bluuebunny/crossref_metadata_2025 huggingface dataset:
The Price Is Right: What Makes an M&A Deal Go Round, and What You Can Do When Companies Combine
Authors: Frenette Craig , Munisteri Islin , Ighalo Samuel , Terrazas Rodrigo , Tambosso Alan , Dodson Jeffrey T. , Law Lucas K.
Published: October 2015

Forum

This year and the last have been significant for acquisitions in the energy sector. At the corporate level, we are seeing the Halliburton takeover of Baker Hughes, the Shell buyout of BG Group, and Repsol’s acquisition of Talisman. At the asset level, there was the Woodside-Apache liquefied natural gas project, Nigerian companies’ acquisition of western companies’ interests in the country, and various master limited partnership mergers in the US.

The TWA Forum team talked with some of the top minds in the energy mergers and acquisitions (M&A) arena about what is driving the market, and how to prepare yourself if you are employed on either side of a transaction. This article will provide an overview of what happens behind closed doors before a merger or an acquisition takes place.

What Gets the Ball Rolling?

What are the key drivers of M&A activity in the energy sector?

Alan Tambosso (AT): The key drivers are currently cash flow, cash flow, and cash flow! Assets that are currently making money are in demand. Previously, assets were traded on a reserves basis. Transactions were very often based on a proved plus probable reserves value at a specified discount rate, say 15%. However, the focus has changed now as the market demands a current cash flow.

The shift in M&A drivers from reserves to cash flow occurred in the early 1990s when junior companies would buy underdeveloped assets with lots of reserves and then put capital in to accelerate the cash flow of the asset. This in turn provided more capital to develop more reserves, which created growth. The market reacted by funding these companies, as markets will always allocate capital toward companies with high growth potential.

Recently, low commodity prices have highlighted the focus on cash flow. Assets must be producing positive cash flow or the company holding the assets will not be able to sustain itself. Other drivers of transactions are debt, including operational obligations, such as abandonment liabilities. Companies with high levels of debt are less likely to be able to acquire a company or asset. In addition, acquirers may not want to purchase a target with high debt load.
Estimating Effective Fracture Pore-Volume from Early Single-Phase Flowback Data and Relating It to Fracture Design Parameters
Authors: Fu Y. , Ezulike D. O. , Dehghanpour H. , Steven Jones R.
Published: October 2015

Flowback data analysis has been recently considered by the industry to quantify hydraulic fracture parameters such as, effective fracture pore-volume. Tools based on simulation and rate transient analysis have been applied for flowback analysis. However, too many unknown parameters, together with complex production mechanisms lead to uncertain and non-unique results. This paper illustrates how flowback data can be interpreted to estimate effective fracture pore-volume and its relationship to fracture design parameters.

This study starts by addressing some limitations of the previous flowback models. In particular, the effects of water expansion and fracture closure are included in the proposed model. The resulting linear relationship is applied to flowback data from eight tight oil and gas wells in Anadarko Basin to estimate effective fracture pore-volume. The estimated effective fracture pore-volumes are compared with fracture design parameters such as total injected volume of water, soaking time, gross perforated interval, and proppant concentration.

The results indicate that fracture closure is the main mechanism for single-phase water flowback. Therefore, effective fracture pore-volume largely depends on fracture compressibility. The results also show that soaking time, gross perforated index, and proppant concentration are among the key design parameters for an optimum fracturing treatment.
Characterization of Anisotropic Elastic Moduli and Stress for Unconventional Reservoirs Using Laboratory Static and Dynamic Geomechanical Data
Authors: Hamza Farrukh , Chen Cheng , Gu Ming , Quirein John , Martysevich Vladimir , Matzar Luis
Published: October 2015

In a vertically transverse isotropic (VTI) medium, accurate prediction of the vertical and horizontal Young's moduli (E) and Poisson's ratios (ν) is crucial to predicting minimum horizontal stress (σhmin) and hence selecting drilling mud, cement weights, and perforation locations. Fully characterizing geomechanical properties of VTI shale requires five independent stiffness coefficients: C33, C44, C66, C11, and C13. In a vertical well, C33 and C44 are directly calculated from the velocity of the vertically propagating P- and S- waves, while C66 is estimated from the Stoneley wave velocity. To obtain C11 and C13, an empirical model must be employed. This study integrates laboratory mechanical and sonic measurements to evaluate the ANNIE and modified-ANNIE models and extend the dynamic-to-static conversion equation.

Laboratory static and dynamic geomechanical methods were applied to multiple core materials extracted at different depths from a target shale play. The dynamic elastic moduli were measured using a laboratory sonic scanner; velocities were measured in different directions to obtain C33, C44, C11, C66, and C13. The dynamic data were then applied in the ANNIE and modified-ANNIE models for estimating the dynamic elastic moduli, including dynamic Young's modulus and Poisson's ratio. The static elastic moduli were measured using axial compression experiments; horizontal and vertical core plugs were tested to account for anisotropy.

Static and dynamic results illustrated horizontal Young's moduli were predominantly higher than vertical Young's moduli, which suggested a horizontal layered structure. Vertical Poisson's ratios can be greater or smaller than horizontal Poisson's ratios, which is consistent with the prediction of the modified-ANNIE model. Conversely, the ANNIE model always predicts ν(vert) ≥ ν(horz). Static and dynamic data illustrated the anisotropic σhmin was predominantly higher than the isotropic σhmin. This implied that using an isotropic model to predict laminated shale will underestimate σhmin. It was noticed that the static Young's modulus increased with decreasing porosity for the target interval. The elastic moduli measured from the dynamic method were consistently higher than those measured from the static method. The dynamic and static data were used to fit the widely-used dynamic-to-static conversion equations—the Canady and Morales equations. The Canady equation was extended to the "very hard" (greater than 70 GPa Young's modulus) regime, while the Morales equation was extended to the regime of porosity < 10%. Finally, σhmin predicted by different models was compared with the measurements, showing that modified-ANNIE improved the prediction by solving the stress underestimation issue of the ANNIE and isotropic models.
Geomechanics Modeling in CO2-EOR: Case Study
Authors: Jabbari H. , Ostadhassan M. , Rabeie M.
Published: October 2015

Horizontal drilling and hydraulic fracturing have enabled production from Bakken tight oil reseroirs. However, since the primary recovery is very low, it is important to use enhanced oil recovery methods to unlock part of the remaining oil in the reservoir. In this study, the CO2 injection as a huff-n-puff EOR process is studied. Numerical simulation was used for coupling the reservoir fluid flow with geomechanics to study the stress and deformation of reservoir rock in a CO2-EOR process. The simulation was performed through porosity and permeability relationships with pressure, temperature, and mean total stress for iterative coupling of stress and flow to account for the effect of geomechanics in CO2-EOR.
An Application of Diversion Technique in Un-Cemented Section of a Horizontal Well in the Williston Basin
Authors: Madsen M. , Carlson J. E. , Rondon J. R. , Valenca A. , Do T. , Stewart M. , Borchardt E. , Dupuis B.
Published: October 2015

A well which was drilled in the Pronghorn formation of the Williston Basin had significant trouble during the cementing process. While the lateral length was 11,103 feet, only the 9,296 feet of the lateral closest to the toe had adequate cement to provide the isolation needed for hydraulic fracture stimulation. An integrated solution with evaluation of well integrity and novel diversion material used over the remaining 1,807 feet of the lateral to generate multiple hydraulic fractures was proposed and results were confirmed with production log evaluation.

After using an ultrasonic imaging logging tool conveyed via tractor to determine the point at which the cement isolation became unreliable, the appropriate completion was designed. The first 33 stages of the stimulation were done using a standard plug and perf technique. The last 1,807 feet of the lateral were completed in two intervals with only one additional bridge plug. The two intervals were each stimulated with seven hydraulic fracturing stages and six diversion pills consisting of a proprietary blend of degradable materials. While more stages were pumped in the heel section, the same amount of proppant per foot of lateral was used as in the larger conventionally completed toe section.

The 14 stages pumped in the heel portion of the lateral showed that in both intervals, the instantaneous shut-in pressures at the end of each one of them increased by 2,300 psi and 340 psi respectively. This increase is consistent with fractures initiating at lower pressure intervals, and then being diverted to higher pressure, unstimulated areas. Well production was evaluated with a production log capable of identifying multiphase holdup along the lateral. This evaluation showed that 42% of the total oil production was coming from the 18% of the lateral which was stimulated using the degradable diversion material.

The application of this degradable diversion material in poorly cemented or un-cemented lateral sections in order to create a more uniform distribution of hydraulic fractures can significantly improve both completion efficiency and hydrocarbon production.
AOF Analysis of One Shale Gas Play
Authors: Pang Wei , Xin Cuiping , Du Juan , He Ying , Mao Jun
Published: October 2015

China is believed to own the world's largest shale gas reserve and is the third country to exploit shale gas breakthrough in the world. Fuling gas play in Sichuan basin is one typical shale gas reservoir in China gaining good production performance, and the absolute open flow capacity (AOF) of some wells reaches as high as 1.5 million cubic meters per day. However, we still haven't get good understanding of AOF to evaluate the producing potential and performance of hydraulic fracturing in Fuling shale gas play.

In order to quantify the influence of parameters on AOF, statistical analyses are conducted on fourteen parameters including formation porosity, total organic carbon (TOC), injected fluid volume, injected proppant volume, injected fluid volume per stage, injected proppant volume per stage, proppant concentration, fractured stages, and fractured clusters, horizontal lateral length, angle between horizontal lateral and minimum stress direction, cumulative production in the first three months, stimulated reservoir volume (SRV) and flowback recovery in the first three months.

Results show that six parameters including cumulative gas in first three months, angle between horizontal lateral and minimum stress direction, SRV, TOC, porosity and injected fluid volume show relative strong correlation with AOF with coefficient bigger than 0.50. The influence of the other nine parameters on AOF is very weak, and the coefficient between AOF and water flowback recovery in early days is even as small as 0.11.

AOF is negatively correlated to three parameters including proppant volume per stage, proppant concentration, and angle between horizontal lateral and minimum stress direction. The negative influence of proppant concentration on AOF may have been caused by ineffective fractures (networks), and a positive correlation can be expected if proppants are injected into "sweet points" that meet the geology and engineering requirements and improved stimulation techniques with better performance of fracture propagation control. The angle between horizontal lateral and minimum stress direction is suggested to be less than 20° in order to get bigger AOF. AOF is positively correlated to the other eleven parameters. High TOC, porosity, injected fluid volume are good indication of high AOF.
Practical Application of Type Curve Analysis to the Interpretation of Multi-Stage Fractured Horizontal Well Data
Authors: Mahmoud I. S. , Anderson D. M.
Published: October 2015

The primary objective of this paper is to demonstrate the practical value of type curve matching, as a complimentary technique to standard diagnostic plots, in the interpretation of production data from complex multi-stage horizontal wells.

The approach is based on the usage of Compound Linear Flow Type Curves (Liang et al, 2012). Our methodology involves identifying the transition from early to late (compound) linear flow that would typically be expected in a multi-stage fractured completion. The "shape" of this transition can be a good indicator of the geometry of the system- specifically degree of stimulation efficiency along the lateral, in relation to the effective fracture half-length. This approach has been applied to several producing wells in the Eagle Ford (nanodarcy reservoir) and Bakken (microdarcy reservoir).

As a result of using CLF type curves, we are able to estimate stimulation efficiency along the lateral, with reasonable confidence. The stimulation efficiency is defined as the effective stimulated horizontal well length divided by the actual horizontal well length. In addition, we are able to estimate stimulated reservoir width in a reasonably objective and consistent way. These results can be used to seed analytical models for subsequent history matching and forecasting. Diagnostic methods currently used for interpreting performance of multi-stage horizontals are based on identifying specific flow regimes using specialized plots (eg- square root time and flowing material balance). These methods are limited, in that they don't consider the transition periods, which in some cases can dominate the production history. Type curve matching is a good compliment to the standard diagnostic plots, providing an independent and objective method of characterizing the reservoir.

Historically, type curve matching has been proven as a valid technique for interpreting production data (Fetkovich, Blasingame, Agarwal et al). However, with the advent of complex multi-stage completions in tight fractured reservoirs, the existing conventional models are no longer useful. The recently introduced CLF type curves are more appropriate for unconventionals. This work represents the first detailed case study where type curve matching is applied to an unconventional oil and gas play.
Preparing for LNG: A Montney Gas Field Optimization Workflow
Authors: Holst Richard P.
Published: October 2015

The Montney formation of northern Alberta is a very low permeability reservoir with regions of liquid-rich gas production. The reservoir is typically developed using multi-stage fracture horizontal wells with multiple wells per pad. The produced gas ultimately flows into a gathering network that may have both high and low pressure systems. The primary objective of this paper is to present an efficient workflow for preparing and utilizing an integrated gas reservoir / network model of a Montney field as a tool to determine the optimum facilities plan for the field. Pipeline infrastructure planning is needed to accommodate the large amount of drilling that will ultimately support future LNG demands. Optimizing the development is critical, especially during times of low commodity prices.

This paper presents a simplified tight gas reservoir modelling workflow, which has proven to be successful in the Montney and other fields. The workflow integrates available technical work on a field into one simplified full-field development planning tool. Basically, for each current and future well, a simple gridded numerical reservoir model is developed that matches the short term flush production and the long term type curve predictions. The wells are then attached to a gathering system model, thus creating a tool for optimization and planning. Type curves alone are not adequate for short term planning because they do not react to changes at the surface.

The implemented workflow has proven to be effective for optimizing development such as the sizing and timing of compression and the scheduling of infill activations. It has also been useful for quantifying back-out of existing production upon infill drilling and ensuring that facilities such as pipelines and compressors are properly sized. The timing and impact of switching rapidly declining wells from high pressure to low pressures systems was also considered when optimizing the system.

The workflow has allowed for full-field shale gas models to be developed with reasonable model construction times and manageable model running times. The workflow could be applied to other similar fields or formations, such as the Horn River in north-eastern British Columbia or the Duvernay in central Alberta.
New Downhole Data Clarifies Coiled Tubing Behavior in Horizontal Wells
Authors: Blanchette C. , Getzlaf D.
Published: October 2015

A downhole force recorder is presented that uses onboard strain gauges along with temperature and pressure sensors to measure and record the forces experienced by a downhole assembly at the end of a coiled-tubing string. Field trials are discussed in order to demonstrate the benefits of the downhole force recorder during a typical fracturing operation.

The downhole recorder measures force, pressure and temperature. The recorder utilizes a system of onboard strain gauges, pressure transducers and temperature sensors in order to determine the force applied to the gauge. The pressure and temperature sensors are used to filter the pressure and temperature effects out of the force measurement, as well as to record standard treatment data. All data is stored onboard the tool and recovered postjob at surface. The data obtained is then downloaded and compared to a static tubing forces model to validate the results captured in dynamic well conditions.

Field trials were completed over the course of two and a half years, with design improvements to refine data capture capabilities. Initial downhole recorder trials showed that pressure had a large effect on the force measurement. This was offset by calculating the piston areas of the gauge and writing algorithms to remove the pressure-induced force. The latest field trials verify the data collected by the downhole force recorder represents actual force measurements in dynamic well conditions and in varied reservoir types. This data provides more precise downhole information than the general data found in static models. The downhole force recorder has been successfully used in over a hundred deployments.

Four significant uses for accurate downhole force measurments have been identified: validating third-party force models and better calibrating downhole force recorders used under similar fracturing operationscompleting an informed rootcause analysis when troubleshooting job performance issuesproviding operators with more information on force, pressure, and temperature to support job planning for typical completionsinfluencing future product development driven by force and depth requirements captured under specific well conditions.

Novel/Additive Information: The novelty of the new downhole force recorder is its ability to accurately determine the force experienced by a bottomholeassembly (BHA) at the end of the string when used during typical fracturing operations. Capturing this new downhole force information will transform how operators approach job planning and troubleshooting on well completions, and how tool designers approach future product development for fracturing operations.
Performance Analysis of the Canadian Deep Basin Unconventional Wells
Authors: Pour Faleh Novin , Sayed Nada El , Eddy John
Published: October 2015

The Canadian Deep Basin is comprised of a stack of tight sand reservoirs including channels and sheet sands with reservoir fluids that regionally vary from dry gas, gas-condensate to volatile oil. This Basin has been ranked one of the most commercially developable unconventional systems and has attracted many operators. Thousands of wells have been drilled in the area that tested a variety of well designs and fracking technologies over time. The initial development started with hydraulically fractured vertical wells that targeted all sand intervals in the vertical section, but the recent technology advancement enabled operators to focus more on horizontal drilling with multiple fractures along the wellbore. Assessment of the commercial development of these wells and the future of the assets depends on the proper evaluation of the performance of the existing wells and reliable production forecasting and estimation., Rate Transient Analysis (RTA) and multi-segment Decline Curve Analysis (DCA) techniques have been identified as the quickest and best fit for purpose techniques. Upon data availability, rates and pressures, RTA models provide better quality analysis over DCA yet DCA is required for many analog wells in the public domain. In our proposed methodology calibration of DCA parameters with the results of RTA is included for enhancing DCA quality.

This paper discusses the generalized performance characteristics of the Deep Basin wells under study. Key decline parameters such as the decline exponent and time to boundary dominated flow are discussed and compared between wells. Differences in well design such as well length and proppant tonnage impact the well performance and are covered in this paper with a suggested methodology for normalizing the performance data. Finally, a key focus of this study is uncertainty and non-uniqueness associated with the results. This is particularly important in early time when the wells are still in the transient period. Methodologies with probabilistic techniques are presented to address the issue.
Acid Additives Effect on Production – A Beaverhill Lake Case Study
Authors: Maley Darren , O'Neil Bill , Ubana Lea , Mattucci Mike
Published: October 2015

Since the start of large volume acid fracturing treatments of horizontal wells in the Beaverhill Lake formation many variations of acid chemistry have been used. Often the changes to the chemical formulations are based on cost reduction and treatment optimization since the volume of acid used became considerably large. Though possibly changes based on cost optimization may have affected the overall economics of the well.

This study will evaluate 56 wells that were acid fractured in the Beaverhill Lake formation, specifically in the Swan Hills area with acid blends that consisted of four different antisludge surfactant packages. Initial interpretation indicates that the acid blends containing cationic surfactants yield significantly higher oil production than the acid blends that utilize anionic surfactants once other variables have been normalized. Acid blends containing anionic surfactants have classically been the preferred chemical formulation for oil wells in the Swan Hills are due to the interpretation of the results of simple laboratory testing and the perception that the chemistry is more cost effective.

In an attempt to correlate the change in chemistry to changes in well production, additional lab testing to support previously published work will be presented, including reaction rate testing, wettability studies using core samples, and a modified acid-oil compatibility test with a longer term fluid exposure at reservoir conditions.
Case Studies in Quantitative Flowback Analysis
Authors: Williams-Kovacs J. D. , Clarkson C. R. , Zanganeh B.
Published: October 2015

Recently, several authors have explored new methods for quantitatively analyzing multi-phase flowback data from multi-fractured horizontal wells (MFHW) to extract both fracture and reservoir parameters. These techniques provide much of the same information as long-term rate-transient analysis (RTA), although in a much shorter period of time. Flowback analysis is complicated by a rapidly changing fracture network and wellbore environment, multi-phase flow in the fractures (and possibly the reservoir), completion heterogeneity, as well as other effects which are often not present, or are ignored, when analyzing long-term (online) production data.

For quantitative flowback analysis, the current authors have previously presented data-driven, pseudo-analytical methods for estimating key fracture properties (i.e. conductivity and half-length) from high-frequency, short-duration production test data. Models have been developed for both oil and gas wells representing a variety of reservoir and operating conditions. In this work, the models and procedures are extended to apply to more challenging reservoir/completion scenarios and are used in the analysis of several case studies from Canada. Each of the case studies demonstrate either the potential value add of the developed techniques, or a unique extension to the basic analysis methods.

The case studies analyzed herein focus on light tight oil plays and consider layered reservoirs, multi-well flowback, and oil fracs in oil reservoirs. Further, the potential capital savings associated with conducting quantitative flowback analysis of early-time production test data is demonstrated. Each case study therefore presents a unique set of challenges that are often encountered in the real world. Numerical simulations are used to validate the sequence of flow-regimes depicted in the models.

The methods presented in this paper will serve to partially satisfy the demands of industry to develop new methods for characterizing hydraulic fractures and forecasting production, particularly early in the well life. Through the use of several unique case studies, the wide-spread applicability and versatility of the techniques is demonstrated.
Water-Free Fracturing: A Case History
Authors: Asadi M. , Scharmach W. , Jones T. , Sampayo A. , Chesney E. , Unruh D.
Published: October 2015

While hydraulic fracturing is primarily used to recover oil and gas from reservoirs, water-free fracturing may soon become the center stage to extract hydrocarbons in certain formations or situations. DryFrac™ waterless fracturing technology, as the name implies, does not use water to create the fracture. Instead, this process uses liquid CO2 to crack open the formation providing a highly conductive path for hydrocarbons to flow into the well. This technology can provide superior technical advantages over water-based hydraulic fracturing by eliminating the need for water, resulting in formations free from water damage and maintaining the intended proppant pack conductivity with no polymer residue. This paper presents in-depth information on a case history where liquid CO2 is used to fracture a formation. The presented data includes background, modeling, liquid CO2 implementation as a fracturing fluid, results and analyses.
Montney Unconventional Gas Play: Managing Choke Wear Using Flow Coefficient Diagnostics
Authors: Grant Lee
Published: October 2015

The objective of this project was to improve wellsite safety, optimize choke life, and reduce downtime in highly erosive Dawson Montney (British Columbia, Canada) gas wells through use of real-time flow coefficient (Cv) diagnostics. This was achieved by developing a methodology to trend well behaviour, characterize wear patterns and create Wear Reports based on user defined set-points.

A 2-phase flow coefficient equation was used to reduce error in higher liquid-gas-ratio wells and to improve universality. Percent Cv deviation (%Dev) is introduced and calculated in relation to the theoretical choke curves and acts as a key wear indicator. A custom Steady-State Slope-Fitting algorithm and workflow was developed to numerically characterize choke behavior. Using well specific slope durations based on flow behavior as well as elimination of statistical outliers, reliable slopes can be calculated. Logical statements comparing the slopes of key parameters to user adjustable setpoints identify wear patterns and create a shortlisted "Wear Report". These wells can be quickly validated using a custom Spotfire based visualization template.

A subset of the Dawson Montney Field (107 wells) was originally piloted to validate methodology. Two generalized wear signatures (for auto and manual choke control) were theorized and vetted using a combination of wear trends and failure analyses which showed high internal wear. By comparing slopes of flow rate, choke position, and %Dev to set-point values, wear signatures can be identified. Workflow was easily adapted to be effective with the Dawson Montney standard choke type as well as a new choke pilot. Many wells have exhibited wear signatures and have been correctly identified by the software, thus increasing safety between scheduled onsite choke condition checks. Early indicators have been communicated to field personnel and well specific plans have been made to replace chokes. In many cases, early detection has allowed pre-planning of onsite work to minimize well downtime (from 24–48 hours downtime to 4 hours or less) and maximize cash flow generation ($10–20k accelerated, using typical rates and netbacks). This program has now expanded to over 400 Montney wells and will be monitored by a continuously manned Operation Control Center.

Use of a slope fitting algorithm to numerically describe flow/wear behavior, creation of prelim wear set points/limits, and the wear signature identification logic is a novel approach to detecting and mitigating issues related to choke wear, which ultimately improves safety and reduces costs.
Seismic Methodologies Adapted For Use In Acoustic Logging
Authors: Biswas Partha , Ley Shreya B.
Published: October 2015

If we are to continue to use acoustic logging as a viable method for characterizing wellbore formation characteristics, such as natural fractures, then logging techniques developed for conventional reservoirs and vertical wells should be updated and adapted for use in today's unconventional and directional drilling applications. Unlike seismic processes, which have undergone research and changes to adapt to the more complex characterization needs of today's wells, acoustic logging techniques have stayed relatively stagnant. In order to stay relevant, acoustic logging processes must adapt for use in unconventionals as well. The following discussion focuses on four seismic techniques adapted for acoustic logging processes, the process for choosing these particular techniques to adapt, and the results achieved.

We have based new acoustic logging algorithms and routines on these four seismic techniques and adapted the research into proprietary software for processing raw, acoustic waveform data. First, we have adapted the use of compressional waves to map drops in energy across natural fractures which allows industry to move away from many of the limitations imposed by more widely used techniques. Second, as part of the workflow presented in the compressional fracture identification methodology, we have adapted stacking to improve results and amplify anomalies. Third, in order to provide a broad available toolsets and usable data, we have incorporated advanced filtering routines based on predictive deconvolution, which can be used to process acoustic data from alternative tools or to enhance data collected using measurement-while-drilling or logging-while-drilling tools. Fourth and last, applicable to both shear and compressional waveform processing, we have chosen to move away from Alford-based azimuth computations, or at least correct for assumptions in Alford-based azimuth computations that are not relevant in unconventionals, so that borehole deviation does not adversely affect the processing.

The use of compressional waves to map natural fracture patterns has found great success in both vertical and lateral wells and has been used in the field in the Permian, Eagle Ford, the Bakken, and in various international fields. Comparisons against image and core results demonstrate an 80-85% correlation rate. The following discussion will go over two case studies, the evaluation method used to study the correlation, briefly discuss the workflow used, and also provide an example of how the advanced filtering produces much cleaner waveforms for processing than relying solely on frequency filtered waveforms.

These new processes allow acoustic processing to enter the modern age of exploration and create a new, more direct process for finding the fracture density in the well bore. Furthermore, they may be incorporated in to new and old processing techniques, making the most of the modern tools available.
Low Resistivity Oil Sands: CO and PLT Logs Find By-passed Oil and Extend Life of Mature wells
Authors: Faizal Ardi W , Handoyo Tri , Panca Suci W , Pramudhita Bayu Adhi , Jafet Jafet , Mudayana Riko
Published: October 2015

This is a case history of how aggressive well surveillance can increase oil recovery and dramatically extend well life.

MSBK is a 20 MMSTB OOIP field in the Malacca Stait PSC, located on Padang Island, Riau Province, Sumatra (Figure-1). Oil has been drained from the Lower Sihapas G-3010 sand in two development wells: MSBK-1 for 22 years, and MSBK-2 for 13 years. Other sands were penetrated, but had low-resistivity or 2-3 ohm.m, which was similar to water sands and shale. Given this lack of resistivity contrast, these sands were not considered further.

By 2011, oil production had declined and was approaching the economic limit. Facing the prospect of abandoning the wells, the team looked at ways to extend well life. Although the resistivity logs were not promising, oil shows were noted in the G-1010 and G-1020 sands in MSBK-2, with other oil shows in the G-1010, G-1015 and upper G-3010 sands in MSBK-1.

This paper will elaborate the workflow used to find potential by-passed oil, covering wireline and mud logs, through-tubing perforation (TTP), surveillance logs and finally the workovers.

The team successfully found and developed the by-passed oil.

MSBK-2 had an oil gain of 150 Bopd, and the workover paid off in 12 days. MSBK-1 had oil gain 135 Bopd, and the workover paid off in 27 days.
Locating the Remaining Oil (LTRO) in a Mature Field in the Tertiary Baram Delta, Malaysia
Authors: Kittrell Charles , Sessarego Horacio , Tewari Raj Deo , Othman Tg Rasidi , Yeomans Hugh G. , Taslim Gunawan , Djohor Mohamed , Bahraie Ramin , Meyer Juergen , Jiang Long , Whitney Patricio , Enriquez Hugo A. , Kiome Patrick , Montero Alfonso R.
Published: October 2015

The Late Neogene Baram Delta province developed on an active margin located offshore Borneo in Malaysia. The field has been in production since 1982, and a total of 64 wells have been drilled from three (3) platforms. This paper discusses the process used to locate remaining oil for infill drilling. This involved a multidisciplinary effort including geology and geophysics, reservoir engineering, drilling / completion, and production technology.

The geologic and geophysical (G&G) assessment consisted of updating the static model and constructing mobile oil thickness and structural and bubble maps of all reservoirs. These maps were used in conjunction with original and current fluid contacts and helped to identify and locate remaining oil accumulations. The target portfolio was screened and ranked, and preliminary wellbore paths were built. Four (4) new wells and eight (8) sidetracks combining either shallow or deep targets were passed on to the reservoir engineering team for optimisation from simulation models and first-pass estimation of oil incremental reserves.

Reservoir simulation focuses on optimising target intervals as determined through G&G work and drilling design. Well constraints are set to be consistent with operating field production practices and facilities constraints. Completion intervals for the dual-string wells are optimized to minimise water cut and maximise oil rates. All simulation results are rigorously checked against offset well production and observed properties.

Once drilling targets are risk-assessed on the basis of structural, fluid contacts, and properties uncertainties, the final well trajectories are designed by the drilling team.

This study identified and ranked multiple undrained and appraisal areas. A full infill redevelopment consisting of more than 10 accelerated wells planned through the utilisation of existing facilities was presented and approved by PETRONAS Carigali Sdn. Bhd. (PCSB). The well and target portfolio is focused on three (3) main field development areas: Attic oil in shallow Pliocene reservoirsNew development areas in deeper Miocene levels on the southern blockUntapped deep Miocene reservoirs on the northeastern flank in crestal location

The first two (2) sidetracks and three (3) workovers were successfully completed in December 2012, and the current oil production is 40% higher than originally estimated. The successes to date have proved the effectiveness of the concepts that were applied to identify and develop the remaining oil, and the field became East Malaysia's top producer.
Electrical Submersible Pumping Systems vs. Long Stroke Pumping Units: A Case Study of Economical Comparison in a Low-Volume Well
Authors: Proaño Alejandro , Gomez Cesar , Molotkov Roman , Villacis Nelly , Sola Ana , Suarez Simon
Published: October 2015

Historically, the electric-submersible-pump (ESP) system has been the most cost-effective artificial-lift technology to draw down deep wells with flow rates of more than 200 STB/D. In lower-rate wells, other technologies such as rod pump systems have proven to be more cost effective. However, in recent years the long-stroke pumping unit has extended the rod-lift operating envelope to the point that rod lift now provides competitively effective pumping in wells traditionally using ESPs.

The case study within this paper focuses on a mature well located in a Petrobell's field in South America, Cachiyacu 1, in which a production decline rendered the existing ESP system oversized for the well conditions. The operator was seeking a more efficient lift solution before ESP failure due to down-thrust operation. A comparison of energy consumption, efficiencies, and operating expenses (OPEX) was used to evaluate the two artificial-lift options—a smaller ESP system or a long-stroke pumping unit.

This study compares the costs of power and workovers between an ESP and a long-stroke pumping unit. It shows that over a well-documented period of time, the long-stroke pumping unit reduces power consumption by providing greater operational efficiency than ESPs at similar depths and rates. The long-stoke pumping unit also reduces workover costs with less expensive downhole components.

This operator realized significant financial savings and reduced energy usage by choosing the long-stroke pumping unit. Although both the ESP system and the long-stroke pumping unit can deliver similar production rates, in this case, the long-stroke pumping unit was able to provide a higher production rate than the ESP. The LSPU also provided a more cost effective option in this application (CAPEX & OPEX).
A Parallel Framework for Reservoir Simulators on Distributed-memory Supercomputers
Authors: Liu Hui , Wang Kun , Chen Zhangxin , Jordan Kirk E. , Luo Jia , Deng Hui
Published: October 2015

This paper presents our work on developing a platform for high performance reservoir simulations, which is developed to support the implementation of various reservoir simulators on distributed-memory parallel systems. This platform employs MPI (Message Passing Interface) for communications and OpenMP for shared-memory computation. It provides structured grids due to its simplicity and cell-centered data for each grid cell. The platform has a distributed matrix and vector module and a map module. The map connects the grid and linear system modules. Commonly-used Krylov subspace linear solvers are implemented, including the restarted GMRES method and the BiCGSTAB method. It also has an interface to a parallel algebraic multigrid solver, BoomerAMG from HYPRE. Parallel general-purpose preconditioners and special preconditioners for reservoir simulations are also developed. The numerical experiments show that our platform has excellent scalability and it can simulate giant models with hundreds of millions of grid cells using thousands of CPU cores.
Next Generation Damage Resistant Liquid Coatingsa
Authors: Devadass Melvin , Yousif Aneece
Published: October 2015

The selection of a reliable pipeline coating is an integral part of repair and rehabilitation of aging pipelines. Liquid epoxies have been a preferred choice, specifically considering handling properties, application, compatability to cathodic protection (CP), corrosion control and soil stress. The next generation of field applied two part liquid epoxy coatings will need to offer application and performance properties beyond the specification requirements set forth by the industry. These liquid coatings are designed to protect steel from the harsh effects of corrosion both onshore aswell as in offshore environments. While high build epoxies are generally well regarded for adhesion, one challenge has been to match performance with higher coating flexibility.

This paper introduces the next generation two part liquid epoxy coating with superior flexibility, greater surface tolerance and improved functional properties to meet the demands of rugged terrains supported by laboratory and field data.

Industry specifications have not offered much guidelines on two part liquid epoxy coatings and not much advancement in technology has come to the industry. Abrasion Resistant Epoxy Coatings (AREC) are the next generation of field applied pipe line coatings. They provide a tough coating with outstanding mechanical properties like abrasion resistance, gouge resisastance and impact resistance while maintaining a high degree of flexibility. This next generation two part liquid epoxy coatings will provide similar flexibility properties as FBE, but with the ease of application that two part liquid epoxies offer.
Innovative Offshore Stimulation Campaign
Authors: Sukkar Luai , Arukhe James , Yateem Karam , Ajmi Saleh , Danish Syed Muhammed , Becerra Etan
Published: October 2015

This paper highlights the challenges and limitations encountered, and the respective solutions executed, during an acid stimulation campaign, conducted on multiple offshore power water injector (PWI) and oil producers (OP).

The field development concept for the field in includes a water drive mechanism, having unique placement of both onshore and offshore peripheral water injector wells. This field has a major concentration of extended reach hydrocarbon wells in the region.

Normally, post-drilling or post-workover operations, acid stimulation is foreseen to assure attainment of desirable well productivity or injectivity potentially that might be affected by drilling mud. For optimum treatment, each well requires uniform acid stimulation with significant volumes of chemically inhibited and diverted acid to achieve uniform zonal coverage, which are placed through Coiled Tubing (CT). Based on multiple laboratory tests conducted, an optimized treatment gradient (gal/ft) was fixed.

A rigless intervention technique was used, with a stimulation vessel handling the chemical additives, acid, diesel, and water logistics, on-the-fly treatment fluid mixing, and pumping, while a self-propelled barge handled the CT unit with nitrogen lift pumping capability and return handling system.

The successful combination of the CT intervention and stimulation vessel fluid handling system in this campaign resulted in improvement post-stimulation in terms of both injectivity and productivity. This paper includes general technique and volumes used to successfully stimulate wells.
The Properties Analysis for Reservoir of Sand and Mud Thin Alternations in San Jorge Basin
Authors: Hai Qu , Baoping Lu , Tingxue Jiang , Xinrun Lv , Guien Li , Xingchuan Li
Published: October 2015

The multi-layered stratigraphic formation is the main property in the San Jorge Basin. Because of thin interbeded sand-mudstone, these formation exhibit major inconsistencies and anomalous results in formation water salinity. In addition, the complex reservoir characteristics lead a great challenge to fracturing in that it is no easy to control fracture height. Thus it required the use of optimum hydraulic fracture to improve the hydrocarbon production.

Since January 2011, over 200 diagnostic fracture injection tests have been made into Argentina San Jorge basin reservoir layers. The objective of diagnostic fracture injection tests is to optimize hydraulic fracture technology and parameters in multi-sand and mud thin interstratifications by estimating pore pressure, permeability and closure stress in destination formation. The G-function, pressure match and pseudo-radial flow method were used to analyze pressure records. The pressure match method was used to analyze fracture shape created by the main fracture treatment. The ratios of fracture size were obtained in several work sections. This enhances the capability to design hydraulic fractures based on the reservoir conditions, with the optimum conductivity and fracture half-length to provide the required productivity over the life of the well. The sandscreen reasons were also depicted for sand and shale alternation.

The characteristics of production well were also studied. There is a big difference between perforation completion and fracture/perforation completion. Normally the wells with fracture have a relative good production. But the selection of potential layer is the biggest chanllege to improve production.

Application of this optimum process has resulted in improved well performance in the SJ basin well. Although the results presents are specific to the San Jorge Basin, the methodology and analytical techniques are valid in all basins.
Gaussian Process for Uncertainty Quantification of Reservoir Models
Authors: Hamdi Hamidreza , Hajizadeh Yasin , Sousa Mario Costa
Published: October 2015

Reservoir history matching is a computationally expensive process, which requires multiple simulation runs. Therefore, there is a constant quest for more efficient sampling algorithms that can provide an ensemble of equally-good history matched models with a diverse range of predictions using fewer simulations. We introduce a novel stochastic Gaussian Process (GP) for assisted history matching where realizations are considered to be Gaussian random variables. The GP benefits from a small initial population and selects the next best possible samples by maximizing the expected improvement (EI). The maximization of EI function is computationally cheap and is performed by the Differential Evolution (DE) algorithm. The algorithm is successfully applied to a structurally complex faulted reservoir with 12 unknown parameters, 8 production and 4 injection wells. We show that the GP algorithm with EI maximization can significantly reduce the number of required simulations for history matching. The ensemble is then used to estimate the posterior distributions by performing the Markov chain Monte Carlo (McMC) using a cross-validated GP model. The hybrid workflow presents an efficient and computationally-cheap mechanism for history matching and uncertainty quantification of complex reservoir models.