bluuebunny/crossref_metadata_2025 huggingface dataset:
An Alternative to Streamlines for Flow Diagnostics on Structured and Unstructured Grids
Authors: Shahvali M. , Mallison B. , Wei K. , Gross H.
Published: October 2011

Streamline-based methods can be used as effective post-processing tools for assessing flow patterns and well allocation factors in reservoir simulation. This type of diagnostic information can be useful for a number of applications including visualization, model ranking, upscaling validation and optimization of well placement or injection allocation. In this paper, we investigate finite volume methods as an alternative to streamlines for obtaining flow diagnostic information. Given a computed flux field, we solve the stationary transport equations for tracer and time of flight using either single-point upstream weighting or a truly multi-dimensional upstream weighting scheme. We use tracer solutions to partition the reservoir into volumes associated with injector-producer pairs and to calculate fluxes (well allocation factors) associated with each volume. The heterogeneity of the reservoir is assessed by using time of flight to construct flow capacity-storage capacity (F-Φ) diagrams which can be used to estimate sweep efficiency. We compare the results of our approach with streamline-based calculations for several numerical examples and we demonstrate that finite volume methods are a viable alternative. The primary advantages of finite volume methods are applicability to unstructured grids and ease of implementation for general purpose simulation formulations. The main disadvantage is numerical diffusion, but we show that a multidimensional upstream weighting scheme is able to reduce these errors.
How to Constantly Deliver 100% Packing Efficiency in Openhole Gravel Packs: A Field Study in Colombia
Authors: Trujillo Hernando , Tengono Jose Aldemar , Rubiano John , Castaño Ricardo , Beltran Alexander , Ortiz Everardo , Navarro Claudia , Florez Darwin , Lopez Nicolas
Published: October 2011

Although the application of openhole gravel packs has been well documented, only a few cases using this type of completion in openhole intervals greater than 800 ft in length have been implemented in Latin American land wells. Recent field studies involving openhole gravel packs in long intervals were carried out in the Ocelote field in the Llanos basin of Colombia. The operating company of the field is Hocol S.A., (subsidiary of Ecopetrol) and after many trials and the use of various service providers and tools, the final customized methodology and equipment of one particular service company were selected and implemented for the openhole completion campaign of the entire field.

The wells completed previously in this field were thoroughly analyzed. Because of operational and design issues, pack efficiency in one well was greater than 90%; however, in all of the other wells, only 50% pack efficiency was achieved. This analysis covers the reason why pack efficiency was consistently low in the first three wells, steps taken to correct them, and new service company to guarantee 100% pack efficiency in the subsequent openhole gravel packs, and the new tool designs implemented to solve the existing issues that guaranteed the successful gravel-pack operation in the remaining wells in the campaign. The step-by-step methodology chosen and implemented in the design of each job are presented, including the type and gravel pack material and selection of the correct gravel-pack tools to mitigate potential problems and the selection of the appropriate screens impacting the final outcome.

Finally, data from the subsequent wells that were gravel packed using the new methodology are presented, including the tools used and the technology used to consistently achieve 100% pack efficiency in all of the remaining wells in the field. Conclusions are presented, in addition to individual well performance comparisons.
Experiments and Model Assessment on High-Viscosity Oil/Water Inclined Pipe Flows
Authors: Sridhar Siddesh , Zhang Hong-Quan , Sarica Cem , Pereyra Eduardo
Published: October 2011

An experimental study has been conducted to investigate high-viscosity oil/water flow in inclined pipes. The pipe inside diameter (ID) is 50.8 mm and pipe inclination angles are −2°, 0°, 5° and 10° from horizontal. The fluids are a mineral oil with a viscosity range of 0.2 – 1.1 Pas corresponding to temperatures 60 –100 °F and filtered tap water. Tulsa city natural gas was used to pressurize the facility to 250 (+20) psig. Superficial oil velocity ranged from 0.1 to 1 m/s and superficial water velocity ranged from 0.1 to 0.5 m/s. Experimental measurements obtained are pressure gradient and water holdup. Pipe viscometer was used to obtain live oil viscosity measurements. Flow patterns were observed through a sapphire window and recorded with a high speed video system. The experimental measurements and observations are used to compare with mechanistic model predictions to identify the deficiencies in the models.
3D Multiphase Streamline-Based Method for Interpretation of Formation-Tester Measurements Acquired in Vertical and Deviated Wells
Authors: Hadibeik Hamid , Pour Rohollah A. , Torres-Verdín Carlos , Sepehrnoori Kamy , Shabro Vahid
Published: October 2011

Complex heterogeneous reservoirs penetrated by deviated wells pose significant challenges when modeling and interpreting packer- and probe-type formation-tester measurements. This paper introduces a streamline-based method specifically designed for near-wellbore fluid-flow modeling in vertical and deviated wells. The primary application of the method is for efficient simulation and automatic history matching of formation-tester measurements in the presence of invasion and variable petrophysical and geometrical properties. Based on the spatial distribution of pressure calculated with a previously validated near-wellbore finite-difference model (FDM), the method traces streamlines from the reservoir into fluid sampling probes. The calculated spatial distribution of pressure is input to the streamline-based method to propagate the spatial distribution of water saturation. Subsequently, the calculated spatial distribution of water saturation is input to the FDM to update the spatial distribution of pressure. Streamlines are then recalculated and this repeated pressure-saturation procedure continues until reaching the desired final simulation time.

The combined FDM and streamline-based method utilize full-tensor permeability to couple wellbore-reservoir systems during fluid sampling in horizontal and deviated wells. It is shown that the spatial rendering of streamlines permits rapid assessment of the time evolution of fluid saturation near the sampling probe. We successfully test the streamline-based method in the dynamic simulation of fluid contamination into conventional and focused-type probes operating in vertical, horizontal, and deviated wells for the case of multiphase, immiscible fluid-flow in heterogeneous formations. The method implements successive streamline and FDM time steps adaptively to decrease computational time by a factor of four while achieving less than 5% relative difference in the simulation of fluid production measurements when compared to FDM results.

For formation testing in deviated wells, the streamline-based method permits more rapid appraisal of anisotropy, bedboundary, and complex geometrical effects on fluid-sampling times than conventional 3D fluid-flow simulators. It also quantifies the sensitivity of measurements to variations of permeability, invaded zones, anisotropy, and well deviation. Our simulations indicate that fluid sampling in deviated wells subject to mud-filtrate contamination requires adequate positioning of the probe around the perimeter of the wellbore to secure the fasted cleanup possible.
Integration of Dynamic Modeling of ICD Completion Design and Well Placement Technology: A Case Study of GOM Shelf Reservoir
Authors: Sharma A. , Kok J. C. , Neuschaefer R. , Han S. Y. , Bieltz T. , Obvintsev A. , Riegler P.
Published: October 2011

High water production is a major issue in horizontal oil wells, especially in longer laterals, because of the high drawdown from the heel to toe. In addition, the presence of heterogeneity along the lateral section can lead to uneven sweep of hydrocarbons which can result in poor recovery. To control the water production and achieve better sweep efficiency, ICDs have been introduced which balance fluid flux along the producing horizontal well.

This paper discusses the feasibility and results of using integrated technologies such as ICDs along with rotary steerable drilling systems (RSS) and azimuthal logging while drilling well placement technology to achieve higher reservoir sweep efficiency. This case study is focused on a Gulf of Mexico (GoM) shelf horizontal well which was completed with prepacked screens. The well was sanded in and plugged after five years of high water production. A saturation log was run in the offset well which granted the viability to revisit this reservoir. Consequently, a new offset horizontal well was proposed and drilled next to the existing well to sweep out remaining reserves.

For the new offset well, full field dynamic simulations were performed to evaluate attic placement methodology and optimization of Inflow Control Devices (ICDs) into the integrated design. The results illustrate that attic horizontal well placement is feasible using integrated drilling with ICD technology to maximize the sweep efficiency.
Understanding and Handling Residual Risks
Authors: Zhao J.
Published: October 2011

Risk management and risk analysis techniques have been widely discussed and utilized in many energy firms. They are pro-active tools giving decision-makers forewarnings and scientific predictions. However, a less well known concept in the arena of risk management is worth elaborating. Residual risk, a terminology not common to most people in our industry, is rarely mentioned and discussed in the literature; it still remains a poorly understood notion. It often is confused with the Secondary Risk, and easily mistaken for missed risks in risk identification process. Depicted as" leftovers", residual risks are often neglected in risk management process as many regard such risks are well covered under ALARP (as low as reasonably possible). Moreover, residual risks are often deliberately eliminated from stochastic modelling process as many risk analysts reckon that extreme cases, beyond" normal" 80% confidence range, are not worth considering. In reality when unpleasant events occur the real culprit is more often than not either rare event driven risk or residual risk that caught people off guard.

The treatment of residual risks requires both diligent prudence and well thought-through risk taking. Failure Model Effect Analysis (FMEA) is often deployed to assess the severity of such risks, hence helping management better understand the devastation in case they occur." Normally ranged" risks would often be handled by scientific manner and decisions are relatively easy, however, there isn't a clear path to handle residual risks, as it is not a pure mathematical exercise but demands strong incorporation of psychological judgement as well. The paper challenges decision makers to appreciate true implications of residual risks, and what they are about to bring to their businesses. The author, through the illustration of examples, proposes a residual risk handling process that combines qualitative risk assessment, psychology of risk taking and Monte Carlo simulation techniques. The process mainly applies to early phase project development and business case fruition process where large uncertainties may easily affect decision-makers, but it is also applicable to project execution phase.

Key words: Residual Risk, Risk-taking, Psychology
Review of a Stratigraphic Reservoir Exploration Proven by Production: A Case Study
Authors: Ling Yun , Guo Xiangyu , Gao Jun , Sun Desheng , Lin Jixiang
Published: October 2011

The limitation of conventional seismic resolution (such as 1/4 wavelength) made thin bed reservoir exploration a difficult task. But with recent developments in oil and gas exploration, thin bed reservoirs are now becoming a common topic, especially in predicting the remaining oil in mature oilfields. For successful thin bed reservoir exploration, it is very important to overcome the conventional resolution limitations. In 2003, we began research on a thin bed lithologic reservoir in the Tarim basin, Northwest China. Based on the relative reservoir information preserved processing result and with the application of relative spatial resolution concepts based on isochronous geologic interfaces, prediction of a thin bed lithologic trap and oil-water contact was made. Production of this reservoir has since proven the prediction.
Incremental Recoveries in the Field of Large Scale High Viscous-Elastic Fluid Flooding are Double that of Conventional Polymer Flooding
Authors: Demin Wang , Gang Wang , Huifen Xia , Shuren Yang , Wenxiang Wu
Published: October 2011

By conventional mechanism, polymer flooding decreases the Mobility Ratio and increases the Sweep Efficiency and Recovery of the reservoir, but does not increase the Displacement Efficiency (ED).

However, from new understanding of the mechanism that driving fluid elasticity can increase the ED, Daqing Oil Field started 2 field pilot tests of high elasticity fluid flooding in year 2002, the actual recoveries are all more than 21%OOIP above that of water flooding, with incremental recoveries about double that of conventional polymer flooding (viscosity at 40~60 cp). Due to the very good results, in the recent 3 years, Daqing has rapidly expanded high viscous-elastic fluid flooding to more than 5000 wells. From the results of 1000 wells that have used this EOR method for a sufficient time to predict the results from field data, all will attain an incremental recovery of more than 20%OOIP; the other wells, according to numerical simulation, are performing as expected.

Some new knowledge on the mechanism of viscous-elasticity of the driving fluid mobilizing residual oil is also presented.

Field experience shows the difficulties in solving the problems of producing, pumping, gathering and treating produced fluid from high viscous-elastic floods are about the same as that of conventional polymer floods and much easier to solve than alkaline-surfactant-polymer (ASP) floods.

The field results also show that the economics (costs per ton of produce oil) of this EOR method is about the same as conventional polymer flooding.

In Daqing, very large scale high elasticity flooding is taking the place of conventional polymer flooding and ASP flooding to further increase the field recovery from 42% OOIP for water flooding to above 60%OOIP for high elastic fluid flooding. More than 2000 wells are converted to this method per year.

This is a very promising new EOR method that could be used by itself or in conjunction with other Chemical EOR methods to significantly increase the recovery of many types of oil-fields.
Considerations for Field Implementation of Microbial Enhanced Oil Recovery
Authors: Jackson Scott C. , Fisher John , Alsop Albert , Fallon Robert
Published: October 2011

For the last 6 years DuPont with different partners has done extensive fundamental research into the application of Microbial Enhanced Oil Recovery technology (MEOR).

We have demonstrated two mechanisms that have shown in the lab, more than a 10% increase in the recovery factor.

Increased sweep efficiency by plugging of high permeable zones thereby forcing water to produce oil from previously unswept parts of the reservoir. Reduced oil / rock surface tension resulting in lower residual oil saturation.

This paper describes the key laboratory tests and preliminary field data used to evaluate these two mechanisms.

Our approach has been to inoculate the reservoir with a microbe that under the optimal nutrient conditions will expressed the needed function -- bioplugging or reduced oil saturation. The microbe and the nutrients are tailored to the conditions of each reservoir thus giving MEOR the greatest chance for success. This paper presents challenges that were raised as a result of extensive lab work that are relevant to the implementation of MEOR on a field level.

Our ongoing research has provided many insights into the appropriate application of microbial EOR. The unique aspects of each production area, the nature of the oil, the water, the formation matrix, and the background microbial population and their complex interactions must all be assessed when considering the potential application of microbial EOR. The amount of work described for assessing potential MEOR mechanisms is extensive. However, this process has been streamlined and we have been able to assess new target reservoirs for potential MEOR treatments in about 6 months.

We believe that Microbially Enhanced Oil Recovery has the potential to improve the recovery of oil with the potential for very low capital investment and a much smaller environmental footprint compared to other EOR techniques.
Field Application of Very High Volume ESP Lift Systems for Shale Gas Fracture Water Supply in Horn River, Canada
Authors: Coppola Geoffrey C , Chachula Ryan C
Published: October 2011

Unconventional shale gas plays are emerging and undergoing rapid development at an alarming rate across North America. One of the most challenging dynamics of the Horn River, British Columbia, Canada shale play has been the increasing number of fracture stimulations required per horizontal wellbore. Of critical importance is the massive volume of water required to supply the 24/7 fracturing operations. In an effort to eliminate the reliance on surface waters, Encana engaged in a novel approach to produce high volumes of sour waters from a relatively unknown under-pressurized saline aquifer. The challenge was designin7g an appropriate high volume lift system capable of producing and achieving volumes of up to 8,500 m3/d/wellbore while addressing unknown fluid inflows, fluid transmissibility & re-charge, and reservoir fluid chemistry characteristics.

Electric submersible pumps (ESPs) have proved to be a successful and reliable artificial lift system for production of high volumes of fluid for many decades. This paper describes the steps undertaken by Encana in designing, piloting and successful field implementation of full scale high volume sour water lift ESP systems. These systems have demonstrated significant potential to alleviate the high costs, production withdrawal limitations and environmental impact of delivering large volumes of fracture supply waters in a remote Northerly region. Modifications to the wellbore completion architecture, equipment design and techniques to optimize pumping operations and water distribution from the field trials are presented.
Field Proven Solutions to the Challenges of Centralizing Solid Expandable Casing
Authors: Farley Douglas , Scott Thad
Published: October 2011

During well design and construction, the cementing of tubulars into the wellbore, referred to as primary cementation, has always been a critical step because the introduction of cement into the annulus between the tubular and open hole provides zonal isolation. It is well documented by API, SPE and other industry publications that achieving a good cement bond depends on the proper selection and placement of centralizers onto the pipe being cemented. In addition, getting the pipe to total depth (TD) is one of the most important objectives in the well construction process. Proper placement of centralizers drastically reduces the effects of differential sticking of slick OD tubulars when running across permeable formations and increases the chance of getting to TD. Once at TD, centralizers play a very important role by aiding in mud removal, which allows the cement to flow into the proper position with minimal channeling.

Solid expandable liners are most often run without centralization due to the very nature of expanding tubulars and the effect that the centralizers would have on the expansion forces. Another contributing factor is the tight clearances between the host casing and the expandable tubulars that are present in many applications. Adding to these challenges is the need for proper standoff to aid mud removal in the underreamed hole section in which the expandable tubulars are deployed. Solid expandable liners provide a drilling hazard mitigation technique covering pressure anomalies in the wellbore and their use in horizontal wells for maximum oil recovery furthers the importance of centralization for drag reduction, zonal isolation and the prevention of differential sticking.

In this paper the authors will review the cementing process and the problems associated with centralizers and explore several novel, field-proven and developing approaches to centralizing solid expandable pipe using both positive standoff and bowspring centralizers.
Advanced Upscaling For Kashagan Reservoir Modelling
Authors: Panfili P. , Cominelli A. , Calabrese M. , Albertini C. , Savitskiy A. , Leoni G.
Published: October 2011

The Kashagan field is a huge carbonate formation located 4.5 km below the North Capian sea bottom. The reservoir is saturated by over pressured light oil and the development is based on first contact miscible gas injection.

The reservoir is highly stratified, with a fine sequence of depositional cycles and long range lateral correlations. Three porosity systems, matrix, karst and fractures can be organized in two main environments: a massive, low permeability, matrixlike inner platform and a highly fractured/karstified rim.

The reservoir geology is modelled by means of massive geological grids consisting of tens of millions of cells, with vertical spacing of one meter or even less to account for high order depositional cycles. Fine scale geological grid cannot be used to run compositional simulations and much coarser grids, where hundreds of geological layers are lumped in few tens of dynamic layers, are used by reservoir engineers. To minimize errors due to the coarse scale, an average lateral spacing of 250 m × 250 m is used for both simulation and geological grid, but nonetheless upscaling remains a challenge. Traditional permeability (k*) upscaling methods, including flow based methods, overestimate Kashagan field/wells production and injection potentials.

We implemented a methodology where the outcome of the upscaling are effective transmissibility (T*) instead than k*. T* upscaling has been proposed in the past as an alternative to k* upscaling, but it is neither part of commercial work-flows nor widely accepted in the reservoir modeling community. In our T* upscaling the solution of local flow problems around coarse cell interfaces is used to compute coarse transmissibility. T* and k* upscaling were compared by simulating both single phase and gas injection problems, including platform and rim, using the results of fine scale simulation as reference. We considered single porosity simulations with geological grid populated by only matrix (first medium) and karst+fracture (second medium) properties and dual porosity/dual permeability simulations encompassing both media. Contrary to k* upscaling, T* based coarse simulations perfectly replicate fine scale field and wells injection/production potentials.

Using T* upscaling as cornerstone for Company activities on Kashagan, we can run coarse scale full field simulations in few hours without loss of consistency with the results provided by weeks-long, often unpractical, fine scale simulations. On the contrary, the inaccuracy of k* upscaling would have required much finer and computationally expensive simulation grids together with the implementation of ad-hoc multi-phase upscaling.
Field Development Optimization with Subsurface Uncertainties
Authors: Litvak Michael , Onwunalu Jerome , Baxter Josh
Published: October 2011

This paper outlines a framework for simultaneous optimization of a broad range of field development decisions with subsurface uncertainties.

We optimize discrete and continuous decision variables such as the number of production or injection wells, their locations, perforation intervals, drilling schedules, well rates, etc. As a novel approach, we include additional categorical variables such as depletion strategy, well pattern, or facility size in the optimization process. We consider a limited number of discrete scenarios for each categorical variable (e.g., primary depletion, gas injection, or water injection as three development scenarios).

Field development constraints on well locations, rig schedules, economic risks etc. are incorporated in the optimization. Hydrocarbon recovery or some economic indicator can be used as the objective function for the optimization and applied for ranking the field development options.

Subsurface uncertainties are represented by incorporating multiple reservoir models in the optimization process. Ideally, all reservoir models in the ensemble should be evaluated for every considered field development option to define cumulative probability functions. However, this would make CPU demands very large in some cases. We propose two effective approaches to reduce CPU requirements: (1) one reservoir model is run to test the optimization criterion, and the remaining models are only run if the objective function is significantly improved; or (2) a novel application of a statistical proxy procedure to define a subset of the reservoir model ensemble that is run during the optimization cycle. The efficiencies gained with these techniques allow us to incorporate the additional decision variables in the full optimization process.

Our results indicate that the proposed algorithms sufficiently reduce CPU requirements to effectively handle field development optimization problems with many reservoir models representing subsurface uncertainties. The algorithms have been effectively applied in many fields for simultaneous optimization of well placement, drilling schedule, well production/injection rates, perforation strategy, injection strategy, and facility modifications. They have also been successfully applied in giant oil/gas fields optimizing general field development scenarios.
Well Completion Design Using High-Performance Passive Inflow Control Devices with Selective Isolation Capability
Authors: Coronado Martin P. , Peterson Elmer R. , Garcia Luis A. , Garcia Gonzalo A.
Published: October 2011

In long horizontal wells, oil production rate is typically affected by the reservoir heterogeneities, heel-to-toe effect and mobility ratio. The resulting imbalanced production profile may cause early water or gas breakthrough into the wellbore. Once coning occurs, well fluid production may be severely decreased due to limited flow contribution from the toe or from reservoir areas with high flow resistance in the porous media. To eliminate this imbalance, passive inflow control devices (PICDs) are placed in each screen joint or inflow point to balance the production influx profile across the entire lateral length and compensate for permeability variation.

PICD performance in producer (oil, gas, and high gas/oil ratio environments) wells under different operational conditions will be presented to show the technical benefits of this technique as well as their improved recovery efficiencies when compared to non-PICD completions. The quantification of the benefits of this completion technique was performed using a fully integrated reservoir simulator where the PICD flow performance characteristic (as a function of fluid properties and geometry), well completion description (packers, blank pipe, gravel pack, annulus flow, etc.) and reservoir simulation are considered. The latest-generation PICD design incorporates an integral sliding sleeve which allows selective isolation of portions of the wellbore during the course of a well's life. Shutting off whole sections that have unacceptably high water and/or gas production using the latest PICD feature is also modeled to show improved recovery performance.

This paper details the development of the latest-generation PICD design concept which provides the ability to isolate zones selectively as sections of the completion become uneconomical. Experience from the initial field installations of this new technology will also be discussed.
Analysis of Calibration Materials to Improve Dual-energy CT Scanning for Petrophysical Applications
Authors: Ayyalasomayajula Krishna K. , McIntyre Dustin L. , Jain Jinesh C. , Singh Jagdish. P. , Yu-Yueh Fang , Siddiqui Shameem
Published: October 2011

Dual energy CT-scanning is a rapidly emerging imaging technique employed in non-destructive evaluation of various materials. Although CT (Computerized Tomography) has been used for characterizing rocks and visualizing and quantifying multiphase flow through rocks for over 25 years, most of the scanning is done at a voltage setting above 100 kV for taking advantage of the Compton scattering (CS) effect, which responds to density changes. Below 100 kV the photoelectric effect (PE) is dominant which responds to the effective atomic numbers (Zeff), which is directly related to the photo electric factor. Using the combination of the two effects helps in better characterization of reservoir rocks. The most common technique for dual energy CT-scanning relies on homogeneous calibration standards to produce the most accurate decoupled data. However, the use of calibration standards with impurities increases the probability of error in the reconstructed data and results in poor rock characterization. This work combines ICP-OES (inductively coupled plasma optical emission spectroscopy) and LIBS (laser induced breakdown spectroscopy) analytical techniques to quantify the type and level of impurities in a set of commercially purchased calibration standards used in dual-energy scanning. The Zeff data on the calibration standards with and without impurity data were calculated using the weighted linear combination of the various elements present and used in calculating Zeff using the dual energy technique. Results show 2 to 5% difference in predicted Zeff values which may affect the corresponding log calibrations. The effect that these techniques have on improving material identification data is discussed and analyzed. The workflow developed in this paper will translate to a more accurate material identification estimates for unknown samples and improve calibration of well logging tools.
Utilization of Simple Fluids and Proppant Combined with Design Optimization Yields Outstanding Results in New Mexico Yeso-San Andres Oil Play
Authors: Ely John W , Jacoby Mark
Published: October 2011

In this paper we will describe fairly simplistic completion techniques which have dramatically changed the economics of completion in the Yeso and San Andres formations in southeastern New Mexico. The design optimization process will be described and comparisons made with offset operators for several years of production.

For many years the standard completion technique for the Yeso and other carbonate formations in Southeastern New Mexico was the use of large volumes of hydrochloric acid. The acid was sometimes heated, sometimes gelled. The acid was combined with various diverting aids to achieve what was considered excellent stimulation. In 2006 it was decided to reevaluate stimulation procedures and the oil company decided to use a similar process being utilized in Shale plays and many unconventional reservoirs. The Yeso and San Andres, with some natural fracturing and most of other criteria needed for successful use of what is termed "Waterfrac Sweep", were considered good candidates. This process uses only water and small proppant concentrations pumped at a high rate. The process has found success in virtually every shale play in the US as well as many conventional reservoirs such as the Granite Wash, Cotton Valley, Mesa Verde, Travis Peak, Atoka, and Olmos.

The paper will document the results of more than 100 fracs showing long term production data and comparisons to offset operators using more complex and more expensive systems. We will go through the completion process as it was used in large casing, thus in many instances totally eliminating the need for friction reducers. Very minimal chemicals are used plus proppant sizes no larger than 40/70 in concentrations not exceeding 2.5 pounds per gallon. Based on oil production data we feel infinite conductivity production is being achieved through propped open fractures instead of proppant packs.

There are countless naturally fractured carbonate reservoirs throughout the world that can benefit from this very straightforward stimulation procedure.
Reservoir Simulation: A Reliable Technology?
Authors: Lee W. J. , Sidle R. E. , McVay D. A.
Published: October 2011

Under pre-2009 SEC reserves reporting guidance, filers with the SEC had difficulty in persuading the SEC staff that reservoir simulation met the ‘reasonable certainty’ standards required to classify resources as proved reserves. With the modernization of the SEC's reserves reporting rules, ‘reliable technology,’ including computational methods, is allowed to establish the certainty level required for reporting reserves of any category. However, important questions arise: can we consider reservoir simulation to be a reliable technology? If so, what conditions must be satisfied to establish reliability? This paper concludes that simulation is indeed a potential reliable technology when we can demonstrate that it satisfies the criteria of consistency and repeatability, difficult criteria to satisfy for a computational method. The paper also concludes that the reserves analyst can demonstrate when simulation is reliable by proceeding through the steps in the scientific method outlined by Sidle and Lee (2010a) which provide guidelines to establish that a particular technology in question is consistent with the definition of a reliable technology.

At the reasonable certainty level required for proved reserves, we must demonstrate with empirical evidence that estimates of EUR based on simulation are much more likely than not to increase or remain constant as more historical data become available. For 2P (proved plus probable) reserves, we must demonstrate that EUR forecasts are as likely as not as more reservoir performance data become available, and for 3P reserves, EUR forecasts must remain possible though not likely. Empirical evidence that the required level of certainty has been achieved can come from either ‘hind-casting’ (successfully predicting the future based on only a portion of historical data) or from demonstrated success from applying the same simulation technology in analogous reservoirs, in which the same level of rigor was applied to ensure that the geological model or models used as the basis for simulation is appropriate and that it honors all available information.

When the industry broadly accepts reservoir simulation as a reliable technology (when applied appropriately) suitable for use in reserves disclosures and when it provides persuasive arguments about reliability to regulatory agencies, the interests of all stakeholders in reserves disclosure efforts will be enhanced.
Improved Estimation of Permeability from Joint Inversion of Time-Lapse Crosswell Electromagnetic and Production Data using Gradient-Based Method
Authors: Liang Lin , Abubakar Aria , Habashy Tarek M.
Published: October 2011

Formation permeability is one of the most important parameters for reservoir modeling. There is a high degree of uncertainty associated with the estimation of permeability using the conventional history matching, which adjusts the model to only fit the production data. In this paper, we present an approach to improve the estimation of permeability by history matching time-lapse crosswell electromagnetic and production data simultaneously. A multiphase fluid-flow simulator is used to calculate the time dependent bottomhole pressure at the wells as well as the temporal and spatial distributions of water saturation and salt concentration in the reservoir. The latter ones are transformed into the formation resistivity using a resistivity-saturation formula. A 3D finite difference electromagnetic solver is used to simulate the crosswell electromagnetic data. A regularized Gauss-Newton approach is then used to update the permeability in an iterative fashion until achieving a good match between the simulated and the measured data. In the inversion process, the derivatives of production data with respect to permeability are computed using the gradient simulator method, and the derivatives of electromagnetic data with respect to permeability are computed using the adjoint method and the chain rule.
Demonstrating Reasonable Certainty under Principles-based Oil and Gas Reserves Regulations
Authors: Sidle R. E. , Lee W. John
Published: October 2011

Historically, oil and gas reserves definitions have included the term "reasonable certainty" when describing the standard of high confidence/low uncertainty for a conservative estimate of future recovery from an accumulation. In 2008, the U.S. Securities and Exchange Commission (SEC), one source for such definitions and regulations, changed its rules on oil and gas reserves, and moved from a more rules-based approach to a more principles-based approach. While the SEC regulations both before and after this change incorporated the term "reasonable certainty", the philosophical change from rules-based to principles-based regulation puts more responsibility on the reserves evaluator to understand the uncertainties in the reserves estimation and to "get it right".

This paper examines the stated definition of reasonable certainty as well as the effective definition based on how the regulations were interpreted under the prior rules-based system. Examples of prior methods of regulatory controls, under a rules-based system, that no longer fit under a principles-based system are noted. The paper then examines the current definition. The overprint of a principles-based regulatory system must be considered to understand how such an approach will impact the effective definition under the current rules. The insights from the financial and legal communities are examined for their learnings where other forms of regulations underwent this same philosophical change. This examination describes how rules-based systems are more "input control" focused, while principles-based systems focus more on "outcomes".

Next the paper suggests how the reserves evaluator should apply this understanding of the new principles-based rules. The evaluator is now more responsible to understand the range of uncertainty in reserves estimates and to ensure that the outcome (the proved reserves estimate) satisfies the regulations. Also the paper discusses key tests to demonstrate that the correct outcome, a reasonably certain volume, has been achieved. After 30 years of well-established practices, the responsible reserves evaluator has examined changes as they evolved in then-current regulation text. Now the evaluator needs to additionally consider changes based on the implications of principles-based regulations.
Generalization of Dual-Porosity-System Representation and Reservoir Simulation of Hydraulic Fracturing-Stimulated Shale Gas Reservoirs
Authors: Du C. Mike , Zhan Lang , Li James , Zhang Xu , Church Stefan , Tushingham Keith , Hay Brad
Published: October 2011

Recently, we have developed a new methodology to model hydraulic fracturing-induced fracture networks and subsequently simulate a shale gas reservoir as a dual-porosity system. The reservoir geological, geophysical and petrophysical characteristic data are integrated to build geological framework and property models. Microseismic responses are used to delineate stimulated reservoir volumes. Microseismic events and/or natural fracture intensity are utilized to estimate the initial intensity of this induced fracture network. The fracture intensity is further calibrated using hydraulic fracturing job data and reservoir geomechanical properties through a fracture propagation mechanism.

In this paper, we show a significant extension of the modeling methodology to handle more general scenarios of stimulated shale reservoirs. We introduce a superposition technique to process the overlapping of microseismic mapping responses from different stages of "simul-frac" and/or "zipper-frac" operations in a single well or in multiple wells. The improved method takes into account different fracture network geometries. Various models for volume expansion by stimulation are investigated for proppant placement estimations. In the ideal viscous fluid-proppant transportation scenario, proppant and fracture conductivity distributions can be calculated with mass conservation corresponding to different fracture network geometries and volume expansion models. Both fracture intensity and fracture network conductivity are used to create dual porosity simulation model inputs. Considering that for most shale gas wells there is no microseismic data, we introduce a modeling procedure incorporating treatment data and geomechanical parameters in which the fracture network geometry can be specified based on well completion data and field experience. We also present the general workflow through a demo case from data input, fracture network geometry configuration, calibration and calculations, and output of dual-porosity model parameters for reservoir simulation. This extended methodology can be efficiently applied not only to modeling of singlewell shale gas reservoir but also to modeling of multiple wells where their drainage volumes are inter-connected. A field example demonstrates the applications of the new modeling methodology, which provides a unique, effective means for modeling and simulation study as well as history-matching calibration of stimulated shale gas reservoirs.
Intelligent Appraisal Program for a Multi-Prospect Development
Authors: Delfiner Pierre
Published: October 2011

While many companies are hunting for elephants, exploration results in deep offshore plays over the past years show the increasing trend away from giant field discoveries towards smaller fields in the 50-100 million bbl range, which tend to be geographically dispersed. These resources need to accumulate to a critical mass to justify an economically viable development. How likely is this to happen? Which objects must be included in the resource base? Which drilling program should be planned to reach an early decision? Given the huge costs involved, answers cannot rely on the subjective choice of a few deterministic scenarios.

A novel methodology is proposed to evaluate the potential for a hub in a deepwater multi-prospect development. The approach relies on a probabilistic model of the risks and uncertainties of the resource base, illustrated by a real case study including five discoveries and four prospects, 10-30 km apart. Each object must pass a minimum resource threshold to justify its connection to the hub. Then a global threshold is applied to the complete development.

The performance of a proposed appraisal program is quantified by statistical indicators obtained by simulating a large number of drilling outcomes which are stored in a scenario database. Three indicators capturing the three elements of Decision Analysis (states of nature, decisions, payoffs) prove useful. These are respectively: the distribution of the resource potential in the ground; the probability of a development decision based on the cumulative discovered exceeding the threshold; and the distribution of developed resources. The last two elements define the traditional economic decision tree.

Intelligence is introduced in the appraisal program by reassessing the situation after each well and evaluating the probability of meeting the threshold with the remaining wells. If it is low (10% or less) appraisal is stopped, or its scope reduced. Early quitting minimizes well count in the dry branch of the economic decision tree, which has a great impact on risked economics. Optimizing the drilling order may also reduce the number of wells needed to reach a decision. Thus an efficient appraisal program with firm and contingent wells can be defined.
The Sanding Mechanisms of Water Injectors and their Quantification in Terms of Sand Production: Example of the Buzzard Field (UKCS)
Authors: Santarelli F. J. , Sanfilippo F. , Embry J. M. , White M. , Turnbull J.
Published: October 2011

The sanding of water injectors is considered a serious issue, as it can trigger important injectivity reductions and may sometimes and may sometimes lead to the collapse of wells. Cross-flow during shut-in and the water hammer pressure wave generated by the well closure are recognized as the main contributing factors to sanding. However the paper will show that the precise mechanisms of sanding on water injectors have not been fully described yet.

The unexpected and early collapse of an injector on the Buzzard field - i.e. the largest current oil producer in the UK - required the evaluation of the sanding risk for the other 12 injection wells, as the loss of another one would have been critical in terms of field management. The complete records of all the wells, including their injection histories were therefore recovered and analysed.

The analysis revealed that four sanding mechanisms were at play:

Natural cross-flow between layers at pressure equilibrium, Forced cross-flow between layers not at pressure equilibrium, Swabbing from the water-hammer pressure-wave, Surface-flow between wells.

The occurrence of each mechanism for each well was checked and quantified through field data analysis, modeling and direct downhole measurements (injection logs and video). In particular, the amount of sand produced by each mechanism was quantified. The analysis showed that the forced cross-flow on the collapsed well had produced sand quantities orders of magnitude larger than what was experienced by the other wells and the risk of losing another well was therefore judged minimum. In addition measures were taken to limit the impact of all four mechanisms on the existing wells and a methodology was devised to avoid the conditions of the collapsed well on future wells.

The paper presents a complete methodology for quantifying the risk associated with the sanding of injectors. In addition the measures taken to limit the impact of the various sanding mechanisms can easily be implemented without significant costs to all wells injecting in weak reservoirs.
A Unique Plug for a Restricted Wellbore
Authors: Blevins Joy , Frazier Garrett
Published: October 2011

The completion of most cased-hole horizontal shale wells requires multi-stage stimulations, which calls for some form of plug isolation between the stages. The plugs are normally composite flow-thru plugs that are pumped downhole on electric wire to the required measured depth.

This case history describes a project where the industry's standard-sized composite plugs with a 3.85-3.92 in. outer diameter (OD) would not pass through the curved section of the horizontal wellbore with an internal diameter (ID) of 4.276 in. Small doglegs in the curved section of the wellbore presented geometrical and completion challenges. Three attempts to push the plugs through this section of the wellbore failed, resulting in the plugs getting stuck. The project faced a challenge: Could a plug be built in a timely manner that would pass through the curve restrictions, set in the production casing, withstand stimulation pressure, and still be drillable?

The project challenge was successfully answered. A new composite plug was designed that met all of the wellbore requirements and allowed a successful completion of the wellbore. The 3.25 in. OD flow-thru composite plug was set in a 4.276 in. inner diameter (ID) production casing. Altogether, six plugs were pumped down and set in the wellbore of the West Texas, University Land 39 #29-1H well. The plug met all of the required performance expectations during all stages of the completion.

This plug's application goes beyond the standard horizontal wellbore with multi-stage stimulation requirements. The uniqueness of this plug is its ability to be modified for a variety of applications where reduced internal diameters in production casing create completion challenges below the restriction.

The details of the wellbore deviations and the final plug design solution are included in this paper.