bluuebunny/crossref_metadata_2025 huggingface dataset:
Work Flow Integration, Best Practices, and Technological Solutions for Improving Productivity in Mature Fields
Authors: M. de Jesus Gonzalez , M. Suarez Corvo , M. Mora Villa
Published: June 2014

More than 70% of global oil production derives from mature fields. With current elevated prices, the revitalization and optimization of these fields are of great commercial appeal and interest. However, revitalization requires technologies and procedures for quick analysis and diagnosis of the field in addition to established technical solutions to help improve productivity and counter high levels of pressure and production decline.

In 2013, in the southern region of Mexico, workflow integration for integral analysis of well productivity in mature fields and naturally fractured carbonate reservoirs, in combination with joint efforts of several product service lines and their technological solutions, have been key to identifying a portfolio of opportunities for well interventions. Of which, in a short time period, an increase to production of 1, 843 STB/D of oil was achieved, with only 54.5% of the proposed activity involving well services.

In view of the energy requirements in the world and the low rate of discovery of new reserves, many companies have targeted maximizing the exploitation of mature fields. Therefore, this study intends to establish effective techniques, methodologies, best practices, and lessons learned developed by multidisciplinary teams performed in Mexico during the past eight years. This strategy has helped increase oil and gas production in areas where it was previously considered unlikely because of complexity issues, such as low pressures, low permeability, organic deposits, scales, advanced fluid, reservoir dynamics, and mechanical problems, among others. These efforts have resulted in highly successful solutions as well as added value to the national operator.
Brackish Water as a New Water Resource for Energy Development
Authors: Stewart David R.
Published: June 2014

This paper will discuss the need for additional water resources associated with energy development and the potential of utilizing brackish groundwater as a new water resource. Brackish groundwater used in this context is a water that would have a total dissolved solids content of 4,000 mg/l or higher to a maximum of 50,000 mg/l. These types of groundwater are found throughout the world in areas where oil and gas wells are being developed. Key factors are indicating a conflict between energy development and water uses along with agricultural needs. These conflicts arise from the increase in population and the need for additional water sources, traditional water sources are dwindling in both quantity and quality, energy intensive treatment technologies such as RO or UV treatment and the need for additional water sources due to the requirements of the growing poplution for food resources. For these reasons, it will be important to develop and enhance all of our water resources for future uses. Brackish groundwater can play a significant role in this area.
Using Production Gas Carbon and Hydrogen Stable Isotope Signatures to Predict Fluid Quality: Wattenberg Field, Colorado, USA
Authors: Travers Patrick , Cumella Steve , Dolan Michael
Published: June 2014

Stable carbon (δ¹³C) and hydrogen (δ²H) isotopes have been used to characterize hydrocarbons for exploration, development and production since the 1960s, and have re-emerged as predictive tools with the development of unconventional "tight" oil and gas plays. Here we report on publicly available Colorado Oil and Gas Conservation Commission (COGCC) and U.S. Geological Survey (USGS) datasets of production gases collected from the Greater Wattenberg Area (GWA) of Colorado.

The δ¹³C and δ²H of natural gas can be used to interpret gas origin (i.e., bacterial versus thermal), hydrocarbon maturity, migration and reservoir compartmentalization, and production allocation. Maturities derived from carbon and hydrogen isotopes can serve as controls in regional maturity maps, which are used to help define areas of oil, wet gas and dry gas production. Stable isotope analysis can be executed pre-completion on samples obtained from mud gas and/or gas desorbing from cuttings and core. These data can help predict fluid type, API gravity, and gas-oil ratio (GOR), all of which can help guide land acquisition and development decisions.

Production gases from the lower to upper Cretaceous Muddy "J" Sand, Codell, Niobrara and Sussex formations are characterized isotopically as early-mature to post-mature oil-associated gases. Progressing from shallow to deeper formations, δ¹³C of methane, ethane, propane and δ²H of methane components all increase, reflecting increasing maturity with depth, and the presence of multiple, discrete petroleum systems (Sherwood et al., 2013). Stable carbon and hydrogen isotope values show a strong correlation to both initial and cumulative GOR for the unconventional Niobrara and Codell intervals of Wattenberg Field. While this relationship does not hold for wells actively producing from the Muddy "J", this could be a result of geologic compartmentalization in this interval due to faulting, natural migration and other factors.

Validation of the correlation between Niobrara and Codell production GOR and stable isotope composition was provided by an independent geochemistry dataset from the USGS. The predicted GOR values were then used to accurately distinguish reservoir fluid classification. These results demonstrate the potential of natural gas stable isotope signatures as a useful and reliable fluid quality prediction tool.
Verification of a Proppant-Filled Discrete Fracture Network Model
Authors: McKenna Jonathan P.
Published: June 2014

Effective propped fracture half-lengths following a typical hydraulic fracture stimulation of a wellbore can be difficult to quantify. Therefore, different techniques for modeling proppant distributions must be applied to the same dataset for validation purposes and to gain insight into the actual proppant distributions. A proppant-filled fracture model is applied to one well targeting the Evie Member of the Horn River Formation (British Columbia, Canada). Another technique for identifying microseismic signatures associated with the initial slickwater pad and the proppant-laden fluid was applied to the same well to obtain observed proppant distributions. The similarity of the proppant distributions from the two techniques gives validation to each procedure and the results can be used to optimize future completion techniques.
Unconventional Horizontal Well Placement Challenges - LWD Geosteering Applications Utilizing a Unique Spectral Azimuthal Gamma Ray in Real Time
Authors: Diab Mohamed , Combs Jeremy
Published: June 2014

Placing horizontal laterals in the sweet spot of unconventional reservoirs is challenging. As more unconventional wells are drilled, there is growing evidence that the old way of geosteering homogeneous conventional reservoirs is not sufficient. Challenges due to smaller pore sizes, tinier pore throats, and less permeable rock are limiting production from unconventional reservoirs. Well bore placement for optimal fracture propagation is also an issue and laminations within a single geological layer can prevent oil companies from placing their wells in the sweet spot of the reservoir.

A unique logging-while-drilling (LWD) spectral azimuthal gamma ray (SAGR) tool has been developed that provides high-quality images and spectral elemental analysis, which allows geosteering in the lateral section of unconventional shale reservoirs; the use of the uranium content curve while drilling helps with placing the well in the sweet spot of the reservoir.

Several applications are discussed in this paper, including pre-planning and modeling, kicking-off through the landing, and geosteering in the zone for the maximum production. The significance of these applications is to demonstrate how innovative geosteering techniques can prove useful in more challenging unconventional reservoirs.
Optimizing Efficiency in Horizontal, Multi-Stage Fracturing Operations through E-line Conveyance—Case Study from the Bakken
Authors: Mann Rex , Bukowski Rick
Published: June 2014

In the Bakken, pump-down perforating has been the preferred solution for multi-stage ‘plug & perf’ operations for years. However, when an operator in a Bakken, North Dakota field was faced with a restricted inner diameter, they turned to an unconventional solution of using e-line, tractor-based conveyance. The operation was a success and more such operations have been run. This paper will present the lessons learned from these operations, as well as discuss the applicability and efficiency gains of e-line, tractor-based conveyance. Best practice consideration will be proposed for future plug & perf operations in horizontal wells.

Several challenges led to the initial decision to select the tractor-conveyed solution. Poor road conditions made the logistics of heavy equipment difficult, and coupled with severe time constraints and strict budget considerations the e-line solution became the preferred choice. This decision enabled the operator to get this $9M asset on production in a timely manner.

A 3.6 in. patch was restricting the inner diameter of a 4½ in., 11.6# casing string. The operator needed to plug and perforate 26 zones horizontally from 21,740 ft up to 11,830 ft to get the well on-line quickly. Pumping the 4½ in. plug was not considered an option due to the risk of premature setting or pumping off plug and/or guns resulting in expensive and time consuming fishing operations. Coiled tubing would only be able to reach the first 16 zones leaving 10 zones imperforated. Rig operations would be too time consuming and costly.

The 26 run, e-line operation was completed in 14 days with no conveyance mis-runs or lost time but only one gun mis-fire. The well was brought on-line quickly and the logistical challenges easily overcome due to the lightweight nature of the e-line technology. As an added bonus the operation offered several HSE benefits stemming from the low footprint, reduced personnel requirements, and less heavy lifting.
An Analytical Method for Optimizing the Spacing of Transverse Fractures in Liquid–Rich Shale Formations
Authors: Li J. , Guo B.
Published: June 2014

Producing oil from liquid-rich shale fields requires well completions with multi-stage hydraulic fracturing to enhance well productivity. Good design of transverse fractures is a key to achieving successful well completion and field-development economics. Using large fracture spacing will limit the number of fractures along the horizontal wellbore of given length, while using small fracture spacing can result in merging of fractures in the fracture-shadow area, both will reduce well productivity and oil recovery factor. There exists an optimum fracture spacing for given geological and fracturing conditions that allows the maximum oil recovery factory in shale oil reservoir to be achieved. The current practice of determining the optimal fracture spacing involves running numerical simulators to identify the fracture shadow. The numerical method is not only time-consuming but also inaccurate due to the procedure of numerical analyses and visual identification of fracture shadow. This paper presents a simple analytical method to determine the minimum fracture spacing required for preventing fracture-merging.

On the basis of assumption of constant-width fracture, an analytical solution was first obtained in this work to predict the stress distribution around an existing fracture. The solution was then used to predict the boundary of fracture-shadow area and identify the minimum distance of new fracture from the existing fracture to avoid fracture-merging. The result of the analytical method was compared with that of a numerical model of Finite Element Method (FEM) for a typical fracturing condition in a shale formation. The comparison indicates that the new analytical solution gives a shorter fracture spacing that will increase oil recovery factor. According to the analytical solution, the minimum required fracture spacing is nearly proportional to fracture width and insensitive to the fracture length. The minimum fracture spacing does not exist when the net closure pressure is lower than a critical value, depending on the in-situ stress contrast and Poisson's ratio of shale. This paper provides engineers a simple tool for optimizing their well completion in liquid-rich shale formations.
Case Study: Steam Injection Step Rate Tests Run in the Shallow Low Permeability Diatomite Formation, Orcutt Oil Field, Careaga Lease, Santa Barbara County, California
Authors: Elias Ramon , Marquardt Ian , Medizade Mason
Published: June 2014

Cyclic steam stimulation (CSS) has been used in California since the 1960s. It has been used as an effective method for commercial oil recovery from the very low permeability diatomite formation since about the mid-1990's. Santa Maria Energy (SME) operates a CSS project in the Opal A diatomite of the Sisquoc formation on the Careaga Lease in the Orcutt Oil Field in Santa Barbara County, California. A 19-well CSS pilot has been operational since October, 2009. SME has received entitlement to proceed with an expansion consisting of 110 additional new wells.

The CSS process designed by SME for the diatomite zone is one that works without fracturing the reservoir rock. An earlier paper was presented that describes techniques used for monitoring steam injection to help keep the injected steam confined to the zone of interest1. One such technique is Hall's method2 for water injection and adopted for steam. Corresponding algorithms have been programmed into a supervisory control and data acquisition (SCADA) system to survey and analyze all steam injection cycles for all wells. The method has also been used to analyze steam injection step rate tests (SRT). This paper discusses:

Two SRT's performed using steam injection; The analytical techniques used; and The results.

Of special importance is that matrix flow is seen for CSS even though the injection bottom-hole pressure exceeds that which might normally be considered the rock fracture or parting pressure. This is due to partial plugging and other phenomena during steam injection that occurs to an extent not realized in more permeable rocks (such as very high permeability sandstones). These effects produce extra pressure drop during steam injection into the diatomite zone. This raises questions about the misuse of tubing wellhead pressure readings during steam injection as a reliable indicator of the reservoir formation parting pressure. As a result of this and other work, SME has adopted a specific range of CSS injection rates that are below a critical rate to help insure steam injection is confined to the zone of interest.
Effect of Well Down Spacing on EUR for Shale Oil Formations
Authors: Bharali Susrut Gautam , Sharma Akash , Sehra Sarva Shakti
Published: June 2014

With the shift in focus towards unconventional oil and gas as the future of the oil and gas industry, it has become essential to optimize performance of wells in these formations and ensure economic feasibility in these unpredictable scenarios. Down Spacing of wells is a procedure by which we reduce the space between the laterals of two wells to maximize recovery from the formation. In conventional reservoirs, due to the homogeneity in petro-physical parameters of the formation, down spacing is usually not economic as the lower number of wells would also be sufficient to achieve optimum productivity, furthermore, the wells will have a tendency to cannibalize each other's production. However, in unconventional reservoirs like shale, down spacing becomes essential to maximize reserves and the productivity from them as poor permeability hinders majority of the pores to be reached by a relatively lower number of wells.

The presented paper, achieves to find the optimum down spacing distance that can be achieved between two fractured lateral wells in Eagle Ford Shale Play. The paper analyses the performance of group of wells with different well spacing in the Eagle Ford formation. The data used is from the public forum. The EUR/well is calculated using decline curve analysis. Fekete-Harmony has been used for calculation of EUR and then a simplistic cash flow analysis had been conducted to analyse the feasibility for each presented scenario. This paper also has a group of analog wells created in Fekete Harmony with drilling and completion techniques similar to the ones widely used in Eagle Ford Formation. Real world Eagle Ford geological and petrophysical parameters are incorporated into the Harmony model for the analysis of these wells.

This paper emphasizes on the need for downspacing in the shale oil reservoirs for optimum production. It also discusses the advantages and disadvantages of downspacing as well as looks into the economic side of this process.
Optimization of Hydraulic Fracturing Design under Spatially Variable Shale Fracability
Authors: Jahandideh Atefeh , Jafarpour Behnam
Published: June 2014

Current hydraulic fracturing designs are based on equal fracturing intervals, ranging from 50 to 600 feet, along the horizontal well with an equal half-length, ranging from 100 to 600 feet. However, symmetric spacing designs are only suitable for homogeneous shale fracability or brittleness, which may not be the case in many shale plays. The efficiency of the fracturing process depends on the fracability of the underlying shale rock. Therefore, the heterogeneity in shale fracability can have an important role in designing and optimizing the hydraulic fracturing process, in particular in identifying the optimal number, location, and length of the fractures. In this paper, we develop an optimization approach for hydraulic fracturing design under geospatial variability in shale fracability and investigate several aspect of the design and optimization of the fracturing process. The optimization of the hydraulic fracturing design is performed using the Simultaneous Perturbation Stochastic Approximation algorithm to maximize the net present value of the shale asset that includes the cost of fracturing and revenue from gas production. The proposed optimization framework provides a systematic hydraulic fracturing design and treatment approach for unconventional reservoirs to improve production and reduce the cost and environmental impacts of hydraulic fracturing. We demonstrate the effectiveness and suitability of the proposed method with several numerical experiments in shale gas development.
A Sensitivity Analysis of Input Parameters for Modeling Primary and Tertiary Recovery in Unconventional Oil Reservoirs
Authors: Givens Bill , Hoffman B. Todd
Published: June 2014

Reservoir flow simulation models for unconventional oils reservoirs like the Bakken are difficult to construct and condition to data. It is important, however, to have accurate models to evaluate primary recovery aspects such as well spacing and improved recovery options, such as gas injection. While performance of the model depends on all of the unknown reservoir parameters, it is important to understand which ones have the most significant effect on the accuracy of the model. This information can then be used to focus capital on gathering the most impactful data.

The data used for this analysis comes from the Elm Coulee Field in Eastern Montana. In this paper, we assess a number of different combinations of parameters to match the historical production data. The analysis focused primarily on four common model inputs for history matching: reservoir permeability/porosity distribution, dual-porosity dual-permeability modeling, heterogeneous z-direction permeability and hydraulic fracture modeling. The hydraulic fractures are represented on the grid, so the dual porosity properties account for the matrix and natural fractures. Using an expected range for each input, the change in reservoir performance is determined not only for primary production but also for gas injection recovery operations.

Only the first 3 - 4 years of production is matched; then, the models are validated on the next 5 years of production data. The models predicted accurately with only 10% average error. Under primary recovery, porosity and effective permeability had the most impact on the simulated production rate, followed by hydraulic fracture dimensions. Under gas injection simulation, the porosity and permeability and the most effect on the output, with the other tested reservoir characteristics not making a significant contribution.

Having insight into what are the most significant parameters of a reservoir model can help limit money spent and time wasted on collecting less important data. This paper sheds light onto what those parameters might be in the Elm Coulee field. In addition, a methodology is developed to identify what these parameters might be for any type of reservoir engineering study.
A New Petrophysical Model to Define Porosity Components of Unconventional Reservoirs, Using Standard Open-hole Triple Combo Logs
Authors: Holmes Michael , Holmes Dominic , Holmes Antony
Published: June 2014

Unconventional reservoirs are composed of several types of porosity/hydrocarbon components - standard effective porosity, clay porosity, total organic carbon (TOC), and micro porosity associated with shales. Adsorbed hydrocarbons reside in the TOC component and "free" hydrocarbons in the effective porosity and shale micro porosity. An accurate definition of all these components is essential in defining the reservoir hydrocarbon resource volume.

TOC has a density response close to porosity and indeterminate neutron response. The log responses are probably related to the degree of thermal maturity.

Previous publications (Holmes, et al. 2011 and 2012) were earlier attempts to define these porosity components. This publication is a significant refinement, whereby TOC and clay log responses are determined using an iterative technique. An initial estimate of TOC properties (density vs. neutron) is subtracted from raw logs to derive a "TOC-free" log response. Then clay log responses are defined by subtracting matrix, effective porosity, and silt contributions. The resulting density/neutron cross plot is then compared with known clay mineral responses to determine if estimates of the various component log responses are reasonable. If not, these responses are adjusted and the procedure is repeated. A final check of the methodology is to calculate a reconstructed porosity, which is effective porosity + clay porosity + shale micro porosity, and see if it agrees with total porosity determined from the "TOC-free" reservoir model.

Examples of unconventional reservoirs - both gas and oil bearing - are presented.
An Effective Accelerated Pulsing Injection Method for Restoring Injectivity in Waterflood Fields with Selective Injection Systems with Side-Pocket Mandrels and Control Flow Valves
Authors: Escobar-Remolina J. C. , Barrios-Ortiz W. , Mantilla-Villamizar J. , Vargas-Medina J. A. , Sanabria-Gomez L. , Davidson B. C. , Sanchez-Lona A. , Wegmann-Sanchez J. M.
Published: June 2014

This paper presents the performance of three water injection wells, INJ-1, INJ-2, and INJ-3, at the Ecopetrol's Yarigui Cantagallo field re-completed with newly designed pulsing selective control valves (P-SCFV). The three wells originally had conventional selective control flow valves (C-SCFV) in side-pocket mandrels. While a total of 31 valves were replaced in seven wells, this paper will focus on the three wells where 12 P-SCFVs were installed and the injection data gathered and interpreted.

Enhanced Oil Recovery (EOR) and/or chemical methods are routinely used to improve oil recovery when production levels decline due to reduced formation pressure, poor displacement efficiency, and adverse mobility ratio. For decades, oil production companies with waterflood recovery schemes have employed various types of well completions for water injection, including selective completions with side-pocket mandrels.

When an injection zone loses its capacity to admit water, the optimal sweeping capacity will not be reached, and then the operator will not achieve sufficient oil production to maintain profitability. In the Yarigui Cantagallo field 12 P-SCFVs were installed (4 in each injector well), with the objective of overcoming the loss of injectivity in each injection zone due to blockages and permeability decay on the formation face, primarily as the result of calcium carbonate deposition. The new P-SCFVs were run to demonstrate that they could overcome the common problem of permeability decay with the objective that injectivity performance could be increased and sustained over an extended timeframe.

The 12 P-SCFVs have been in operation for 12 months, and the comparative results have shown performance optimization that conventional C-SCFVs could not achieve, such as, intervals previously not accepting injection water gradually (after ∼ one month) accepting water from the P-SCFVs. The latter confirms the theoretical and practical efficiency created generated by a flow field that concurrently establishes a repeated pulsed water hammer effect and the creation of numerous vaporization zones, which result in the formation of cavitation bubbles. These vaporization cavities work in consort with the water hammer effect to clear detritus material from the mandrel and formation face giving rise to increased near wellbore permeability.
Lab Observation of Low Salinity Waterflooding for a Phosphoria Reservoir Rock
Authors: Jiang Haifeng , Chopping Curtis G. , Forsman Chad , Xie Xina
Published: June 2014

Improved oil recovery by low salinity waterflooding for carbonate rocks has been observed both in labs and in field pilot tests. The objective of this lab study was to test if low salinity waterflooding was an option for improved oil recovery for a Phosphoria reservoir in the Big Horn Basin, Wyoming. Reservoir rock and the crude oil along with production history and water chemistry data were provided for the lab study. Petrological study indicated that the reservoir rock consists of dolomite, anhydrite, and chert nodules and is naturally fractured. The average porosity and permeability of the cores were about 10% and 2 md, respectively. To ensure relative homogeneity, reservoir cores were selected by CT scanning to confirm that there were no visible fractures and large size chert/anhydrite nodules.

Spontaneous imbibition tests were performed with synthetic formation water followed by diluted water in tertiary mode at ambient pressure and reservoir temperature. Oil recovery from 5 to 30% OOIP was achieved by spontaneous imbibition with synthetic formation water. The reservoir rocks appeared to be intermediate to weakly water-wet and mixed-wet. The oil recovery did not increase after low salinity water was used for continuous imbibition. Coreflood tests were performed at reservoir pressure and temperature. Oil recovery ranged from 38 to 64% OOIP by secondary waterflooding with synthetic formation water, accompanied by high differential pressure across the core samples. The subsequent tertiary low salinity waterflooding did not result in additional oil recovery, while anhydrite dissolution was detected. This study shows that low salinity waterflooding may not an effective method for this reservoir.
Accurate Tight Gas Flow Simulation: Where the Real Gas Pseudo-pressure Must Be Used
Authors: Lu Bo , Shiralkar Gautam
Published: June 2014

Because of the growing importance of unconventional gas (shale gas, coalbed methane, etc.), gas flow simulation has been receiving greater interest in the industry. Although the real gas pseudo-pressure m(p) approach has been available for some time, many commercial simulation tools still use gas pressure as the basis for gas flow calculations. There is a widely held perception that, while the m(p) approach can result in faster simulation runs, the two approaches are essentially equivalent or interchangeable. Herein, we show that well productivity is often significantly over-estimated when the standard pressure based approach is used for tight gas reservoirs. The effect is more pronounced at lower pressures.

We demonstrate that the difference in results arises from the numerical dispersion in the simulator associated with the pressure formulation. We discuss the implementation within a simulator that models both sub-surface flow as well as flow in a surface network. This allows comparison of simulation runs using the two different formulations.

Finally, we present several examples simulating gas flow in tight reservoirs with wells that are horizontally and vertically fractured, as well as a multi-well example. The m(p) approach is shown to yield accurate results in contrast to the pressure approach. This has important implications for simulations on a field wide scale and when other phases are present along with gas.

This paper shows that the real gas pseudo-pressure approach should be used to simulate tight gas reservoirs, through which the well productivity can be accurately estimated. The implementation approach is also applicable to other commercial simulators in the industry.
Increased Oil Recovery by Permeability Modification in High Permeability Contrast Slim Tubes
Authors: Jackson Scott , Fisher John , Fallon Robert , Norvell Joseph , Hendrickson Edwin , Luckring Abigail , D'achille Ben
Published: June 2014

Biofilm and biopolymers produced from microbes have been shown to reduce the permeability of high perm streaks which can result in improved sweep efficiency. The rate of permeability modification is very reproducible but can vary depending on the specific treatments used. Our approach has been to inoculate the reservoir with a microbe that under the optimal nutrient conditions will express a biopolymer as a film, reduce the size of pore throats and reduce the apparent permeability. The microbe and the nutrients are tailored to the conditions of each reservoir thus giving MEOR the greatest chance for success. In this paper we describe the use of a high permeability contrast composite slim tube to demonstrate increased oil recovery using microbes that generate biofilms to reduce the permeability contrast and thus improve sweep efficiency. In this setup, three hydraulically constrained slim tubes – working as very long sand packs – were constructed from different sources of sand with a range of particle size distributions. Absolute and differential pressure transducers were used to monitor the pressure drop across individual slim tubes and across the composite configuration of the three slim tubes. Oil traps were located at the exit of each slim tube to measure the oil production from each tube. The permeabilities of the slim tubes against a high salt injection brine (TDS ∼ 85,000 ppm) were measured to be 45, 4.5 and 2.6 Darcy. This presented a challenging system with a slim tube at a very high permeability that would need to be reduced by the MEOR treatment. Oil (viscosity of ∼58 cp) was pumped independently into each slim tube to assure that each slim tube was at residual water saturation. The slim tubes were allowed to age before the start of the test. Once working in composite mode the flows of the injected brine and MEOR treatments were dictated only by the hydraulics of the composite slim tube. The produced fluids from all three slim tubes were sent to a single back pressure regulator. In the composite mode, oil was readily produced only from the high permeability slim tube during the initial (non-MEOR) flooding sequence. A salt tolerant microbe present in the target oil reservoir capable of producing biofilms and altering the permeability was inoculated into the composite slim tube. The inoculated microbes were batch fed periodically using a protocol that was scaled down from one that would be used in a field test. An increase in the pressure drop and corresponding increase in oil production from the lower permeable slim tubes was observed as a result of the treatment. This resulted in a dramatic increase in the recovery factor from the composite slim tube. This work is a continuation of tests described in earlier papers (SPE129657, SPE146483 and SPE159128 – references 4, 5 and 6).
The Role of Counter-Current Flow in Simultaneous Water and Gas Injection Processes
Authors: Sherafati Marjan , Javaheri Mohammad , Jessen Kristian
Published: June 2014

In this work, we are investigating the effect of flow reversals from co-current to counter-current flow on the displacement performance of simultaneous water and gas (SWAG) injection processes. In simultaneous injection processes, gas migrates towards the top of the formation while water tends to move towards the bottom of the formation. The gravity segregation between gas, oil and water will result in counter-current flow occurring in the vertical direction in the reservoir. Experimental and theoretical studies have reported that relative permeability to each phase is less during counter-current flow as compared to co-current flow. The significance of this reduction depends on the gravity number. A reduction of relative permeability in the vertical direction results in anisotropy in relative permeability. This effect has to the best of our knowledge not previously been considered in the simulation of EOR processes.

To investigate the impact of flow reversals on displacement performance, we have implemented a new model that accounts for mobility reductions during counter-current flow in a three-phase compositional, IMPES simulator. A range of displacement settings, covering relevant gravity numbers and miscibility conditions (near-miscible and multicontact miscible), have been investigated to gauge the impact of mobility reductions due to flow reversals. The conventional mobility model (ignoring the impact of counter-current flow) is compared to the proposed mobility model and we demonstrate significant differences in the predicted displacement performance in terms of saturation distributions and recovery estimates. Accordingly, we recommend that an explicit representation of flow transitions between co-current and counter-current flow should be included to ensure accurate optimal design of SWAG processes.
Effective use of Information Technology in Spill Response - How an Integrated Web Portal can Facilitate the Response Effort
Authors: Kerr James , Braisted Robert , Sukkurwala Ghazanfar (Gus) , Teeling Michael
Published: June 2014

Spill responses are stressful and chaotic enough without the added burden of difficult or poorly categorized information. A Web Portal can provide an interactive geographic information system (GIS) map, access to data, and integration with a mobile data collection system to support spill response activities. Effective use of these tools can streamline the response effort and provide the responsible party, responders, regulators and the public access to current information. Incorporating the globally recognized Incident Command System (ICS) architecture into the Web Portal allows for easier coordination with local, state, and federal agencies. Linking GIS tools to the portal allows users to access spatial information and to query a variety of datasets in real-time. In short, a collective Knowledge Management System (KMS) extends beyond standard data management to provide a new way of addressing spill response.

Mobile devices can be used to collect field information that has historically been collected using manual techniques. The information can then be synchronized with a central database through the Internet or by direct download. The database can be linked through a Web Portal to interactive mapping tools providing near real-time information for decision-making and communication. Because significant spill responses in the United States and many other major industrialized countries around the globe use the ICS structure, it is also useful to have an electronic format that mimics that approach. This allows data to be collected, compiled, analyzed and disseminated in a consistent manner that the responders and regulators understand.

The need for timely and accurate information in our current sound bite society is critical. The use of data that is collected, compiled, analyzed and disseminated using electronic methods improves timeliness and accuracy. In addition, by consolidating information in the ICS structure, the data remain repeatable, defensible and reliable as the response effort moves from response phase, into project phase through to closure.

The continued increase in exploration, production, transportation and distribution of North American oil and gas from both conventional and unconventional sources increases the probability of more spills. The timeliness and accuracy by which industry responds to a spill will go a long way in determining the verdict in the court of public opinion and shaping the future laws that govern our business efforts.
Proppants Selection Based on Field Case Studies of Well Production Performance in the Bakken Shale Play
Authors: Hu Kyle , Sun Jianlei , Wong Joe , Hall Bobby E.
Published: June 2014

A brief overview of different proppant types and amounts used in stimulation designs in the Bakken shale play since 2011 is presented in this paper. The primary goal of the paper is to determine the long-term production and economical effectiveness on hydraulically fractured wells using different proppant types, percentages of proppant types and overall amount of proppant in the well completions. The results are based on four case studies that focus on 72 wells in four different fields in the Bakken formation of the Williston Basin.

In these four case studies, the primary variable that affects the difference in long-term production of the different well groups is the percentage and amount of each proppant type used in the completion design. Completion and stimulation data was collected from public resources such as the North Dakota Industrial Commission (NDIC) database. In each case study, wells in the same field were grouped. For each group of wells, the average long-term production and economical effectiveness was analyzed.

The case studies in the Capa Field in Williams County North Dakota and the Chimney Butte Field in Dunn County North Dakota shows that over a 270 day period, in each group of wells completed with about 30 percent ceramic proppant mixed with silica sand, the wells produced an average of over 100 percent more than the comparable group of wells completed using only silica sand. The case study in the East Fork Field in Williams County North Dakota shows that after 270 days of production, the group of wells using 100 percent ceramic proppant attained an average of 27 percent production increase over the group of wells using an average of 62 percent ceramic proppant. These wells also attained a 67 percent production increase over the group of wells using an average of 35 percent ceramic proppant.

In comparing completion procedures in these high-producing fields, using a combination of high percentages and large amounts of ceramic proppant has yield higher production and EUR. The use of ceramic proppant not only covers the additional proppant cost in a short period of time, but also generates higher revenue in the long term. The findings from these case studies should apply to all fields that have similar reservoir characteristics.
High Performance Ceramics in the Bakken
Authors: Crafton J. W. , Herndon D. , Kaul T.
Published: June 2014

An investigation of the performance of a group of 38 Bakken, Montana and North Dakota, horizontal wells was conducted for the purpose of assessing the relative benefit of premium ceramic proppants compared to 20/40 white sand and other ceramic proppants. The observed production histories of the wells, normalized for reservoir quality, severity of pressure drawdown and treatment type and size, were used as the basis for the comparison. The primary performance metrics employed were: apparent or effective fracture half-length normalized for the amount of placed proppant, sustainability of the reservoir/wellbore connectivity, impact of artificial lift installation, incremental oil equivalent recovery at various points in the production histories and impact of rate of pressure drawdown. The premium proppants had similar benefit, while the third ceramic proppant actually performed more poorly than the 20/40 white sand.

Sensitivity to the various damage mechanisms, such as rapid reduction in surface flowing pressure, the impact of shut-ins and delay to artificial lift installation are discussed in the paper. Based on equivalent oil recovery, there is clear evidence of a completions related point of diminishing returns. All of these observations call into question the "minimum cost" well management strategy. Benefits are derived not only from significantly better hydrocarbon recovery and longer apparent fracture length, but less damage during shut-ins and artificial lift installation, along with less sensitivity to pressure drawdown.
Analysis of Decline Curves Based on Beta Derivative
Authors: Shahamat M. S. , Mattar L. , Aguilera R.
Published: June 2014

This paper presents a new simplified method for forecasting oil and gas production during transient and boundary dominated flow (BDF), which does not require the use of complex analytical or numerical modeling tools. The method is based on the behaviour of the beta derivative (β), where two approximate straight lines are obtained during transient flow and BDF with slopes mt and mb, respectively.

The method is applicable not only to vertical wells in conventional reservoirs producing during BDF but also to hydraulically fractured vertical/multifractured horizontal wells in unconventional reservoirs with prevailing transient (linear) flow. Upon selection of an appropriate βBDF (which mainly depends upon the type of flow regime, i.e., radial or linear) and using the proposed equations, type curves can be generated that provide a convenient method for obtaining the slopes of beta derivatives for transient flow (mt) and BDF (mb) through a type curve matching process. The method is validated by comparing results against oil and gas numerical simulations of vertical and hydraulically fracture vertical wells.

The developed method is not biased toward any flow regime or presence of skin. Flow regime and skin effects are embedded in the βBDF and mt parameters. Transient and BDF flow are accounted for through the slopes mt and mb, respectively. Corroborated with the use of numerical simulation, the proposed method provides reliable production rate forecasting while staying away from the complexities of analytical or numerical modeling.
Multi-stage Hydraulic Fracturing Design In Horizontal Wells With The Use Of Drill Cuttings
Authors: Olusola Bukola K. , Aguilera Roberto
Published: June 2014

Successful multi-stage hydraulic fracturing of horizontal wells requires a clear understanding of the in-situ stress profile. This implies knowledge of rock properties and pore pressure variations throughout the wellbore. These properties can be determined with a good level of certainty when complete data sets are available.

In practice, however, data scarcity from horizontal wells is the rule rather than the exception. This has led in most instances to performing multi-stage hydraulic fracturing jobs in symmetric intervals throughout the horizontal well without regard to the optimum locations where hydraulic fractures should be initiated.

This study shows how data extracted from drill cuttings collected in a horizontal well can be used for optimizing multi-stage hydraulic fracturing. The cuttings are used in the laboratory for measuring porosity and permeability and for estimating geomechanical properties (e.g. Young Modulus, Poisson's ratio, brittleness index). The data permit generating the in-situ stress profile and other geomechanical parameters in a hydraulic fracturing model.

A comparison is made of two cases in a horizontal well of the Western Canada Sedimentary Basin (WCSB), where only a gamma ray log is available: In one case drill cuttings are used for estimating geomechanical properties to select fracture initiation zones; in the other case symmetric fracturing stages are selected without giving consideration to geomechanical properties.

The conclusion is reached that the petrophysical and geomechanical knowledge acquired from the study of drill cuttings leads to better rates and improved ultimate recoveries.
CTU Deployed Frac Sleeves Benchmark Horizontal Multi Stage Frac Isolation Performance
Authors: Schmelzl Eric , Schlosser Daniel , Alvarez Domingo , Gulewicz Dale
Published: June 2014

The paper summarizes field results and data which indicate the effectiveness of open hole packers vs. cement in providing competent hydraulic isolation of well segments in horizontal multi-stage completions. The application of multistage fracturing treatments to horizontal wellbores has facilitated unparalleled reservoir access, which is the catalyst for tight-rock exploitation. Whether created utilizing a cemented wellbore or an open-hole (O/H) packer style of completion, the massive surface area of induced and dilated fractures is a key ingredient for the successful completion of low permeability formations. Unfortunately, many of the commonly used completion systems offer little or no indication of the effectiveness of the hydraulic isolation between fracturing stages. In completions employing ball-activated sleeves in combination with O/H liner packers, the only indication of failed hydraulic isolation is masked in the surface treating pressure data collected during the frac. Multiple stages in the tubing at the same time can have the effect of masking the treating pressures as friction and increased hydrostatic pressure of the sand slurry have competing effects. This difficulty in interpreting the surface pressure readings can result in segments of the wellbore being either bypassed or overtreated as a result of the fracture treatments coalescing, potentially preventing the recovery of the targeted reserves. The paper reviews and compares data collected through the application of a combination of Coiled Tubing Unit (CTU) operated frac sleeves with either O/H packers or cemented liners. The use of CTU in the isolation of individual frac stages offers the capability to collect downhole pressure and temperature data of each frac treatment at the frac port, which is typically not available through other methods. Because this data is collected downhole, it can provide clear indications of O/H packer or cement effectiveness in isolating discreet fracture stages, potentially identifying segments of the reservoir which may remain un-stimulated, or possibly over-treated. The downhole data collected through the application of CTU operated frac sleeves may be valuable for operators seeking to maximize the effectiveness of their stimulation programs through optimal packer placement or cementing design, and may potentially help to maximize EUR for multistage completions.