North America

Saturation evaluation based on resistivity methods have been widely accepted industry standard for the decades. Formation Evaluation in carbonates usually relatively straightforward due to simple lithology and resistivity-based methods works perfectly due to high formation water salinity. However, complexity and variation of carbonate texture and wettability makes estimating of saturation solely on resistivity methods challenging especially in case of the paucity of special core analysis (SCAL) data.

New developments in logging technology, especially in dielectric logging, is aiming to improve the log derived interpretation and reduce the uncertainties of the evaluation. Outputs of dielectric dispersion logs including computation of Archie's parameters (m=n), water-filled porosity enable clearly identified the hydrocarbon-bearing zones despite misleading oil saturation calculated using resistivity-dependent saturation approach in front of most porous reservoir. Water saturation computed with inverted from dielectric measurement Archie's parameters allows accurately identify the type of fluid (hydrocarbon or water) filling the free pore space and gain insight prior to the formation sampling and well test.

The objective of this work is to describe a comprehensive approach integrating dielectric measurement and other advanced sets of wireline logs for petrophysical characterization of carbonate reservoirs. This paper is intended to discuss in detail a case study from the Western Kazakhstan in which the integration of advanced petrophysical logs has enabled a robust reservoir and fluid characterization of carbonate reservoir and provided insights for formation testing results in advance.

The extensive logging suite to address all the key challenges included standard logging, dielectric dispersion, nuclear magnetic resonance, and formation microimager. The reservoir fluids and dynamic properties were characterized by a series of formation sampling. The integration of dielectric, nuclear magnetic resonance and formation microimager measurements has played a major role in characterizing formation heterogeneity and reveal pore structure type, a dielectric multi-frequency measurement is being utilized to measure the flushed zone oil saturation relatively independent of pore fluid salinity, rock texture, and composition.

The comparative analysis of well-logging and well-test results was carried out. Saturation types of 6 tested objects out of 6 obtained from well-test show perfect match with predicted reservoir saturation from petrophysical evaluation.

Field development strategies in unconventional shale reservoirs have increased in intensity over the last few decades. Completion design and well spacing have been key focus variables in the incremental design process. With this wide range of design and development strategies, assets across different basins might end up with wells from a variety of design generations. This could make type curve creation even more complicated as it does not account for impact of hydrocarbon drainage in an area by the older (parent) well on the newer (child) wells. The present paper tackles this issue by addressing type curve development by including date dependent spacing variables to account for the dynamism of field development strategies over the years.

The present paper analyzes the impact of well spacing on type curve development in an asset. Type curve generation is a critical component in evaluation and subsequent planning so de-risking this step is very valuable. A lot of the analysis done in recent years is by considering well spacing as a static variable. The present analysis looks at spacing as a dynamic variable instead to account for time-series based variations. The spacing in the estimation process is also a 3-D spacing algorithm which identifies multiple points along the lateral section of the wellbore for a true evaluation of pressure transient propagation.

The present analysis showed the impact of date dependent well spacing on type curve development. The underestimation of well spacing in well-developed acreages was brought to attention as spacing mean deviations of upto 0.7 Standard Deviation were found between current well speacing and date-dependent well spacing scenarios analyzed. These deviations led to the type curves having upto a 40% EUR differential between estimation processes, with PV10 differentials higher than 100% in some cases. While the degree of impact of time series well spacing varied across the assets evaluated, quantifying the risk in type curve development and subsequent EUR estimation were key conclusions from the analysis.

The present paper presents a novel approach in tackling type curve development for parent and child wells observed across different basins. The paper provides guidelines on creating highly accurate type curves and highlights errors that may arise due to high well density and inter-well interaction by conducting the analysis in the high well density Middle Bakken formation.

Drilling in the Appalachian basin in Pennsylvania has evolved since its inception. Operators have shifted their focus from mere wellbore delivery to delivering wells in the shortest amount of time to reduce risks and costs, as well as drive efficiency. This paper presents a case study in which offline cementing helped improve operation efficiency by reducing drilling times and provided significant cost savings.

Offline cementing is not a new concept. In Q4 2015, an operator drilling in the Eagle Ford shale began the movement of their program toward offline cementing of both the surface and production casings. The operator determined that reducing flat time was crucial to create a cost savings (Hsieh 2018). When another operator began their 2018 drilling program in northeastern Pennsylvania, improving efficiencies was discussed with the service company. After quantifying the experience obtained during a previous project, the service company proposed offline cementing because of the economic benefits it could provide.

The service company was able to cement both the surface and intermediate casing strings offline while the operator skidded to the next well to begin rigging up. All surface casings were drilled and cemented offline and the rig skidded back to drill for the intermediate casings, which were also cemented offline. Approximately 15 hours was saved by skidding between surface strings, and another 16 hours was saved between intermediate casings.

This paper discusses the successful use of offline cementing during drilling operations in northeastern Pennsylvania. The flat time reduction achieved during this drilling program can be quantified into a cost savings of approximately USD 80,000 per well.

Improved completion design and field development strategies have provided commodity price resilience by sustained efficiency gains across most major US Shale plays. This rapid evolution in completion practices, however, has created behind pipe opportunities. Refracturing offers a viable solution to maximize on these opportunities, however, its effectiveness is dependent on a variety of factors. The present paper explores the implementation of refracturing as a re-development strategy in legacy shale plays and evaluates it as a truly multivariable problem.

The paper takes into consideration petrophysical parameters, initial completion design, chemical composition, formation quality, time from original completion, refrac completion design and production performance to quantify impact on refrac KPIs such as IP ratio, EUR ratio, decline trend impact, amongst others. The paper does this by using an ACE (alternating conditional expectation) non-linear regression model that incorporates the KPI’s as response variables and utilizes the transforms of a wide range of input variables to identify cause and effect relationships. By running this analysis across multiple legacy shale plays, including the Haynesville, and Barnett, the paper provides best-practices to maximize refracturing success.

While refrac can offer a viable solution in obtaining incremental production, depending on the basin, a refrac can be a tenth of the expense of a new well and can beneficially impact the production from the existing well. In most cases, the analysis found EUR predictions improved by 30% - 200%. While correlations varied across basins and completion design, an inverse correlation was found between refrac KPIs and initial frac intensity.

Although, refracturing in horizontal shale wells is a well-established practice, a significant amount of analysis on their performance is focused on one or two key variables. The present paper adds to the existing body of literature by using data analytics and machine learning to evaluate this strategy from a truly multivariable standpoint. The paper also provides best practices to evaluate and predict refrac performance to de-risk refrac as a field re-development strategy.

This paper presents a method for pinpointing intervals for fracture stimulation in horizontal wells targeting unconventional oil plays. The observation of crossflow among fractures has been of great concern as this phenomenon affects the productivity of producing wells. The cause is related to the effectiveness of fracturing stages, which by itself depends on the rock lithology. We identified interaction among fractured intervals from diagnostic modeling of performance data that exhibited cross flows in the wellbore. On wells exhibiting the most prolonged duration of crossflow, we noted the disadvantages of equal space fracturing. We then used the drilling parameters from MWD data for individual wells and computed the d-exponent profiles and noted significant differences in rock brittleness as characterized by their d-exponent data. Out of the more than 60 wells studied, wells exhibiting minor changes in the d-exponent showed the least indications of cross flows from performance data while in wells with significant cross flows we see the nonuniformity of the d-exponent profile and the negative impact of equal space fracturing.

The artificial lift system (AL) is the most efficient production technique in optimizing production from unconventional horizontal oil and gas wells. Nonetheless, due to declining reservoir pressure during the production life of a well, artificial lifting of oil and gas remains a critical issue. Notwithstanding the attempt by several studies in the past few decades to understand and develop cutting-edge technologies to optimize the application of artificial lift in tight formations, there remains differing assessments of the best approach, AL type, optimum time and conditions to install artificial lift during the life of a well. This report presents a comprehensive review of artificial lift systems application with specific focus on tight oil and gas formations across the world. The review focuses on thirty-three (33) successful and unsuccessful fieldtests in unconventional horizontal wells over the past few decades. The purpose is to apprise the industry and academic researchers on the various AL optimization approaches that have been used and suggest AL optimization areas where new technologies can be developed.

In the past ten years, hydraulic fracturing technology and strategies have made major improvements in the operational efficiency and economic performance of shale well completions. Much of this advancement was derived in the past three years as a response to the global downturn in oil and gas commodity pricing. Mature shale plays across the United States have a surplus inventory of horizontal wells employing highly inefficient completions styles. Amid the low oil pricing environment, operators in the Bakken and Eagle Ford were capable of revitalizing these prior generation wells with great success through re-fracturing programs. In many cases, production of these re-fractured wells rivaled the production of newly drilled and completed shale wells both in terms of initial production post re-fracture as well as extended interval cumulative production. These re-fracturing programs allowed producers to achieve tremendous gains in production while minimizing drilling activity. Although re-fracturing began as a highly economical method to improve production during a time of depressed oil pricing, it is still being used today to improve the production of additional wells recognized as top-tier candidates.

By developing a specific set of criteria to select wells for re-fracturing, these programs can be successfully employed in the Appalachian Basin to improve the economics of gas wells, mitigating the effects of highly discounted natural gas pricing. After the explanation of well candidacy, an economic sensitivity analysis was implemented to illustrate the impacts a strong re-fracturing program could make for operators in the Northeast through a comparison of public data showing production and total reserves for both in and out-of-basin re-fracturing programs. Additionally, while this paper focuses on re-fracturing as it relates to shale formations it also includes information as to how re-fracturing relates to conventional formations.

After looking at the incremental economics of re-fracturing programs implemented in shale plays across the United States and in-basin data, the impacts of gas well re-completion can be fully quantified and understood through the application of probabilistic modeling. Additionally, this modeling further delineates re-completion candidacy by identifying which wells pose higher risks in economic metrics.

Very little information has been published regarding the impacts a re-fracturing program could have in the Appalachian Basin. As the field matures, the topic of re-completions will become increasingly important, and this analysis will allow operators to have a greater understanding of the impacts of refracturing shale gas wells in the Northeast.

Gas-assisted plunger lift (GAPL) could be an effective and economically favorable artificial lift (AL) method to be considered during the AL life cycle for North American shale wells. The main advantage of GAPL is that it improves the well production by reducing liquid fallback and boosts the plunger efficiency through gas injection and increases the gas lift efficiency by assisting in delivering the slugs to the surface. The objective of this study is to capture the GAPL dynamic behavior through a transient multiphase flow simulator. The entire GAPL production cycle was modeled, including plunger fall, gas injection, pressure buildup, and production. First, the GAPL well production history was analyzed to evaluate the well operating condition. Then, a transient simulator was used to model the well flow behavior and production performance with GAPL. The study demonstrated the GAPL impact on flowing bottomhole pressure and the improvement in the well productivity.

A Delaware Basin well case study demonstrates the benefits of dynamic modeling and provides a comprehensive comparison between dynamic simulation results and field data. The simulation work provides insights into the fluid flow, GAPL behavior, and pressure and rate transients of a GAPL well.

The modeling results were validated against field data. A commercially available transient multiphase flow simulator was used and produced outcomes that were in alignment with field data collected. The dynamic plunger cycles were reproduced in the simulation, and the results showed the benefits of GAPL in a typical shale oil well. This could extend the gas lift life by delaying the transition to rod pumps or potentially act as an end-of-life AL solution. In the long term, this reduces the overall AL life cycle cost. The use of transient simulation helps validate AL design concepts, especially for unconventional wells where the flow behavior is very dynamic. This study encourages the use of this analysis in the AL selection workflow to help optimize the overall AL life cycle cost and maximize the net present value (NPV).

Low injected fracturing fluid recovery has been an issue during flowback period that is highly impacted by the fracture closure behavior. Although existing flowback models consider fracture closure volumetrically, they do not represent the true situation of non-uniform fracture closure. In this paper, we proposed a coupled geomechanics and fluid flow model for early-time flowback in shale oil reservoirs. The fluid flow model is coupled with an elastic fracture closure model through finite element methods. In this study, three stages are modeled: fracture propagation, well shut-in and flowback. Cohesive Zone Method (CZM) has been used for modeling fracture propagation. The presented model distinguished the propped part from the unpropped part of the fracture. At the beginning of flowback, the proppants may not be completely compacted in early shut-in time. Thus, permeability evolution during closure is tracked using a smooth permeability transition function. The numerical results have shown that fracture closure during the flowback period is often not uniform. While the uniform fracture closure leads to maximum fracturing fluid recovery, an aggressive pressure drawdown strategy may damage fracture connectivity to the wellbore. An integrated flowback model enables modelling nonuniform fracture closure in a complex fracture network. This study highlights that by choke/pressure drawdown management, operators can influence fluid recovery and even maintain high fracture conductivity. Furthermore, the methodology presented in the paper can also be used for inverse analysis on early flowback data.

Production data and analytical models derived from coupling the linear flow in the reservoir and the linear flow in hydraulic fractures were used in this study to optimize fracture spacing for maximizing productivity of shale oil and gas wells through refracturing. This study concludes that productivity of multi-fractured horizontal wells is inversely proportional to the fracture spacing. The shortest possible fracture spacing should be used to maximize well productivity through refracturing. This supports the practice of massive volume fracturing where as many as perforation clusters with the shortest possible spacing are used for pumping massive proppant into the created hydraulic fractures. Production data analysis indicates that the multi-fractured horizontal oil and gas wells could have higher productivity if they were fractured with less perforation cluster spacing. Mathematical model analysis implies that reducing the cluster spacing from 70 f t t o 15 f t t h r o u g h r e f r a c t u r i n g c a n d o u b l e d w e l l p r o d u c t i v i t y, w i t h t h e M i n i m u m Re q u i r e d C l u s t e r S p a c i n g (MRCS) determined by well completion constraints (packers, perforation clusters, and casing couplings). Result can be checked for fracture trend interference on the basis of analyses of pressure transient data or production data.