bluuebunny/crossref_metadata_2025 huggingface dataset:
Guidelines for the Handling of Natural Fractures and Faults in Hydraulically Stimulated Resource Plays
Authors: Stephenson B. , Coflin K.
Published: October 2015

Do fractures help or hinder production in hydraulically stimulated resource plays? Most say they help, but some say they hinder. After monitoring productivity for over 10 years in a number of plays in Shell's unconventional portfolio, it appears that the evidence for fractures helping is more conceptual than empirical, further substantiated by a detailed literature review. The objective of this paper therefore is to bring some objectivity to the discussion around the impact of structure using logical arguments by reason, incorporating knowledge of the variability in structure and well performance within the spectrum of unconventional plays.

Fundamental to this assessment is the recognition that different scales of features will have a markedly different impact. And to communicate the concepts herein, small-scale features are referred to as "natural fractures" and large-scale features, referred to as "faults" or "lineaments".

This analysis indicates that the variability in (small-scale) natural fracture intensity across most plays is not sufficient to be detected in well performance metrics, given the other sub-surface heterogeneity and the large range in estimated ultimate recovery (EUR) for any given set of wells. Furthermore, natural fracture connectivity is typically low and stimulation of networks is not supported by data or trials. It is proposed to consider natural fractures as an intrinsic rock property which will modify the bulk geomechanical properties of the formation. The only exception found was for folded tight-sand plays, where fracture network connectivity may be sufficient to provide a measurable enhanced deliverability.

Understanding the impact of seismically-visible, planar, structural features (e.g. faults or lineaments) proved to be more problematic, with operators reporting both EUR increases and decreases. This inconsistency is explained with a novel concept classifying faults as contained or uncontained, contingent on whether they are within a closed fluid- and pressure-contained system, or not (respectively) before and after hydraulic stimulation.

Rather than searching for a production performance correlation, it is suggested that an enhanced understanding of the physical processes during a hydraulic stimulation would be more beneficial to clarify the impact of structure. And to this aim, a compilation of potential fracturing diagnostics is presented herein.
The Well Factory Approach to Developing Unconventionals: A Case Study from the Permian Basin Wolfcamp Play
Authors: Rexilius Jarrad
Published: October 2015

In order for operators to grow production and maintain profit margins in unconventional resource plays, a ‘Well Factory’ or ‘Manufacturing’ style of development is often employed. These types of plays are commonly termed ‘statistical’ and the popular school of thought is to drill and complete hundreds (or thousands) of wells in the same manner and design. Such a strategy, likened to the assembly line model that made the car manufacturing industry so successful, requires making some general assumptions regarding subsurface and surface homogeneity across the field. There are both merits and potential drawbacks to employing an overly strict well factory approach to development with standardized designs. A manufacturing style typically results in faster execution speeds and improved efficiency, meaning more wells on production over a shorter period of time at a lower cost. This approach also lends itself to taking advantage of economies of scale, by applying standard designs across multiple rig lines over a large geographical area. However there are drawbacks to this approach if not implemented appropriately, including slower adoption of industry best practices, suppressed innovation, and increased likelihood of value erosion due to lower well recoveries as a result of suboptimal or incomplete subsurface characterization.

This paper will analyse differing well factory approaches to unconventional assets, using examples from the Wolfcamp Unconventional Oil Play in the Permian Basin. The Wolfcamp play is one of most active and mature unconventional oil plays in the world, with over 200 industry rigs currently developing the resource base, and more than 12,000 industry wells already drilled.

An emphasis is placed on utilizing a factory model that enables flexibility for project execution teams to optimize, while maintaining the efficiency and execution speeds that a classical factory model provides. Ultimately it is imperative that operators can adapt to the ever-evolving nature of these plays, as technology, research, and well performance data matures. It is also important that operators can trial new ideas and concepts with a ‘learn fast-fail fast’ culture that does not interrupt the factory performance. This paper will present a framework for a well factory process to most optimally develop an unconventional resource play, with the caveat that all fields and plays are different and a ‘one size fits all’ approach rarely applies in any oil field application, let alone an unconventional play.
The Use of Completion Diagnostics in Haynesville Shale Horizontal Wells to Monitor Fracture Propagation, Well Communication, and Production Impact
Authors: Sani Abu M. , Podhoretz Seth B. , Chambers Brent D.
Published: October 2015

This paper presents case studies of several leases containing horizontal wells in the Haynesville shale. The studies involve the successful use of completion diagnostics: fluid tracer, proppant tracer, and offset wells pressure monitoring. The diagnostics were used to evaluate fracture propagation, connectivity and communication (between stages and offset wells) and the impact on production performance for different completion methodologies.

Proppant tracers were used to identify cluster efficiency, fracture geometry and communication between stages. Fluid tracers result provided the extent of fracture connectivity between offset wells and show fracture propagation dependency on well spacing and sequence of fracturing. Furthermore, fluid tracers provided an estimate of lower bound on the fracture connectivity, as well as a qualitative measure of stage contribution based on the load fluid recovery period during the initial production phase. Depletion and treatment volume were found to play a key role in fracture propagation and tracer migration. The instantaneous pressure response in monitoring wells during the fracturing operations of adjacent wells was determined to be related to well spacing and the fracture treatment volume. Fracture propagation was found to positively impact the production performance of the depleted wells, thereby changing their original production decline.
Achieving Top of Cement; An Engineered Solution for Loss Zone Wells in the Bakken
Authors: Blake B. , Bowditch R. , Simacheva N. , Hudson M. , Crane D. , Shea C.
Published: October 2015

Primary cementing across the Williston basin Mission Canyon formation, a depleted zone with a low fracture gradient, can require alternative cementing techniques to achieve reduced equivalent circulating density (ECD) to minimize losses during cement placement. Achieving top of cement in this zone is challenging, and has historically required some form of remedial cementing. Some solutions have been foamed and two-stage cementing techniques; however, these techniques can be operationally complex.

The solution used is a lightweight, high-performance cement slurry. This solution uses an engineered, high-crush-rated hollow sphere particle as a cement extender, thus providing the slurry with reduced density and increased solid volume fraction upon comparison to conventional slurries. This slurry is used in combination with a fiber-based loss circulation material (LCM.) The combination of the increased solids content of the cement and the fiber LCM improves the plugging efficiency across the loss circulation zone. This cementing package allows for cement to be effectively placed across the Mission Canyon loss circulation zone with single-stage cement techniques.

Both case study wells sustained losses in the Mission Canyon at approximately 9,500 ft, with target true vertical depths (TVDs) approximately 10,800 ft. The average mud weight used in these wells was 10 ppg, and an aggressive LCM package was used prior to drilling into the Mission Canyon formation. Casing running rate was modified in order to reduce risk of inducing losses. Using the previously discussed design, a low-density, high-performance lead slurry was employed to cover these loss zones. A significant increase in solids content was achieved by extending this slurry with a manufactured, hollow sphere particle. This system gave an overall reduction in ECDs when compared to conventional slurries across the zone of interest. This lightweight, high-performance system was used with a fiber-based LCM package to maintain good circulation throughout cement placement. Critical job parameters were recorded throughout cementing and compared to design ones to support the observation of consistent returns to surface throughout placement. Ultrasonic cement evaluation was used to confirm top of cement post placement.

The novel solution, supported by two case studies, shows the successful use of a lightweight, high -performance cement system, along with fiber-based LCM. This cementing package was used to successfully achieve required top of cement during primary cementing across depleted or naturally fractured zones in the Williston basin during a single-stage cement placement.
The Full Montney - A Critical Review of Well Performance by Production Analysis of Over 2,000 Montney Multi-Stage Fractured Horizontal Gas Wells
Authors: Reynolds Murray , Bachman Robert , Buendia Juliana , Peters Wade
Published: October 2015

In today's low price environment, maximizing productivity and hydrocarbon recovery while reducing cost has become more critical than ever. In many resource plays, factory style completion campaigns using high rate / volume fracture treatments have become the accepted norm. However, is that really the optimum design to maximize productivity and net present value (NPV) of the asset?

This paper will present a new style of statistical analysis of the well performance of approximately 2,000 Montney / Doig horizontal gas wells completed since 2010. This analysis will review the important parameters to determine the effectiveness of the completion designs, such as:Fracture fluid systems;Open hole or cased hole multi-stage systems;Number of fracture stages / fracture spacing;Size of fractures, proppant tonnage per well;Cost.

The analysis was performed based upon normalized parameters including: Cumulative production at 3 and 12 months;Cumulative production: per proppant tonnage; completed well length; number of fracture stages; and completion cost.

The study will cover an overall review of the entire Montney / Doig gas fairway, as well as focus on an individual ‘high activity’ area of the Montney. This area includes some operator specific well performance comparisons.

This paper will outline the importance of applying advanced well performance analysis techniques to determine the efficiencies of specific completion and fracture designs. This illustrates the importance of looking back in order to optimize future completions. This paper reinforces the need to move completion designs from the current ‘operational effectiveness’ mode of fracture designs, to a ‘fracture effectiveness’ mode provided by optimizing designs to achieve higher recoveries and improved economics.
Integrated Reservoir Modeling and Optimization Study of Multi-Fractured Horizontal Well in the Swan Hills Formation: A Case Study of Acid Fracturing
Authors: Islam Arshad , Ziarani Ali S. , Glover Ken , Schneider Brian
Published: October 2015

With the advancement of drilling and fracturing technology in recent years, multi-stage fractured horizontal wells have become a norm in the development of unconventional oil and gas reservoirs in North America. This has created a renewed interest in major formations of the Western Canadian Sedimentary Basin. Due to higher completion cost, it is crucial to find an optimal fracture size and spacing as well as wellbore spacing for these horizontal wells. Acid Fracturing is a stimulation process in which acid is used to enhance the conductivity of a hydraulic fracture through differential etching of the fracture face. The effectiveness of acid fracturing depends on retaining fracture conductivity under closure stress after treatment. Fracture face roughness created by the acid etching and mechanical properties of rock after acid treatment are two important factors that play a vital role in retaining conductivity after fracture closure. Acid fracturing treatments of carbonate reservoirs have yielded an increase in production in many areas of the world. The Swan Hills Formation (a member of Beaverhill Lake group) in Alberta, Canada, a carbonate oil play, is the focus of this paper.

A dual porosity model was employed to integrate core, rock mechanics, PVT, stimulation, and production data. Acid treatment data was used to estimate the fracture geometry and conductivity which was then incorporated into a three dimensional reservoir simulation model. A multi-layer, single-wellbore reservoir model of horizontal heterogeneities across the study area was built based on core calibrated formation and geomechanical log data. The model input parameters were further fine-tuned using production history matching.

The calibrated reservoir parameters, based on a history matched model, were used for initial fluid in-place estimation, production forecasting and to investigate the fracture and wellbore interference. Interference analysis was performed based on reservoir pressure depletion and decline in cumulative production. A sensitivity study of fracture density, wellbore spacing, and lateral length of wellbore was carried out and their effects on oil and gas production are discussed. Recommendations on optimal fracture and wellbore spacing for the Swan Hills Formation are also provided.
Production Performance in the In-Fill Development of Unconventional Resources
Authors: Cherian Bilu V. , McCleary Matthew , Fluckiger Samuel , Nieswiadomy Nathan , Bundy Brent , Edwards Sarah , Rifia Rafif , Kublik Kristina , Narasimhan Santhosh , Gray James , Olaoye Olubiyi , Shaikh Hamza
Published: October 2015

Until 2015, North America’s unconventional resource market was known to be home to the largest oil shale deposits of economic value. Although the recent commodity price fluctuations have exposed the role of geo-politics, world economies and commodity trading on the life cycle of assets, few field development studies have consider the impact of commodity cycles on the development of in-fill wells. Papers have been presented to demonstrate the impact of vertical fracture connectivity and fracture asymmetry on in-fill well performance (due to delayed in-fill drilling), but little has been done on validation and coupling the impact of depletion, due to production, and hydraulic fracturing (due to in-fill efficiency fracture operations). This paper presents results from the analysis of in-fill drilling on well performance. Production data, fracture treatment data, completion and production timing are analyzed using pressure/production history matching techniques and compared with results predicted by data driven models (developed to match well performance) with the aim of proposing in-fill development strategies. Analysis of the field production data indicates that timing of in-fill wells (following the parent well) can influence the in-fill production depending on the level of depletion (cumulative fluid produced) and the size/type of fracture treatments pumped. Analysis of raw production data, modeling results from multi-domain model based coupled simulations and high resolution monitoring data also indicates that the order of the in-fill operations (East-West, Zipper, etc.) also has a significant impact on performance. This paper presents a simplistic approach to understand the impact of the quest for operational efficiencies and economic cycles on development strategies.
A Material Balance Equation for Stress-Sensitive Shale Gas Reservoirs Considering the Contribution of Free, Adsorbed and Dissolved Gas
Authors: Orozco Daniel , Aguilera Roberto
Published: October 2015

Unconventional shale gas reservoirs around the world have been proven to store gigantic volumes of natural gas. It has been demonstrated with both laboratory and mathematical work that these reservoirs can be represented by a quintuple porosity formulation plus an additional storage mechanism provided by dissolved gas in kerogen. All these storage mechanisms must be considered for estimation of original gas in place (OGIP). Otherwise pessimistic values of OGIP and recoveries will be obtained by ignoring any of these mechanisms. This paper presents a new easy-to-use Material Balance Equation (MBE) for shale gas reservoirs that considers the contribution of free, adsorbed and dissolved gas and their effects on cumulative gas production. Furthermore the proposed MBE takes into account the stress-dependency of permeability and porosity as the reservoir is depleted.

Aguilera (2008) formulated a MBE to account for the effect of fracture compressibility on OGIP determination in stress-sensitive naturally fractured reservoirs. Cabrapan et al. (2014) extended the method by incorporating adsorption in shale gas reservoirs. The authors used the Langmuir Adsorption theory for quantifying the adsorbed gas volume as a function of average reservoir pressure. In this paper, the method is further extended to include the effect of production by diffusion of dissolved gas from kerogen. The volume of dissolved gas depends on the total fractional volume of kerogen in shale and the methane concentration in the kerogen body, which is in turn a function of pressure and temperature, as proposed by Swami et al. (2013).

Results are presented as crossplots of P/Z (pressure/gas deviation factor) vs. Gp (cumulative gas production), Gp vs. time and gas rate vs. time. The plots allow detecting four stages of production in a shale gas reservoir: 1) production of free gas from fractures and organic porosity, 2) production of free gas from the inorganic matrix when fractures start closing, 3) production by desorption from the organic material and 4) production by diffusion of dissolved gas. The same trends have been observed in Devonian Shales of the Appalachian Basin where long production histories are available. It is concluded that dissolved gas is not only an additional storage mechanism but it also provides an important pressure and production contribution in shale reservoirs.

The new consideration introduced in the MBE proposed in this paper is of importance because although diffusion from kerogen in shale gas reservoirs is by nature a slow process, it provides long term production rates with relatively small declines. To the best of our knowledge, an analytical MBE that includes simultaneously stress-dependent porosity and permeability, free gas, adsorbed gas and dissolved gas has not been published previously in the literature.
Creating More Representative Type Wells
Authors: Freeborn Randy , Russell Boyd
Published: October 2015

This paper presents original research on how to improve the predictive ability of type wells used in evaluating unconventional resource drilling programs by extending traditional Monte Carlo calculations. The paper addresses three critical questions engineers must answer before constructing a type well: which well to use in the construction, the relative importance (weighting) appropriate for each well, and how to adapt the results to reflect certainty (e.g. P10, P50 or P90).

The proposed method involves determining the aggregated distribution of estimated ultimate recovery (EUR) for the specified number of wells by running a statistically significant number of Monte Carlo trials. From this distribution, one can determine mean EURs for the desired type well certainties, such as P50 or P90. Additional Monte Carlo trials yielding the desired mean EUR will help determine which wells to average. Monte Carlo sampling results in several hundred trials that match the desired EURs. The relative frequency of well selection from these trials defines the weighting factor and thus the relative importance of each well. Type wells result from a weighted averaging of history and production from the selected wells.

Engineers can use this new methodology to prepare production profile forecasts for the evaluation of multi-well unconventional resource drilling programs. They can also gain an understanding of the impact aggregation will have on their evaluation work.

Our research concludes that current type well construction practices may not be appropriate for evaluating future drilling because the production profiles for the wells used to build the type well may differ from the production profiles of the planned wells. This paper presents a new method to obtain more representative type wells. The method proves accurate for any ranking criterion (EUR, net present value, payout time) as long as one can identify the ranking parameter for each well.

This paper contributes to the technical knowledge base by:

identifying deficiencies in current type well methodology and proposing methodology to remove those deficiencies, proposing a method to meet selected certainty criteria and aggregate properly using Monte Carlo simulation, and introducing the concept that type wells do not need to be based on EURs, and in fact may be more valuable if they are based on more relevant criteria.
Integrated Method to Screen Tight Oil Reservoirs for CO2 Flooding
Authors: Zhang K. , Qin T. , Wu K. , Jing G. , Han J. , Hong A. , Zhang J. , Chen S. , Chen Z.
Published: October 2015

As a result of poor fluid delivery in tight oil reservoirs, oil production drops rapidly at early stages of depletion development. While water flooding only boosts production to a limited extent, CO2 miscible flooding seems a promising technique in improving tight oil recovery. Generally, CO2 flooding is performed only after water flooding gives better results than natural depletion. Since cumulative CO2 injection versus oil production goes up as formation permeability goes down, it is crucial to select suitable reservoir candidates to conduct CO2 flooding to be economically successful. There are several methods of ranking candidate reservoirs for the CO2 enahnced oil recovery (EOR) process based on criteria on reservoir parameters. Nevertheless, few of them take account of an oil recovery increment and risk analysis. In this paper, an integrated method for CO2 flooding reservoir screening criteria is presented, considering asphaltene precipitation and an oil recovery factor increment. This method is based on the least squares method, reservoir simulation, and fuzzy analytical hierarchy process, associated with equation of state (EOS) compositional calculations and compositional modelling. It is applicable in high diversity and can be used as guidance to screen tight oil reservoirs for CO2 flooding.
Estimation of Propped Volume Permeability Using Strain from Geomechanical Modeling of Interacting Hydraulic and Natural Fractures - Application to the Eagle Ford
Authors: Ouenes A. , Bachir A. , Paryani M. , Smaoui R.
Published: October 2015

A new workflow that uses the strain derived from geomechanical modeling of hydraulic fractures interacting with natural fractures is applied to an Eagle Ford well. The derived strain map is used to estimate the asymmetric half lengths that are input in any frac design software able to incorporate this new information. The simplistic symmetric and bi-wing design is revised by adjusting the leakoff coefficient, injection rate, and proppant concentration resulting in asymmetric half lengths that do not exceed the lengths of those provided by the strain map. Once the half lengths and orientation from the frac design match those provided by geomechanical simulation, the propped length and other key results provided by the frac design software may be used to optimize the well's completion. This process could be used iteratively to optimize desired metrics and could also be used to improve reservoir simulation.

The derived strain map may be propagated in the stimulated geomechanical layer to form a strain volume which may in turn be used to estimate the stimulated permeability. In this paper, we used a radial function to relate the stimulated permeability to the strain within the maximum half lengths provided by the strain map. Two calibration constants are needed in the radial functions and could be estimated by history matching or pressure transient analysis. An adaptive Local Grid Refinement (LGR) and variable stimulated permeability provide a realistic representation of the stimulated reservoir volume (SRV). After history matching, the resulting pressure distribution allows an accurate selection of refrac or new well candidates, for optimizing well spacing, and for estimating an accurate EUR.
Optimum Nanosilica Concentration in Synthetic Based Mud (SBM) for High Temperature High Pressure Well
Authors: Wahid Norazwan , Yusof Muhammad Aslam , Hanafi Nor Hazimastura
Published: October 2015

Synthetic based mud (SBM), a non-Newtonian fluid is proven to be the optimum mud for almost all drilling operations, for example in high temperature high pressure (HTHP) well, deepwater, unconventional and long extended reach directional (ERD) well. However, at certain conditions, the good performance of SBM will degrade, particularly due to effect of chemical instability under high temperature. In the light of aforesaid concern, the study on nano particles as a smart-fluid in drilling operations has been gaining attention worldwide. Therefore, this study intends to improve the performance of SBM with silicon dioxide nanopowder (nano-silica) at different concentration. The involving parameters in this study include the manipulation of nano particles concentration per amount of a commercial fluid loss control between 20 to 100 %, and performance at different temperature (275°F and 350°F). The enhanced formulation has given significant benefits by reducing the filtration up to 41.67% and act as the rheology modifier high temperature condition. In summary, the optimum amount of nano-silica has been identified at 40% of total fluid loss control weight to avoid further rheological and filtration degradation.
Hydraulic Fracturing in HPHT Deep Naturally Fractured Reservoir in China
Authors: Li Yongping , Xu Jianhua , Yan Fei , Zeng Siyun , Cheng Xingsheng , Zhang Fuxiang
Published: October 2015

The KQ Foreland Thrust is a typical HP/HT deep gas reservoir in China. The production formation is often buried below 6000m, where the reservoir pore pressure is often over 110MPa and the temperature is over 150 °C. Moreover, the natural fractures richly distribute in the formation. All these factors make the hydraulic fracturing in the KQ challenging, though the fracturing is necessary because the well initial production is often lower than the economic limit production. In previous, even the 20,000psi fracturing equipment was used in the field, the wells can't be totally hydraulic fractured because of the high surface treatment pressure and the limited pumping rate.

The high-density fracturing fluid is the key for HP/HT deep well fracturing, but the fluid weighted with bromide or the VES weighted with CaCl2 are both too expensive to use in the field. So a new fracturing fluid system weighted with nitrate is developed to lower the treatment pressure. The new delayed cross-linked fluid system is high temperature-stability and shearing resistance, and the density can reach 1.35 g/cm3. More important, the cost of new fluid is only 1/5 of the fluid weighted with bromide. Other measures were adopted to ensure the treatment safety and success, such as larger ID pumping tubing, 20,000 psi fracturing equipment and Christmas tree, proppant slug, et al.

Nine layers in six wells were successfully fractured with integrated measures. And the stimulated deepest well is 6988m, and the highest treatment pressure is 136MPa. The well production after fracturing increased by 3 times comparing with the initial production. This makes the well can be economically developed.

These series of technology will provide reference for the similar HP/HT reservoir fracturing to significantly increase the well production.
Special Considerations for Deepwater Well Temperature Prediction
Authors: Chen Zhongming , Xie Liangjun
Published: October 2015

Accurate wellbore temperature prediction is essential in deepwater drilling and completion operations. The wellbore temperature profile is the most dominant factor to consider when the cement slurry properties are designed. These properties are critical to ensure the success of cement placement. Many wellbore temperature simulators described in the literature use a finite difference approach in transient temperature profile modeling. However, for deepwater drilling and completion, the process is more complex. Seawater currents and natural convection cannot be ignored in heat-transfer modeling, especially for subsea pipelines and risers. Also, there are few published results of thermal property correlations for non-Newtonian, high-viscosity cement slurry. Special treatments accounting for transient heat transfer for those cases are necessary.

Mud and cement slurry are typically pumped at lower flow rates for cementing operations. At these rates, apparent viscosity may be used in heat transfer coefficient calculations. However, rheology properties for non-Newtonian fluids are changed abruptly for different models, and so are simulation results. For high viscosity fluids, such as cement slurry, there is a general need for experimentally derived heat transfer correlations.

A novel heat transfer model has been introduced for deepwater cementing. Special considerations for non-Newtonian fluids are included based on theoretical analysis, real field data correlations, and transient heat transfer of deepwater subsea pipelines and risers.

The predictions of the wellbore temperature profiles from this model are validated through measured wellbore temperature profiles, both in offshore and onshore cases. The model has been successfully applied in deepwater circulating, cementing, and hydraulic fracturing. Cases will be presented in this paper.
Production Prediction Based on the Heterogeneity Analysis of the Tight Carbonate Reservoir in the Sichuan Basin, China
Authors: Xie B. , Wang Y. , Zhou X. , Zhao Z. A. , Zhou X. , Zhao X. R. , Li K. X. , Yu D. G. , Xie T.
Published: October 2015

Cambrian and Sinian tight carbonate reservoirs have become a breakthrough in natural gas exploration in China's Sichuan basin. The officially certified geological reserves proved that Moxi-Gaoshiti block is a giant gas field. However, carbonate rocks are diverse and their pore spaces are complex. The storage spaces in carbonate rocks can be divided into matrix pores, fractures, and dissolution pores. The strong heterogeneity in petrophysical properties brings lots of troubles in finding the sweet spot, and it is necessary to incorporate logging methods that provide insight into the pore geometry.

This paper shows a method which incorporates Nuclear magnetic resonance (NMR), borehole images, and induced gamma spectroscopy. NMR is successfully utilized to characterize the pore geometry using a system built upon mercury injection capillary pressure (MICP) measurements and borehole image interpretation. The pores are divided into micropores, mesopores, and macropores. It shows a great advantage in production prediction because the macropores contribute to high initial production rates when they are well connected. The carbonate rocks are then classified into different types based on the pore geometry analysis of NMR and borehole image interpretation, which can be the guide for the further exploration.

Case studies are presented from carbonate reservoirs in the Sichuan basin. A robust and comprehensive petrophysical description of lithology, porosity, pore geometry, permeability, rock types, and fluid saturations is presented. A new understanding of carbonate reservoir heterogeneity is established. The synthetic curve that incorporates several petrophysical properties turns out to be a good prediction of production. Our interpretation methodology was validated well with core data.

This paper discusses a novel combination of open-hole logging tools for the heterogeneity analysis of tight carbonate reservoir in Sichuan basin, and it provides the geologists a handy technique to identify the best pay zone. The workflow can also be applied to other tight carbonate plays in China.
Well Control Simulation Model of Oil-Based Muds for HPHT Wells
Authors: An J. , Lee K. , Choe J.
Published: October 2015

A kick is defined as an unscheduled flow of formation fluids into a wellbore. Kick control is crucial for safe drilling in high pressure high temperature (HPHT) wells. During drilling with oil-based mud (OBM) in these conditions, it is difficult to detect and control a kick because of high gas solubility and mud density change with pressure (P) and temperature (T). The main objective of this paper is to simulate behavior of kicks in HPHT conditions in offshore wells with OBM.

To simulate kick behavior more accurately, it is necessary to consider mud density change with P and T. We select Standing-Katz correlation for base-oil density among three typical methods by comparing them with experimental data available. With the correlation, we update OBM density by use of Hoberock et al.'s compositional model in HPHT conditions. In this paper, by updating OBM density in Choe and Juvkam-Wold's modified two-phase well-control, kick behaviors are analyzed more realistically.

We analyze several cases in 20,000 and 30,000 ft offshore wells with OBM. Under the condition of simulations, mud density decreases as well depth increases because temperature is more dominant than pressure. Pit volume does not always increase as the kick rises to surface because of combined effect of gas solubility, P, and T on kick volume. If we consider the density change of OBM, more surface choke pressure is needed for constant bottomhole pressure with deeper vertical depth and HPHT condition. By applying the proposed method, we can have realistic modeling of wellbore pressure profile and kick behaviors.
Reviving the Mature Field of Bekapai: Integrated Work From Subsurface to Network Optimization
Authors: Muhazir Yan , Supriady Supriady , Kristianto Andy , Herwin Henricus
Published: October 2015

Bekapai is a mature oil and gas field located in the offshore Mahakam Delta, Indonesia. The hydrocarbons are accumulated in complex multilayered reservoirs. Ten platforms were constructed to accommodate the oil production coming from 74 wells drilled between 1974 and 1996. The production started in 1974 with peak production at ~60,000 BOPD in 1978, followed by a period of decline until it reached its lowest point at 1,000 BOPD in 2007.

A field re-development project, so-called Phase 1 initiated in 2008, had increased the production to 10,000 BOPD and 46 MMSCFD by the end of 2013. It consisted of 9 development wells. Following this successful project, a new 3D OBC seismic was acquired and further development plan, Phase 2, initiated, consisting of 10 development wells and gas production facility debottlenecking. Two wells have been drilled in 2014 and contribute in stabilizing the production of 2014 at 11,500 BOPD and 38 MMSCFD, the highest oil production of the past 25 years. The gas production decreases as a consequence to field production facility limitation. It was shelved due to priority of oil development. However, it is expected to increase to 100 MMSCFD in 2015 after the debottlenecking. In parallel, idle wells reactivation to access the shallow gas resources is also reviewed. Besides contributing to gas export, the gas is also used as artificial lift to revitalize the oil wells.

This paper demonstrates the main elements of the redevelopment: evolution of the geological model achieved through seismic and petrophysical data, production management in a complex production system and various optimizations at the production network in order to unlock the production capacity limit through debottlenecking projects and chemical injection at the export line. A continuous effort in even further redeveloping the field is also shown through Phase 2, the objective of which will be chasing the attic oil, blowing down the gas-cap, and double the gas production.
Achieving Zonal Isolation in Critical High-Temperature/High-Pressure Well Through Modeling and Use of Advanced Isolation Materials
Authors: Phyoe Thein , Bermea Jorge Vargas , Jain Bipin , Pallapothu Surya , Hassan Azza El
Published: October 2015

Achieving zonal isolation has always been a challenge when drilling and cementing gas-producing wells in a high-pressure/high-temperature (HP/HT) environment. A generally accepted definition of a HP/HT well is one in which the undisturbed bottomhole temperature at prospective reservoir depth or total depth is greater than 149°C [300°F] and either the maximum anticipated pore pressure of any porous formation to be drilled exceeds a hydrostatic pressure gradient of 97 Pa/m [0.8 psi/ft] or pressure control equipment with a rated working pressure in excess of 68.94 Mpa [10,000 psi] is required.

In the past, HP/HT wells were drilled and cemented in the UAE using conventional cementing design and techniques. Those wells had zonal isolation concerns for cemented production strings, proving that cementing was a critical factor in the HP/HT field. In addition, the wells must bear the stresses generated from injection pressure and temperature changes and frequent cycling of injection during well testing and production. Trapped gas and oil between production and intermediate casing (abnormal annular wellhead pressure) has been globally recognized as one of the serious challenges faced by the Industry from well security and isolation perspective. To tackle the potential safety and environmental hazards of abnormal annulus pressure, better cementing practices and solutions are introduced to improve well life cycle and minimize the frequency of workover operations.

This case describes the use of self-healing cement and flexible and expandable cement to prevent cement failure due to induced stresses and optimize the isolation and ultimately deliver on the objective set for critical exploration well by the Operator.
Developments of ASP/SP Flooding Formulations for Huabei Fault Block Reservoir
Authors: Zhu Youyi , Liu Xiaoxia , Fan Jian
Published: October 2015

Chemical combination flooding technology is one of the effective enhanced oil recovery (EOR) methods for high water cut sandstone reservoirs. Alkali-surfactant-polymer (ASP) flooding has been tested and applied in Daqing oilfield with significant EOR performance. When chemical combination flooding was extended to different reservoirs, one of key techniques is to develop chemical flooding formulations to fit the reservoir conditions. Huabei oilfield is a fault block reservoir with specific geological conditions and reservoir fluid properties other than Daqing oilfield. The average water cut was around 90% by water flooding. Chemical combination flooding is an alternative technique to enhance oil recovery.

ASP and alkali-free surfactant-polymer (SP) combination flooding formulations were investigated for Huabei reservoir conditions based on polymers and surfactants screening tests, surfactant adsorption losses experiments and oil displacement core flooding experiments. The research results lay the foundation of pilot tests for chemical combination flooding applying to the fault block reservoir.

Salt tolerant polymers including comb-shaped polymer KYPAM showed good viscosifying performances than conventional polymers when prepared with Huabei formation water. Petroleum sulfonates (PS) were selected for ASP and SP formulations. Ultralow interfacial tension between crude oil and ASP/SP solution prepared with formation water could be obtained at a widely range of surfactant concentrations from 0.05wt% to 0.3wt%. Adsorption losses of surfactants on core sand showed that the adsorption losses of surfactants were less than 1.00mg/g. Core flooding tests of chemical flooding proved that about 20%-23% incremental oil recovery over water flooding could be obtained by using ASP (1.0wt% Na2CO3 + 0.3wt% PS-1 + 1400mg/L KYPAM) or SP (0.3wt% PS-2 + 1200/1400mg/L KYPAM) flooding with an injection pore volume of chemical slug was 0.5PV.

The experimental results were considered to be technical feasibility and effectiveness of chemical flooding EOR methods for the fault block reservoir, which might present further understanding for chemical EOR field application in Huabei fault block reservoirs.
Case Study of 25 Years of Low Salinity Water Injection
Authors: Zeinijahromi A. , Ahmetgareev V. , Bedrikovetsky P.
Published: October 2015

During the last two decades, low salinity waterflooding as a part of more general varying water composition has become a promising EOR method. Nevertheless, the physics mechanisms of extra oil recovery by low salinity waterflood are not clearly understood. Yet, fines migration and consequent permeability reduction may occur as a result of reduction of water salinity that can divert the water flux. This effect must be accounted in low salinity waterflood modelling. Moreover, the flux diversion due to induced-fines migration could be utilized to improve the reservoir sweep.

In the current study the Tempest software is applied to build a model and history match 25 years of low salinity water injection in Bastrykskoye field (Russia). The model is then used to compare recovery factor for two scenarios of low salinity water (LSW) injection and formation water (FW) injection.

The modeling results show an insignificant change in recovery factor between two scenarios of LSW and FW injection. This low incremental recovery is explained by the production of a significant amount of the reservoir water (FW) before the commencement of low salinity water injection.

A sensitivity study shows that the location of the injectors can highly affect the incremental recovery obtained by LSW injection. A 2-layer model with 5-spot pattern shows a significant incremental recovery (8%) during injection of LSW as compared to the injection of formation water (FW).
Storage of Natural Gas by Adsorption Process
Authors: Arora Anshul , Bachle Anukrati
Published: October 2015

The desire to use natural gas as an automotive fuel at reduced pressures for both safety and compression cost reasons, but without compromising the range of the vehicles, has led to the investigation of the possibility of enhancing onboard storage with the aid of adsorbents.

Natural gas ideally in an adsorbent material will have a density intermediate between that of the liquefied natural gas (LNG) and the compressed natural gas (CNG). Thus, adsorbed natural gas (ANG) will have a very high energy density without the need of low temperature (LNG) or the need of high pressure tanks (CNG). While in principle this is an ideal storage scheme for natural gas as an automotive fuel, one has to find or develop the proper adsorbent material.

ANG technology allows storing big amounts of natural gas at a relatively low pressure (40–60 bars) at room temperature in a relatively thin walled tank filled with adsorbent. This level of pressure allows refueling the tank using simple and cheap equipment or sometimes refueling directly from NG pipelines. At present, activated carbon appears with the greatest potential for storing natural gas at pressures not to exceed 500 psi. In addition, high performance carbons tend to have high densities. Consequently, the high density carbons will occupy a smaller volume in the storage vessel.

This paper reviews the storage technologies for natural gas. Technical comparison is made between storage systems for adsorbent, liquefied and compressed natural gas and cost estimates. We discuss carbon adsorbents, design of storage tanks, cost and safety.
Derivation of New Analytical Expressions for Calculation of Gas-Liquid Relative Permeabilities through Fractures-Part I: Incompressible Flow
Authors: Saboorian-Jooybari Hadi , Abeyat Ehsan
Published: October 2015

The problem of multiphase flow through underground geological fractured formations arises in various areas of geosciences such as geology, hydrology, petroleum, soil, and environmental engineering. Considering the fact that flow in fractured formations is fracture dominated, relative permeabilities through fractures must be well understood. The comprehensive literature review of this paper shows that few experimental, numerical, and analytical studies have been performed to describe two- and multiphase flow in fractures. Contrary to reservoir rocks, there is no standard experimental procedure for measurement of relative permeabilities through fractures. Furthermore, existing techniques are generally inconsistent, time consuming, expensive, complicated, and may fail due to technical difficulties encountered while performing the experiments. Thus, developing an analytical model for accurate prediction of relative permeabilities through fractures is of vital importance for treating one of significant uncertainties associated with characterization and simulation of fractured reservoirs.

Historically, the straight-line relative permeability model (X-curve) has been widely used in numerical simulation of fractured reservoirs. However, experimental measurements of gas-liquid relative permeabilities through fractures have revealed high degrees of phase interference which cannot be well represented by the X-model. In this work, idealized flow configurations of stratified and segregated flow are assumed in order to make the analytical derivation tractable without the need of using numerical techniques. Then, basic fluid flow equations are combined to develop simple analytical models for gas-liquid flow in each of the patterns. Combining the models with Darcy's law leads to closed-form analytical expressions for explicit calculation of gas and liquid relative permeabilities through fractures. The relationships simply state that the relative permeabilities depend on several parameters one of which being the saturation, whereas they were considered to be only functions of the saturation in the classic X-model. Afterwards, the formulas are further simplified by adopting a realistic assumption. Eventually, the validity of the derived relative permeability expressions is checked by comparing their predictions with available experimental data. The results show that the ability of the segregated model to accurately predict experimental data is considerably poorer than that of the stratified model. Therefore, the generalized relative permeability expressions proposed for the stratified pattern must be used to describe the dynamics of gas-liquid flow in fractures. It addition to robustness, other advantages of the newly presented formulas such as simplicity, cost effectiveness, and being explicit and analytic make their implementation in numerical simulators straightforward.