservoir. The TOWs were logged frequently to establish temperature trends. Based upon temperature trends steam identification and saturation logs were also acquired periodically.
Five injector completions of increasing complexity were installed to understand the injectors' mechanical integrity, recovery of flow control devices, performance of isolation packers and fiber optic surveillance systems. A history-matched reservoir simulation model with coupled wellbore hydraulics was used for forecasting throughout the project life to conduct operational sensitivity analysis and to improve reservoir characterization. Fiber optic flow profiling methods were developed in the injectors that were validated with the observation wells and reservoir models. During each workover torque and drag measurements were acquired which were analyzed with both soft and stiff string analysis to understand wellbore mechanical conditions in the horizontal section. After each workover, all available reservoir and workover surveillance data, TOW logs and production and injection well information were used in a multidisciplinary review to understand progress against the four prioritized learning objectives. The performance of offsetting traditional, vertical steamflood developments were also evaluated.
Chemical Flooding in Low Permeability Carbonate Rocks
Authors: Ghosh Pinaki , Sharma Himanshu , Mohanty Kishore K. 
Published: October 2017

Abstract
Waterflood in low permeability carbonate reservoirs (&lt;50 mD) leaves behind a substantial amount of oil. Alkali-surfactant-polymer (ASP) floods can improve oil recovery from these reservoirs by lowering the interfacial tension (IFT); however, there are several challenges such as polymer injectivity, divalent ions, geochemical interactions, pore-scale heterogeneity, and oil-/mixed-wettability. This paper addresses the first two challenges: polymer transport in low permeability carbonate cores and surfactant interaction with formation brine during ASP floods. Since polymer injection in low permeability carbonate cores is challenging, polymer transport in low permeability carbonate cores was studied. Shearing of high molecular weight polymers and successive filtration treatment were performed to reduce the polymer size distribution. Single phase polymer corefloods were performed to study the transport of treated polymers and identify the optimum pretreatment. Phase behavior experiments and aqueous stability experiments were performed to develop ultralow IFT surfactant formulations with a reservoir crude oil. ASP corefloods were performed in oil-wet low permeability limestone rocks. The oil recovery, pressure drop, effluent ionic composition, effluent viscosity and effluent surfactant concentrations were measured. Polymer hydrodynamic radius must be much smaller than the pore throat radii for the polymers to be transported. Mercury porosimetry data should be studied before polymer selection. Shearing and successive filtration can be used to reduce the hydrodynamic radii of polymers. This preprocessing worked with the HPAM polymer used in this study for the Edwards Yellow Limestone, but not for Texas Cream Limestone. An ultralow IFT ASP formulation can be developed with a formation brine with a significant amount of divalent ions by using a chelating agent. Tertiary ASP injection increased the cumulative oil production to 77% in a field core and 87% in an outcrop core. The adsorption of the anionic surfactants was limited to 0.4 mg/gm of rock in the core floods. UTCHEM simulations showed good agreement with lab coreflood experiments.
Eliminate Decision Bias in Facilities Planning
Authors: Cristea Z. , Cristea T. 
Published: October 2017

Abstract
The paper asserts that traditional Facilities planning methodologies, heavily based on Design Basis documents and biased towards the ‘most conservative conditions’, fail to recognize the entirety of operational conditions throughout the oilfield lifecycle, leading to significant residual risk and the wastage of resources in the Operations stage. An integrated stochastic approach is proposed, accounting for both subsurface and surface uncertainties and their interrelations throughout the field life. A practical example is also provided.
The proposed methodology employs Big Data algorithms to quantify subsurface and surface uncertainties and produce Probability Distribution Functions (PDF) for all relevant variables. Data sources are diverse, normally available in a project team, and may include geological and reservoir models and production forecasts, PVT reports, nodal and network analyses, and environmental databases. The relevant variables are expected to change throughout field life with different levels of uncertainty, due to planned and unplanned events such as condensate banking, lean gas injection for pressure maintenance, water breakthrough, etc. Stochastic algorithms (e.g. Monte Carlo method) are then applied on the deterministic model, randomly sampling from the previously defined probability distributions. Results are summarized as Tornado charts and spider or scatter plots, which are then used to analyze the most relevant variables and correlations affecting the objective function.
The provided example results indicate the risk is still present in 9% of cases for the original, deterministic design. Furthermore, resources are wasted in 76% of cases. In the integrated stochastic design the risks and wastage are reduced down to a range of 0 to 1%. The associated OPEX components are reduced from USD 3 mln to USD 1 mln (-66%), expressed in Present Value terms. An unquantified increase in system availability is also noted.
The paper demonstrates the utility of integrated, stochastic approach in Facilities planning, accounting for both subsurface and surface uncertainties and their interrelations throughout the field’s life. This approach eliminates the Design Basis induced bias and enables superior decisions at Project and Asset levels. The proposed approach is scalable, transferable to other oilfield challenges, and it is suited to multidisciplinary work environments.
Multiscale Modeling of Shale Apparent Permeability: An Integrated Study of Molecular Dynamics and Pore Network Model
Authors: Wang Sen , Feng Qihong , Javadpour Farzam , Zha Ming , Cui Ronghao 
Published: October 2017

Abstract
The physics of gas transport through shale systems is still ambiguous, even though several theoretical and experimental works have been reported. Most of the existing studies only concentrate on the permeability of shale kerogen. However, shales are composed of various amounts of organic matter and inorganic minerals (e.g., calcite, clay, and etc.). Inorganic pores could be larger than organic pores, hence, affect apparent permeability.
To accurately predict shale apparent permeability, we couple molecular dynamics (MD) and a pore network model (PNM) to develop a multiscale framework for gas flow through shales. First, we use non-equilibrium MD to study the pressure-driven flow behavior of methane through organic, calcite, and clay (montmorillonite) nanopores under subsurface conditions, from which we build modified Hagen-Poiseuille equations to characterize the overall conductivity of each pore. Then we incorporate these formulations into a shale pore network model, in which the impact of shale composition and bimodal pore size distribution (PSD) are taken into account.
Molecular dynamics simulations show that the streaming velocity of supercritical methane in an organic nanopore exceeds the prediction of Hagen-Poiseuille equation by orders of magnitude. However, methane exhibits a slightly enhanced flow in comparison to Hagen-Poiseuille equation in inorganic pores, which can even be ignored if the diameter of inorganic pore is larger than 10 nm. On the basis of these simulation results, we modify Hagen-Poiseuille equation to estimate hydraulic conductivity of methane through nanopores with different material types. We construct the multiscale pore network model conditioned to total organic carbon (TOC) and mineralogical composition. The pore/throat size ranging from nanometer to micrometer scales are assigned according to the pore size distributions in organic matter and inorganic matrix separated from nitrogen adsorption results. We validate our PNM model results with experimental data published in literature. We conclude that the pores located within inorganic matrix show a more pronounced effect on the shale apparent permeability than those associated with kerogen. We further examine the influence of TOC, pore network connectivity, mean pore size, and etc.
Using molecular dynamics and pore network model, this work presents a multiscale framework that accounts for distinct pore size distributions and fluid transport properties in organic matter and inorganic matrix. In comparison with previous methods, our proposed model highlights the effect of inorganic matrix owing to their greater pore sizes. This work provides an efficient tool to better understand gas transport through shale systems at both molecular scale and pore scale.
Combining Passive and Autonomous Inflow Control Devices in a Tri-Lateral Horizontal Well in the Alvheim Field
Authors: Langaas Kåre , Jeurissen Emile , Hailu Kebede Abay 
Published: October 2017

Abstract
This paper describes the analysis, test and design work to deliver an optimum lower completion for a tri-lateral well, by integrating autonomous and passive inflow control devices (ICD), in the Alvheim field offshore Norway. Chemical tracers, permanently installed in the completion, enabled the evaluation of inflow performance in each lateral. This continues to give valuable information to assess whether the tri-lateral completion is performing as predicted, improves reservoir characterisation and guides reservoir management decisions.
In 2015, both passive and autonomous inflow control devices (AICD) were tested in the laboratory with Alvheim fluids at reservoir conditions. The experimental flow testing, reported in this paper, demonstrated that the AICD chokes gas more efficiently than the passive ICD, but also that the strength of the AICD were lower than expected a priori. The experimental results were used to model the AICD correctly and establish a lower completion strategy as follows: where the well was close to the overlying gas cap, AICDs should be used, while passive ICDs with variable strength were to be used elsewhere to optimise the inflow.
Steady-state inflow modelling was performed before the drilling operation and updated accordingly with the as drilled information. The lower completion design for each branch focused to get what was estimated to be an optimal inflow based on oil volume in place. A key uncertainty in the design work was whether shaly zones along the wellbore would creep/collapse with time and act effectively as packers or not. The lower completion covered around 7 km of reservoir penetration in the three branches, and 15 unique oil tracers were installed to evaluate the clean-up and the inflow profile along the well. The well started producing in May 2016 and downhole flow control valves enabled a successful clean-up, as confirmed by oil tracer responses. In addition, a restart tracer sampling campaign was done after a 12-day shut-in, in August 2016, and this formed the basis for a "chemical production log". The tracer based inflow interpretation is compared quantitatively with the model predicted inflow and qualitatively to the tracer responses seen during the clean-up. This gives valuable feedback to the completion design, and assist in understanding the various degrees of pressure support and if the shaly reservoir sections have creeped/collapsed or not.
The well has exceeded pre-drill production expectations, with an average oil rate of 3375 Sm3/d (21240 stb/d) during the first production year. This is a consequence of higher than expected NTG, but is also partly a result of the lower completion design, where the focus has been to optimize the lower completion such that the whole well contributes, from the heel to all toes. To the knowledge of the authors, this is the first well in the world with a lower completion integrated with AICDs, ICDs and chemical tracers.