bluuebunny/crossref_metadata_2025 huggingface dataset:
Multilateral Wells in the Urucu Field of Western Brazil: Reducing Environmental Impact in the Amazon
Authors: Mendes Sandro , Albuquerque Marcelo , Vento Mario , Batista Nazildo
Published: June 2014

The operator assessed many technologies to increase production, and reduce costs while protecting the environment in the Brazilian Amazon. For this project, where access to likely well sites is restricted both by limited infrastructure and Brazilian regulations, the operator chose environmental impact as the primary factor in their decision process.

To address both environmental and production issues, the operator selected multilateral technology which minimizes the well site footprint yet allows for drainage of a much larger volume of the reservoir from a single surface location. This is a significant advantage when compared to the cost and environmental impact of drilling multiple wells or using large drilling pads.

The operator implemented this technology in the Urucu field, located 650 km southwest of Manaus, in the heart of the Brazilian Amazon. The field is made up of three reservoirs called ‘River Urucu’ (RUC), ‘East of Urucu’ (LUC), and ‘Southeast of Urucu’ (SUC).

The Urucu has 95 oil producing wells and 6 gas injection wells. The target formation is Jurua in the Paleozoic Solimões basin–a basin that includes an important petroliferous system called Jandiatuba-Jurua. The reservoir rock consists of eolian and marginal marine carboniferous sandstones.

This paper presents the results of a successful multilateral technology project in the Urucu field in which three TAML Level 4 dual-lateral wells were installed by the operator. Those wells had an average production rate of 1.75 times more than a typical horizontal well while spending only 1.42 times the average cost of the same.
Geomechanical Modeling of Wellbore Stability in Salt Formations
Authors: Wang Han Yi , Samuel Robello
Published: June 2014

Exploration drilling is venturing out into deeper regions of water. While exploring these deeper water depths, large hydrocarbon deposits have been found below salt formations. These reservoirs are located in formations called "pre-salts," which are located below the salt formations. Pre-salt reservoirs have been found in offshore Brazil, the Gulf of Mexico, West Africa, and the North Sea. Completions in salt formations can be difficult owing to the creep behavior that the salt formations exhibit. Creep behavior results from the instability of the salt formation, which causes a slow flow and permanent deformations. Creep deformation occurs over time and is initiated once the salt formation has been penetrated. Completion of the wellbore does not stop formation creep. The constant creep of the salt formation causes excess stress on the wellbore casing, which may eventually cause the casing to collapse. In this study, a 3D geomechanical model is developed, using data such as wellbore pressure and temperature, formation stress and temperature, rock, cement, and casing properties, to predict the effects of salt creep behavior on stress loading in the wellbore casing, which helps to assess the life expectancy of wells in pre-salt reservoirs. The simulation results of this model can provide quantitative results of casing stress and deformation as a function of time under various temperature, in-situ stress and operation conditions, that can be used as useful information for subsequent wellbore casing design and wellbore integrity analysis. In addition, possible methods that can mitigate the severity of salt mobility and reduce the risks of casing collapse are discussed.
Stress Redistribution Analysis in Multiple Eccentric Packers During Completion Operations
Authors: Zhang Yuan , Samuel Robello
Published: June 2014

Advancement in multiple zone completion has been quite rapid in recent years but it poses numerous operational challenges that adversely affect the efficiency of the completion process. In addition to increasing the number of activities involved in horizontal drilling, a lot of packers are used during completion which results in various problems during pulling out and running in. These problems include increased torque and drag and buckling. The increasing complexities of wellbore geometry imply an increasing potential for damage when running packers for completion operations.

In addition, hole diameters vary frequently during the drilling process. When the diameter of the casing changes, even though the production tubing size remains the same, the packer usually becomes eccentric. Current methods are not modeled properly and severely underestimate stress values and pick-up loads when completion strings are run in.

Normally, a packer is designed for central symmetry. When a packer is in an eccentric position, the stress in the packer gets redistributed to suit the eccentric condition. In addition, the pressure limitation is also changed. This study describes a new analytical model for estimating the stress distribution in eccentric packers by assuming that the packer material is elastic. This study concludes that when the packer is run into an eccentric wellbore, the stress distribution in the packer changes and the pressure limitation of the packer decreases. A methodology and a mathematical model have been developed to calculate the stress and the pressure limitation of a packer with an eccentric profile.
A Novel Forecasting Model for Chemical Flooding Enhanced Oil Recovery
Authors: Mollaei Alireza , Delshad Mojdeh , Li Zhitao
Published: June 2014

Chemical enhanced oil recovery (EOR) method includes the injection of a mixture of chemicals to improve sweep efficiency and produce residual oil saturation left behind in the swept volume after waterfloods. The way chemical flood works is by the synergistic effect of polymer to improve mobility (slow down the movement of water to match that of the oil, i.e., mobility ratio of 1) and surfactant (with or without alkaline) to reduce the interfacial tension between oil and water to displace the discontinuous trapped oil remained in reservoir after the waterflood. Surfactant flooding uses the same concept as using detergent/soap to remove oil. The primary objective of surfactant/polymer (SP) or alkaline/surfactant/polymer (ASP) flooding is to reduce the interfacial tension between oil and water to values on the order of 0.001 dyne/cm or less in order to displace the trapped oil from rock pores.

We present a novel method to predict the results of the chemical EOR processes using an analytical and robust forecasting model. This fast and simple analytical approach will aid to screen chemical EOR projects where numerical simulations are not feasible due to either lack of data or the time and expertise required conducting such studies.

The proposed forecasting model is based on a general approach for predicting the performance of isothermal EOR processes. The model incorporates fundamental principles of material balance, segregated flow and fractional flux while with effects of mobility ratio, chemical slug size, miscibility and reservoir heterogeneity. The permeability heterogeneity is modeled using Koval fractional flux model with its applicability to wide range of permeability and degree of heterogeneity. The forecasting tool has been successfully validated against numerous SP/ASP field and numerical simulation results.

We also developed correlations to describe the model variables as functions of mobility ratio, slug size and reservoir heterogeneity based on the experimental design methodology and numerical simulation. Successful history matching against numerical simulation results and the strength of the developed correlations proved the ability of the model to predict SP/ASP results when field results are not available.

The forecasting tool provides key results to assess the flood performance. These include average oil saturation, cumulative oil recovery, oil cut, oil production rate, recovery efficiency and volumetric sweep efficiency as functions of time. An estimate of volumetric sweep efficiency helps in a better design and increases the chance of successful field projects.
Fully Integrated Approach Using Temperature Measurements to Describe Complex Reservoirs: Case Study from Saudi Arabia
Authors: Al-Mutairi Saad , Alghazal Mohammed , Alhuthali Ahmed , Cole John
Published: June 2014

Reservoir heterogeneity and inter-reservoir communication due to fracturing pose major challenges for our industry in terms of reservoir characterization and fluid flow modeling. Improved understanding and representation of their role in static and dynamic models is becoming a pivotal component for effective field management. Normally, multiple sources of both static and dynamic information are integrated to generate models used to simulate reservoir performance in order to identify optimal practices for efficient production and recovery.

This paper presents a thorough reservoir study focused on the investigation of the use of temperature measurements to inform on fluid flow within and between reservoirs. The study addresses mainly the communication that exists in the reservoir beyond the well-bore, attributed to fracture corridors and faults. The interpretation of temperature measurements are integrated with other sources of dynamic and static information such as open-hole logs, production profiles, fluid losses, and pressure transient analysis. The study area covers a portion of an oil field that has been under peripheral water flooding for more than 30 years, producing mainly from the upper of the two reservoir units. As expected, the injected cold water imposes a significant variation in temperature profile across the reservoir which helps to describe the flood performance and understand the underlying geology. Additionally, we found that the rate of change of temperature with respect to time over the entire area shows that increasing temperatures are correlated with locations showing high structural relief. Our existing mapping shows these areas as being more densely fractured, with high fluid flow capacity. The coincidence of these factors with the temperature anomalies we observed strongly suggests that the faults and fractures in these areas may be responsible for mass and heat transfers between the two reservoirs.

The outcomes of this study are used to optimize development and production plans such as balancing the off-take between high-structure and down-dip areas to prevent undesired water flood advances. They are also fully integrated with other sources of information to construct geological and flow simulation models in order to assess sweep performance and recovery estimation.
The Condition of Capillary Condensation and Its Effects on Adsorption Isotherms of Unconventional Gas Condensate Reservoirs
Authors: Li Baoyan , Mehmani Ayaz , Chen Jinhong , Georgi Daniel , Jin Guodong
Published: June 2014

Traditionally, Langmuir isotherms are used as the adsorption isotherms of coal bed methane and shale gas. To model the adsorbed multi-components of hydrocarbons, the Langmuir isotherm for the single component is extended to the Langmuir isotherm for multi-components. A Langmuir isotherm is simple, but it is based on the assumption that the adsorption is a single molecule layer adsorption. Its adsorption mechanism is adsorption-site filling.

For shale gas reservoirs, the adsorption of gas could be multi-layer adsorption, because of the small sizes and wettability of nanopores in the kerogen source rocks. Particularly for gas condensate reservoirs, such as the Marcellus shale gas reservoir, capillary condensate could exist, due to the confinement of kerogen pores, i.e., the adsorbed gas becomes condensate to fill the pores at the pressure below the dew-point pressure. For capillary condensation, therefore, a Langmuir isotherm is not valid.

The conventional Kelvin equation can be used for computing the isotherm of capillary condensation. However, it is limited to the single component. We introduce a method, which is based on the generalized Kelvin equation, to compute the adsorption isotherms of capillary condensation for multi-component hydrocarbons.

This new computation method enables us to investigate the condition of capillary condensation and relation between pore size and condensation line. Furthermore, we check the capillary condensation effects on the adsorption isotherm caused by fluid composition, pore-size distribution, temperature, and pressure. We predict the phase behavior for the Marcellus shale reservoir. The computation results show: When the temperature is less than pore critical temperature (lower than the cricondentherm temperature), capillary condensation can occur.For shale gas formations, if the hydrocarbon composition includes some heavy components, capillary condensation can occur, depending on pore-size distribution, composition, and pressure.Large standard deviation of pore size will smooth the adsorption isotherm for capillary condensation.As pore size increases, capillary condensation occurs at pressures close to the dew-point pressure.Capillary condensation can occur in the Marcellus shale formations.
Managed Pressure Drilling, Casing and Cementing Enables Success in Conventionally Undrillable Wells in the Harding Field
Authors: Mashaal Mohamed A. , Fuller Tom , Brown Chris J. , Paterson Robert
Published: June 2014

Managed Pressure Drilling (MPD) has been used around the world to help drill wells where there is a tight mud weight (MW) window, due to the ability of the technology to more accurately control annular bottom hole pressure (BHP) while drilling, tripping and during connections. This paper presents the case history of the Harding PNE2a well design and execution in 2012, with particular focus on the planning process, design methodology and execution particulars associated with the use of MPD as the enabling technology to drill, case and cement the well. The team also employed a novel Fluid Pressure Transmission Pill (FPTP)i, composed of a cross-linked polymer, to maintain hydrostatic pressure while tripping BHAs and during deployment of the liner and sand control equipment.

Earlier attempts to drill Extended Reach Drilling (ERD) wells from the Harding platform to the PNE4 and PNE2 reservoir targets resulted in drilling issues including packoffs and severe lost circulation due to BHP departing from the tight window of useable mud weights between the pressures at which the formation is expected to collapse or fracture. Use of MPD on the PNE2a well directly contributed to achievement of the well's objectives, and the operation was able to provide good control of BHP throughout the well construction process, in both 12-1/4" and 8-1/2" sections. This led to the long unstable shale sections being maintained with no cavings being observed while drilling, a first for the field, and the cementation of the long 9-5/8" liner being performed without losses despite the tight operating window and the use of conventional cements.
Production Analysis in the Barnett Shale – Field Example for Reservoir Characterization Using Public Data
Authors: Pratikno H. , Reese D. E. , Maguire M. M.
Published: June 2014

Development of unconventional reservoirs continues to expand in North America and has gained interest worldwide. The first unconventional play to be rapidly developed is the Barnett Shale located in North Central Texas. As of July 2012, the Barnett Shale had more than 13,000 multi-staged fractured horizontal wells (MFHW) with approximately 2,500 of these wells with over five-plus years of production history. In addition to these MFHW, there are approximately 3,000 vertical wells in the Barnett Shale.

Well spacing is a key value driver for field development and needs to be addressed early in the appraisal process. Interpretation of early production analysis from MFHW can provide many insights into the reservoir and fracture characteristics of these wells. However, these interpretations are non-unique until end of linear flow (ELF) is reached. This study used public production data that lacks wellhead flowing pressures. For this study the wells that did see end of linear flow did so in a time period where flowing pressures are expected to be relatively constant and therefore having measured pressures was not deemed necessary. Reservoir permeability, fracture half-length, and original-gas-in-place of the area contacted by the created hydraulic fracture network can be determined once end of linear flow is reached. Once fracture half-length and permeability have been determined, the appropriate well spacing can be estimated using simulation and economics.

A comprehensive review of approximately 2,500 MFHW using public data within two Northern counties of the Barnett Shale found more than 100 wells where end of linear flow could be clearly observed in production characteristics. With the end of linear flow determined for these wells, estimates of permeability and fracture half-length were determined. A single well simulation study feeding an economic evaluation was then used to study well spacing and yield suggested optimum development spacing. This paper will review all of this work, the results and conclusions, and provide observations of some of the trends.
Front Line Leadership in the Oilfield
Authors: Horn Aaron D.
Published: June 2014

The United States has a path to energy independence through the economic development of domestic unconventional resources. At the same time, the oil and gas industry faces a generation gap as many baby boomers in leadership retire. Compounding the generation gap is the industry's general trend to promote people to leadership positions based on technical ability, assuming technical acumen will translate to leadership acumen. This paper puts forth a military-influenced model for leadership in the industry and provides analysis of the results of a survey regarding front line leadership.

Leadership is the art of influencing not only one's subordinates, but also one's peers and superiors in the accomplishment of a common objective. This paper proposes a model for effective front line oilfield leadership as the embodiment of five traits—self-awareness, humility, honesty, courage, and persistence—and the adoption of five habits— leading by example from the front, knowing your people, treating people as they can and should be, communicating effectively, and being decisive (but not in a vacuum). The focus is on leadership at the front line, where technical staff interacts with field staff to accomplish the mission. The oilfield relationship between technical staff and field staff is similar to that in the military, which is central to the author's argument for the proposed leadership model. The paper also summarizes a survey conducted of approximately 100 oilfield personnel, ranging in age, experience, job function, and organization type. The survey results provide insights into the current state of leadership in the industry, using the proposed leadership model as a guide for the assessment.

These findings support the author's three primary conclusions. First, there is a need for collective focus on core leadership principles to obtain the best, safest performance from a generationally lopsided workforce. Second, the survey offers multiple perspectives across a broad demographic regarding the relative importance of the leadership model's traits and habits and how they relate to one another. Finally, an analysis of survey data provides perspective on the conflicting perceptions regarding leadership between different industry demographics, most notably between executives, management, technical staff and field staff.

Should the industry continue on its growth trajectory, the lack of adequately trained leaders has profound ramifications, ranging from decreased capital efficiency to increased accident rates. Focus on the leadership ability of tomorrow's leaders should not wait until tomorrow.
Modeling and Prediction of Frac-Pack Tool Erosion
Authors: Lee Erik , Russell Ronnie , Williams Thomas , Carbone Frederick , Clem Nicholas
Published: June 2014

Reservoirs continue to push the envelope in frac-pack stimulation rates and proppant volumes. Consequently, the tools delivering these stimulations must be qualified using testing procedures that replicate actual job conditions, as closely as possible, to ensure the integrity of the tools when deployed in these challenging environments. High stimulation rates and large slurry volumes, which must be replicated in a testing environment, require an investment in assets and logistics on the order of that required for an actual deployment. Therefore, testing parameters must be selected based on those anticipated in the completion for which the tools are being qualified.

Several variables play a significant role in the erosion potential of frac-pack slurry, such as particle density, concentration, roughness and sphericity, velocity, angle of impact, fluid viscosity, and the metallurgy of the erodible material. Changes in each of these variables can produce significant variance in the amount of erosion caused by a frac-pack treatment and in understanding the contribution of each of these variables. While impractical in a full-scale testing environment, these variables can be quantified using numerical methods and complimentary erosion prediction models.

Data sets from lab-scale and full-scale tests have been used to develop and refine erosion prediction models as they relate to conditions typical of frac-pack applications. Results will be presented showing how newly refined erosion modeling can aid in the development of tool designs and further refine the prediction of the erosiveness of frac-pack slurries for applications that deviate from full-scale erosion testing conditions.
Using Connection and Total Gases Quantitatively in the Assessment of Shale Pore Pressure
Authors: Alberty Mark , Fink Kristi
Published: June 2014

Connection and total gas measurements have been used qualitatively for decades in drilling oil and gas wells to identify over-balanced, under-balanced or near-under-balanced pressure conditions (mud hydrostatic relative to shale pore pressure). Results often conflicted with sand direct measured pore pressures and the pre-existing perceptions of shale pore pressure. We propose a technique that allows mud gases to be used in a quantitative manner, given that: (1) there is an increased understanding of the relationship between mud gases and shale pore pressure, (2) the development of the LWD based annular pressure measurement allows real-time monitoring of down hole hydrostatic pressures, and (3) differences between sand and shale pore pressure may exist as a result of the sand's structural position.

This paper presents time-based ECD behavior of block movement, flow rate, and total gas from Gulf of Mexico wells, and explains the relationship to shale pore pressure. These examples are quantitatively analyzed for shale pore pressure. The results are compared to direct formation pressure measurements within the sands.

Six principles guide pore pressure interpreters on the quantitative use of mud gases. The principles define the pore pressure values assignment to specific mud gas observations as a function of recorded annular mud pressure. The pore pressure estimates in shale can be used as calibration points for traditional shale pressure indicators such as resistivity, velocity or Dxc measurements.

The result of this integrated technique yields an improved characterization of shale and sand pore pressures and it can be used as input for well designs to increase reliability, safety and improve drilling efficiency.
High Pressure Multi-Stage Centrifugal Pump for 10,000 psi Frac Pump - HPHPS FRAC Pump
Authors: Pettigrew Dana , Lillies Allan , Limanowka Andy
Published: June 2014

Field use and test results of an HPHPS (High Pressure Horizontal Pumping System), and how it is integrated into a frac fleet of 20 PD (Positive Displacement) conventional frac pumpers to support fracs in the Horn River Basin.

This HPHPS was successfully tested on leases in the Horn River Basin of North Eastern British Columbia to pump Debolt source water (a saline, sour and gassy aquifer) during frac operations in 2010 and 2011. This provided an alternative solution to a $50mm+ water treatment plant for supplementing fresh water volumes used for frac operations.

Fresh water is being extensively used for fracturing operations to stimulate both oil & gas shale wells. Once used for this purpose, the water is either disposed of, or needs extensive treatment to recondition it for further fracture operations. Operators in the Horn River Basin have access to a non-potable aquifer that is available for both source water and disposal use, that is shallower than the shale gas wells requiring stimulation, but much deeper than the fresh water aquifers. Many tests were conducted by numerous operators on the Debolt aquifer to determine how this water source could be utilized to supplement fresh water requirements for fracture operations. Extensive aquifer testing revealed that this Debolt water remains stable if kept above the bubble point pressure, but existing PD frac pumps cannot pump this water at the high suction pressures required to keep the water stable. A high pressure multi stage centrifugal pump configured as an HPHPS for 500 psi suction and 10,000 psi discharge is capable of using raw Debolt water as a fracture fluid.

This paper will review how 3 HPHPS frac pumpers were integrated into a frac fleet of 20 PD frac pumps for evaluation of HPHPS pumping performance on a 10 well pad site during a 2013 frac campaign in the Horn River Basin. This multi-well pad site is scheduled for 252 fracs at 6.3 fracs per day.

The successful integration of HPHPS frac pumps into a standard PD frac fleet enables a Pressurized Frac On Demand (PFOD) system to be used. Untreated sour aquifer water can then be used to supplement fresh water in the large water demand requirement necessary to stimulate shale zones.

These concepts may be applicable in other shale exploitation areas to reduce the demands on the local fresh water resources in their areas too.
A New Concept of Wellbore Boundary Condition for Modeling Liquid Loading in Gas Wells
Authors: Limpasurat A. , Valko P. P. , Falcone G.
Published: June 2014

A new formulation of the wellbore boundary condition in multiphase reservoir simulation is suggested, allowing automatic determination of the direction of the flow at any time instant. It is particularly useful in coupled transient modeling of the liquid loading phenomenon in gas wells. The traditional Inflow Performance Relationship (IPR) uses a common well-block productivity index, but determines the inflow/outflow of the individual phases through a wellbore connection in an otherwise detached manner. The new approach takes into account that all phases should flow in the same direction and should have a common zero flow condition. The restriction leads to the definition of a new state variable: the multi-phase zero-flow pressure (MPZFP, P°). According to the new formulation, the flow direction at the connection is determined by the sign of the difference between this grid-block variable and the wellbore flowing pressure. Some advantages of the new formulation are: the flow is always co-current through a single connection (but multiple connections can lead to cross-flow); the meaning of well-block productivity index is preserved; the phase composition of the connection stream is determined by the upstream condition; when wellbore pressure is far from the MPZFP, the traditional (detached) IPRs are recovered; and - last but not least - previous numerical convergence problems are completely eliminated during coupled dynamic simulation of the wellbore/reservoir system in the presence of significant capillary pressure. Examples illustrate the application of the new wellbore boundary condition in coupled modeling of the complex phenomena under liquid loading conditions.
Fluid Profiling for Reservoir Evaluation - Two Norwegian Case Studies
Authors: Pfeiffer Thomas , Kretz Vincent , Øpsen Daniel , Achourov Vlad , Mullins Oliver C.
Published: June 2014

Today's climate of a general lack of resources and people, high prices and limited rig availability forces the oil industry to plan for efficient production and secondary recovery. This puts more weight on understanding reservoir architecture and fluid complexities, the main drivers of recovery. Improving confidence in reservoir architecture has taken center stage in risk management especially in high cost environments. Data availability to increase this confidence will always be limited by budget and/or operational constraints. This puts the strike on maximizing the value of acquired data and integrating all available data to help this cause.

Recent advances in sensor technology and petroleum science allows using downhole fluid analysis data to improve confidence in reservoir architecture. Mapping composition, gas oil ratio (GOR) and density across the field is common practice. These properties are based on the amount of solution gas in the liquid phase and their equilibrium distribution can be predicted by (typically) cubic equations of state (EOS). Evaluating the relative asphaltene distribution is based on different physics: the suspension of solids in the liquid phase. It is robustly assessed by the latest generation of downhole fluid analysis (DFA) tools and recent breakthroughs in science now also allow predicting equilibrium distributions by EOS. Consequently, two equations of state are used to analyze two separate fluid gradients, GOR and asphaltenes, yielding a robust method of reservoir evaluation. This new independent workflow is especially valuable when used in concert with PVT reports, well test data, static pressure gradients and other common techniques to assess reservoir architecture.

This paper presents two real-life case studies from the Norwegian continental shelf that use available DFA data to support the assumptions made from other data on reservoir architecture between wells. It shows the validity of the concept, but also highlights the limits and constraints of such a data set. These case studies lead the way to planning the data acquisition to include a more comprehensive DFA data set to address connectivity and other reservoir concerns.
A New Method for Modeling Multi-Phase Flowback of Multi-Fractured Horizontal Tight Oil Wells to Determine Hydraulic Fracture Properties
Authors: Clarkson C. R. , Williams-Kovacs J. D.
Published: June 2014

Unconventional light oil reservoirs are currently a primary focus of exploration and development activity in North America. Operators are seeking new methods to characterize hydraulic fractures generated during stimulation of multi-fractured horizontal wells completed in these reservoirs, particularly early in the well life. One such method is to quantitatively analyze flowback fluids immediately after fracturing operations. In previous studies it has been shown that flowback fluid rates and pressures can be modeled to obtain hydraulic fracture half-length and conductivity.

In this work, we develop an analytical procedure and methods for analyzing pre- and post-breakthrough of hydrocarbons during flowback of light tight oil wells. Flowback of multi-fractured horizontal wells, stimulated with water-based fluids in tight oil reservoirs, often consists of a short period of single-phase (water) flow followed by breakthrough of hydrocarbons, after which multi-phase flow (oil, water and gas) occurs. Our modeling approach therefore accounts for these multiple stages of flowback fluid production. The first flowback regime typically observed is fracture storage/depletion – this stage is analyzed by modeling single-phase depletion of the fracture pore volume from which a pre-hydrocarbon breakthrough estimate of fracture permeability and half-length is obtained. A stress-dependent permeability can be included to account for fracture closure and consequent conductivity loss during flowback. Fracture storage is followed by formation fluid breakthrough, which causes a deviation from the depletion signature. This stage is modeled by assuming transient linear flow of oil and formation water to the fracture, and accounting for consequent multi-phase flow in the fracture. The primary properties adjusted to match pre- and post-hydrocarbon breakthrough fluid production include fracture half-length and permeability, fracture relative permeability, breakthrough pressure and reservoir permeability. We have observed, as have others, that effective fracture half-length may be significantly reduced following hydrocarbon breakthrough.

Our new method for tight oil reservoir flowback analysis is tested against a field example. As with previous studies associated with shale gas, significant uncertainty in fracture property estimation results from the analysis, which we will address in future work.
A New Standardized Laboratory Protocol to Study the Interaction of Organic-Rich Shales with Drilling and Fracturing Fluids
Authors: Zhou Junhao , Jung Chang Min , Pedlow John W. , Chenevert Martin E. , Sharma Mukul M.
Published: June 2014

The two major concerns during drilling and completion of wellbores in unconventional reservoirs are: wellbore instability and proppant embedment. Both of these issues are controlled by the interaction of water-based fluids with the organic-rich shale. Understanding the interaction of water-based fluids with organic-rich shales is the first step towards developing screening tests for their compatibility with the shale. In this paper, we present a systematic approach to investigate the interaction of water-based drilling and fracturing fluids with organic-rich shales.

We performed a series of measurements to determine shale mineralogy, native water activity, swelling parallel and perpendicular to bedding planes, Brinell hardness, P-wave and S-wave velocities and compressive strength. Changes in hardness and acoustic wave velocities were measured before and after shale samples came into contact with water-based fluids. Shale swelling was determined in two directions simultaneously with our unique 2-D strain indicators. The dynamic Young's modulus and Poisson's ratio were calculated based on the wave velocities. It is shown that these measurements can be used to screen drilling and completion fluids that may interact unfavorably with the shale.

The shale mineralogy was obtained using XRD. The shale native water activity was determined with controlled humidity environments. Multi-scale durometers were used to measure the shale hardness. Anisotropic swelling was observed for all shale samples characterized. The results showed a good correlation with the mineralogy, hardness and wave velocities of the shale. In general, the water adsorption was greater with fresh water than with 4% NaCl and 2% KCl. Changes in hardness, P-wave and S-wave velocities, dynamic Young's modulus and Poisson's ratio after shale's contact with water-based fluids can be used as indicators for wellbore stability and fracture conductivity impairment in these shales.

The measurement techniques and procedures presented in this paper can be used as standard screening tests to evaluate the interaction between organic-rich shales and water-based drilling and fracturing fluids. If this testing protocol shows incompatibility of the fluids with the shale, additional fracture conductivity tests should be conducted. The screening protocol presented here minimizes the number of fracture conductivity measurements (that are hard to perform) that need to be conducted to check for shale-fluid compatibility.
A North American Review of Commercial Shale Plays; Have We Learned Anything Besides Serendipity?
Authors: Shelley R. F. , Mullen M. J. , Minner W. A.
Published: June 2014

When evaluating mud rock completions one is quickly struck with the complexity of the task. Mud rock "shales" by their very nature can be problematic to evaluate given the wide variation in geology, rock properties, and reservoir characteristics, not to mention the effect of multi-fractured horizontal well completions. Quite often, the reservoir characteristics between an economic well and an uneconomic well are very similar, further compounding the problem. So, what can we learn by taking another look at North American shale plays to help identify the more productive shales, improve economics and reduce the cycle time bringing this resource to market globally? Sometimes, the simple measurements we make at the wellsite can be very indicative of the things we don't measure very well, like the degree of natural fracturing and the interconnectedness of porosity. The subject material and the information discussed in this review was derived from the study of the characteristics and data from hundreds of completions with production results for shale wells in North America.

The findings presented show the results of formation evaluation and analytical evaluation which have proven to be good indicators of well productivity and hydrocarbon recovery. Many of these methods have been underutalized by the industry for shale evaluation and completion optimization.

Past successes in unconventional resource arenas are sometimes viewed as the result of seredipity. However, that has not been the case – past successes have evolved, in some cases over periods of years. A comparison of learnings from the Bakken and Eagle Ford show some interesting commonalities that help identify economic wells from subeconomic wells, as well as the most productive completion intervals in lateral wellbores. These findings and evaluation methodologies can readily contribute to the global hunt for unconventional reservoirs, and evaluation / optimization of their development strategy..
Design Verification, Optimization and Validation of Ultra-HPHT Completion and Production Tools
Authors: Deng Guijun , Doane James , Ruffo Antonio , Shyu Goang-Ding , Collins Scott
Published: June 2014

The growing global demand for hydrocarbons is challenging the oil and gas industry to explore and develop deeper and hotter reservoirs, pushing the boundaries of equipment capability beyond traditional High Pressure High Temperature (HPHT) limits into the Ultra-HPHT region. Ultra-HP/HT wells are currently being drilled in the Gulf of Mexico, on the shelf and in deep water. Many of these wells have a total depth of in excess of 30,000 ft, where reservoir pressures and temperatures approach 30,000 psi and 500°F. There are many technological challenges that must be overcome for downhole service and completion tools to operate successfully in the Ultra-HPHT environment. As a result, there are currently few packer-type devices that are considered fit-for-service in these applications.

This paper gives an overview of the latest developments in how advanced finite-element analysis tools are used to develop Ultra-HPHT completion and production tools. These advanced analysis tools enable the designs to be verified before prototype and production to determine if they are functional under complex scenarios that sometimes were impossible to validate by testing. A design process that integrates analysis with design and testing for concept verification, design optimization, and test correlation is discussed in detail.

The technical challenges of multi-physics simulation like thermal-mechanical coupling, buckling, and 3-D multi-body contact with metallic and hyper-elastic material, are also addressed in this paper through a few Ultra-HPHT completion and production tool design examples.

The design process which will be described integrates design verification, design optimization using advanced finite-element analysis techniques, and design validation. It has proven to be a very valuable process in developing state-of-the-art Ultra-HPHT completion packers and bridge plugs for operating conditions as challenging as 500°F and 25,000 psi. Two validation tests were conducted on each of these tools. First, they were tested in accordance to ISO 14310 Grade V0. Then they were tested to a modified grade V3 procedure in as-rolled ID casing, and both passed the tests successfully. A summary of the process and the relevance of each step will be presented, along with conclusions regarding how the process leads to improvements in design and reliability.
Numerical Challenges in Foam Simulation: A Review
Authors: Rossen W. R.
Published: June 2014

We review challenges to accurate simulation of foam enhanced oil recovery, with a focus on numerical issues. Foam responds in an abrupt, nonlinear way to changes in water saturation, surfactant concentration, and oil saturation, in ways that cause fluxes to fluctuate in time and space. As the grid is refined these effects have smaller impact on the overall process but execution of the simulation slows. In addition, in simulations of foam with oil, consecutive grid blocks can lie on opposite sides of a strong foam/weak foam boundary on the composition diagram. Because by definition foam is an interaction between gas and water, the naming of phases (gas or oil) in a compositional simulation of a miscible EOR process can have significant effect on the simulation of a foam flood. Numerical dispersion of surfactant concentration is a problem, but attempts to minimize its effect can lead to other numerical artifacts. Because foam is so sensitive to water saturation and capillary pressure, capillary effects are important, especially in finely laminated formations. "Population-balance" foam simulators, which represent the complex dynamics of bubble creation and destruction along with the effect of foam on gas mobility, face additional challenges with instability and slow run times, especially for models that represent the multiple steady states seen in the laboratory.

We collect and review the various numerical challenges to foam simulation. Some of these problems are largely cosmetic, giving for instance fluctuating fluxes and pressure gradient but no significant effect on final recovery. Others do severely influence the whole progress of the flood. We discuss the origin of the challenges, how to recognize them, how they can be mitigated, and whether they arise from a correct representation of foam physics or the unintended result of attempts to solve other numerical problems.
Flow Assurance Solutions to Mitigate Naphthenates Problems in Crude Oil Production
Authors: Oliveira M. C. , Rosário F. F. , Bertelli J. N. , Pereira R. C. , Albuquerque F. C. , Marques L. C.
Published: June 2014

Recent years have seen a wide-world increase in the production of acidic crudes rich in naphtenic acids (NAs). The presence of these compounds in crude may lead to two different problems: i)- the so-called naphthenic acid corrosion (NAC), and: ii)- formation of naphthenates (naphthenic acid salts) which can either precipitate or form interfacial active salts (soaps) that are prone to stabilize emulsions. The formation of naphthenates (NAPHs) during the W/O separation process is promoted by the pH increase of the produced water phase brought about by CO2 degassing.

NAC problems are well-understood and advantages in technologies to mitigate them are abundant. In contrast to this, NAPHs problems which are germane to the topside O/W separation settings are themselves a dimly understood problem. However, the combination of tailored chemicals and changes in the processing parameters is the best solution to keep NAPHs problems at bay.

Taking these points as the main rationale this paper presents:- a description of NAPHs problems in the upstream crude oil sector; - a comprehensive description of the NAPHs problems Petrobras has been facing; - the analytical tools suitable to characterize and quantify the presence of NAPHs in the produced fluids; the suite of lab tests to screen chemical additives for field application; the difficulties in sparking actions to modify oil-processing parameters and to injecting chemical on an outsourced FPSO top-side facilities, and; the concert of solutions that have provided the best field results.

This paper concludes with a suggestion that a comprehensive water and crude oil characterization program (including geochemistry studies) is totally necessary to cope with the macroscopic behavior of NAs in actual field conditions.
Frac-Perforating Charge Maintains Treating Pressure while Increasing Pumping Rate: A Case Study in South Texas
Authors: Brady Thomas , Grace Timothy
Published: June 2014

The amount of horizontal, multistage completions performed globally is rapidly increasing. Unconventional shale gas plays are proving to be both productive and economical when a plug-and-perforate method is used as a gateway for hydraulic fracturing. Historically, deep-penetrating charges were used to perforate multiple clusters with varying shot density. Results, however, did not always correlate with the designed frac job. The limited-entry frac design used was based on published average entry-hole size and shot density, which created a backpressure or choke effect. The choke effect helped increase the chances of all of the perforations breaking down and being stimulated. However, because entry-hole sizes vary in diameter, the effective perforations were not always consistent with the treatment design. Screenouts and high treating pressures were often an unexpected result. These instances became accepted as the norm, often prompting the operator to abandon the stage and possibly move on, consequently resulting in loss of production from that stage.

Obviously, there was a need to minimize the perforation coefficient and deliver a consistent hole size, despite the distance of the standoff. The perforation coefficient needed to be minimal to plan and execute the desired stimulation. Instead of using deep-penetrating charges that were designed for completions requiring no stimulation, a frac-perforating charge was incorporated into the gun system. The frac charge offers reduced a variance of entry-hole size, regardless of the standoff.

This paper demonstrates how less variance with respect to entry-hole size enabled an operator to effectively reach the designed pump rate while maintaining the same treating pressure. Additionally, the results of alternating stages between conventional deep-penetrating charges and a new frac-perforating charge are presented.
Real World Solutions, Effective Fracture Treatment Design in Horizontal Wells
Authors: Sturms Jason M. , Smith Charles H. , Ziane Lynda
Published: June 2014

Horizontal wells have altered the ability to deliver production from marginal reservoirs. Although reservoirs with permeability values in the 0.1 to 0.01 millidarcy range had been identified in many producing basins, these reservoirs could not be exploited until horizontal drilling became a commercial reality. Drilling these reservoirs became an engineering process that could be applied with great success in many different basins and rock types.

The completion of these resources proved to be a different matter, however. Wells that were drilled with excellent vertical control within the reservoir did not exhibit a consistent response to stimulation treatment along the entire traverse of the horizontal sections. Although reservoirs that are considerably different lithologically were always expected to provide a diversity of completion challenges. More troubling, however, are the reservoirs that appear to be homogeneous that do not respond well to similar treatment designs along the length of the horizontal section. Pump-in tests were used in an attempt to understand this lack of consistency. In some cases, pump-in tests followed by treatment designed from that data failed to yield the expected production results. Sometimes, breakdown could not be achieved in the reservoir.

This paper describes how to apply data derived from dipole sonic logs in horizontal sections of a well to establish the anisotropy along the length of the horizontal section. This information is then used to define the brittleness properties of each section of the wellbore. Perforations are selected to take advantage of this brittleness, and effective fracture treatments are designed and pumped.

These case studies are examples of this application in difficult and troubling reservoirs. In each well, the fracture treatment success increased as much as 100% and had reduced breakdown pressures. Production rates were also increased by 20% when compared to production from the nearest offset wells in the same reservoir and of similar horizontal length.