bluuebunny/crossref_metadata_2025 huggingface dataset:
Modelling the Interfering Effects of Gas Condensate and Geological Heterogeneities on Transient Pressure Response
Authors: Hamdi H. , Jamiolahmady M. , Corbett P. W.
Published: September 2011

Numerous publications have investigated the effect of gas condensate fluid on the transient pressure well-test (WT) response. However, to the best of authors’ knowledge, its combined effect with geology has not been studied. Our findings presented here demonstrate that geology can complicate the WT response and make it difficult for interpretation. In this study the impact of geological heterogeneities on the WT response of a commingled braided-fluvial gas/condensate reservoir has been investigated. Numerical well-test data were generated for a single-well model with a commercial compositional reservoir simulator. Several sensitivity simulations were performed to explore the effects of correlation length, vertical permeability, relative permeability, production rate and drawdown time, on the pseudo-pressure derivate curves. The WT weighting Kernel function and the calculated well-pressure sensitivity coefficients were implemented to demonstrate different trends of drawdown and build-up responses encountered in this study.

The results clarified that some geological heterogeneities and production parameters can alter pressure distribution and condensate saturation, and mask the native model WT signatures. In this exercise, it was demonstrated that ramp effect, a geologically complex phenomenon in high net:gross commingled reservoirs, is affected by the condensate formation. This interfering phenomenon is reflected on the derivative curves and is magnified in the presence of the shorter correlation lengths, the lower vertical communications and the higher production rates. We also examined the stepwise stripping of the reservoir heterogeneity, in order to show the impact of each facies on the build-up and drawdown transient pressure response.. The time dependent sensitivity coefficients were calculated to show that the drawdown test is very sensitive to effective permeability in near wellbore areas, where condensate is prone to build up with time. In the build-up, on the other hand, the condensate saturation is almost invariant with time and affects the early time region. This work leads toward better understanding of the influence of geology in gas/condensate well-test interpretation.
A New Modified Genetic Algorithm for Well Placement Optimization under Geological Uncertainties
Authors: Morales A. N. , Nasrabadi H. , Zhu D.
Published: September 2011

Determining optimum location of wells is a crucial step in field development. A realistic geological model is an important factor in finding an accurate optimum well location. Usually history matching is used to come up with a realistic geological model. However, there is no unique solution to the history matching problem. Often several geological models could match the history data. This introduces some risk associated with the results of well placement optimization algorithm.

In this work, we present a new modified genetic algorithm (GA) for well-placement optimization under geological uncertainty. The inputs of the algorithm are possible geological models, and the level of risk that the user can accept. In the algorithm, the classic GA is modified so that: 1) in evaluating the fitness value (cumulative production or net present value) of each individual (well location) all the possible geological models provided by users are evaluated, 2) upon convergence of the algorithm, the output is one optimum well location as the fittest individual taking into account all the provided geological models, and 3) this optimum well location is selected based on the input user-defined level of risk. Most current available algorithms in the literature do not allow the user to input the risk factor desired and individual weights for each realization. The risk-constrained algorithm will provide different optimum well locations depending on the level of risk the user wants to take. All these features make the new algorithm much more efficient and applied than current well-placement algorithms in the literature for handling geological uncertainty.

We present the application of the risk-constrained algorithm to a horizontal well-placement optimization in a gas condensate reservoir, Qatar’s North Field, with multiple possible permeability fields and with different user-defined risk factors.
Improved Normalization of Time-lapse Seismic Data using NRMS Repeatabity Data to Improve Automatic Production and Seismic History Matching in the Nelson Field
Authors: Kazemi Alireza , Stephen Karl D. , Shams Asghar
Published: September 2011

Seismic history matching requires an accurate representation of predicted and observed data so that they can be compared quantitatively for automated inversion. Often, observed seismic data is obtained as a relative measure of the reservoir state or its change. Unless these data are calibrated, we need to normalise them. In this study we use NRMS, a repeatability measure to filter the observed time-lapse data so that normalization is more effective.

We apply this approach to the Nelson field. We use three seismic surveys over nine years of production. We normalize the 4D signature based on deriving a least squares regression equation between the observed and synthetic data. Two regression equations are derived as part of the analysis. To obtain the first, the whole 4D signature map of the reservoir is used for each interval while in the second, 4D seismic data is used from the vicinity of wells with a good match to production data. NRMS data is used to remove more anomalous measurements. Net:gross and permeability are modified to improve the match.

The best results are obtained when the normalization is performed using NRMS filtered maps of the 4D signature. The history match to the first six years of data is reduced by 55 per cent. The misfit for the forecast of the following three years is reduced by 29 per cent. If only production data is used in history matching, the history and forecast misfit reductions are 45% and 20% respectively. In this case the seismic misfit increases by 5% while in the best case it dropped by 6%.

Updating the reservoir by history matching of 4D data gives us better understanding of changes to the reservoir and also reduces risk in forecasting leading to better decisions about reservoir maintenance and infill well targeting.
Molecular Diffusion and Dispersion Coefficient in a Propane-Bitumen System: Case of Vapour Extraction (VAPEX) Process
Authors: Etminan S. Reza , Haghighat Parnian , Maini Brij B. , Chen Zhangxin
Published: September 2011

The solvent based recovery methods have recently attracted considerable attention due to environmental and energy concerns associated with thermal recovery methods. However, knowledge about molecular diffusion and mechanical dispersion as two key parameters to characterize these processes is limited. To find out the contribution of convective dispersion in enhanced production rates in VAPEX, three experiment sets were conducted for a system of propane and Athabasca bitumen. In the first set, molecular diffusion coefficient of propane in Athabasca bitumen was determined through a constant-pressure technique. A numerical technique was developed which also accounts for significant swelling of bitumen due to propane dissolution. The Levenberg-Marquardt method was utilized to estimate the molecular diffusivity through an inverse approach. In the other experimental set, a physical sand pack model was used to run the VAPEX experiments in the same temperature and pressure. The obtained dead oil production rate values were introduced into VAPEX analytical model. It allowed us to back-calculate the value of dimensionless number Ns. Finally, a set of PVT measurements were conducted to determine the viscosity and density of diluted bitumen for different values of propane concentration. This enabled us to find the dispersion coefficient from the definition of Ns term.

Molecular diffusion and convective dispersion are two important parameters for characterization of processes like VAPEX, ES-SAGD and other hybrid thermal solvent scenarios. Accurate estimation of these parameters improves predictions of compositional reservoir simulators. Obtaining propane molecular diffusivity into the bitumen and comparing it with our VAPEX back-calculated dispersion coefficients, would allow us to evaluate contribution of the convective dispersion to recovery rate enhancement in VAPEX experiments.
Secure Low-Cost, High-Volume Data Transmission of Wellsite Data to Remote Surveillance Centers
Authors: Sann A. Clark
Published: September 2011

Remote surveillance centers and intelligent production systems need data that often originates from wellsites located in extremely remote locations. Economical solutions are now available that provide consolidation of data at the wellsite, highly secure encryption, data compression, and data communications from most locations.

Traditionally, off-the-shelf supervisory control and data acquisition (SCADA) systems, fast computers, routers, virtual private network (VPN) appliances, and very small aperture terminal equipment have been employed for these purposes. Until now, the expense and complexity of these solutions have limited their use to only the most critical wells.

A new system has been developed that provides a low-cost and simple data consolidation/data transmission solution. What used to require several computers and associated networking and security hardware can now be accomplished in one low-cost, single board or rack-mounted computer.

Data can be acquired from a variety of wellsite end devices, such as pressure and temperature transmitters, chemical automation controllers, tank monitoring systems, down-hole electronic gauges, electrical submersible pumps (ESPs), and intelligent well systems. Also, numerous fiber-based sensors, such as distributed temperature sensors, real-time casing monitoring systems, and fiber-based down-hole pressure and temperature gauges can provide data to this system. This solution is intended for use in unattended remote locations, operable from solar power, and will function in extreme environments.

Acquired data can be provided locally via Modbus protocol or OLE for Process Control (OPC). Data can also be economically encrypted, compressed, and transmitted off the wellsite to remote surveillance centers in near real time. Data communication is performed via low-cost data communication systems such as cellular or Inmarsat's new Broadband Global Area Network satellite system.

Real-time production data, diagnostic data, and log data can also be transmitted off the remote wellsite, either automatically or upon demand.

Additionally, the system supports remote administration. Some measurement devices can be remotely reconfigured and remotely controlled. Examples of this include rescaling, recalibration, rebooting, restarting, and time synchronization of the end devices or of the data collection application.

This paper describes the system, how it has been deployed, and the proven benefits of the system.
Applications and Laboratory Studies of a New Class of Silica Polymerization Inhibitors of Bio-renewable Origin
Authors: Reyes-Garcia E..
Published: September 2011

Silica precipitation during a sandstone acidizing treatment or its subsequent deposition post-treatment can negate the effectiveness of said acid treatment. Moreover, the removal of tenacious silica scale from a wellbore can sometimes result in matrix damage as a result of injecting the dissolved silicon into the formation. While this problem is well-known, effective solutions continue to be sought to sustain mature, hydrothermal, and siliceous wells that suffer from fines migration. Geochemical reactions operative in siliceous formations can induce various processes, such as silica migration, diagenesis, or hard scale. Laboratory investigations focused on preventing the formation of silica have identified a new class of silica polymerization inhibitor (SPI). The SPI mechanism is disruption or retardation of the condensation and polymerization of silicic acid monomers and oligomers and the ultimate growth of amorphous silica. Aluminum, commonly present in clay and feldspar minerals, can interfere with the SPI, so its effect has been studied. Dissolved Al3+ in the fluid must be regulated with the use of chelating agents to prevent precipitation, along with the silicon-SPI complex, at pH levels of interest in acidizing operations, namely <4. Most effective acidizing treatments employ HF formulations, with HCl or organic acids, to dissolve the silicate minerals or scale in the near-wellbore region; hence, these studies are directed toward this application.

The SPI described in this work is a naturally occurring material of low molecular weight (MW) that effectively maintains in solution total dissolved silicon concentrations of up to 3,000 mg/L (0.12 M) below 2 pH, where minimal precipitation has been observed. Minimization of silica precipitation with typical concentrations of 1,000 to 2,000 mg/L of SPI was attained at <4 pH. At this and lower pH levels, nearly constant silicon concentrations of 2,400 mg/L were maintained. These findings are significant to maximizing resource recovery because they allow the operator to consider alternatives for treatment processes geared toward higher-temperature wells, fracture acidizing, and expansion of the pH range of treatment fluids.
Successful Applications of Pressure-Rate Deconvolution in the Cad-Nik Tight Gas Formations of BC Foothills, Canada
Authors: Jones Jack , Chen Andrew
Published: September 2011

The Cadomin-Nikanassin (Cad-Nik) sandstone formations in the lower Cretaceous reservoirs along the reverse thrust faulting belt of North Eastern British Columbia, Canada, have emerged in the recent years as a new tight gas play. The low porosity (3% ~ 6%) of the rock matrix controls gas storativity, while the presence of natural fractures in the form of clusters or swarms allows significant and sustainable flow rates for commercial productions. Newly drilled wells are commonly hydraulically fractured to establish or enhance wellbore connectivity to the natural fracture network.

Seismic mappings of these structural unconventional gas reservoirs provide the early assessments of resource sizes and initial gas-in-place (IGIP), which usually bear huge certainties due to the difficulty of determining reservoir structural closures and pay porosity cutoffs. Regional analogue wells are often used to guide development decisions. Meanwhile estimating connected reservoir volumes through conventional gas material balances (P/Z vs. cum production) and production data analysis (RTA) has not been without challenges. Fairly long pressure buildups, on the order of 100's of hours, are often performed without seeing any pressure stabilization. The applicability of pressure extrapolation to these tests has not been systematically investigated. Thus, reliable average reservoir pressure estimates require much longer well shut-in times in order to perform meaningful gas material balance. Since this is not practical, confidence in material balance results requires a second, independent method for establishing connected well volumes to be used in comparisons and cross-checking. One possible choice is rate-transeint analysis (RTA) but, in these fields, many times well head pressure data are also unavailable or unreliable.

This paper presents two field case studies, which demonstrate the successful application of the pressure-rate deconvolution approach combining a well's long, high quality production rate history with accurate downhole pressure data from relatively short buildup tests. This approach allows the reservoir engineer to (1) reconcile the performance based EUR estimates with the volumetric OGIPs, (2) establish, at least, minimum well drainage size and connected volume and (3) pick possible infill-drilling opportunities. A final benefit is that this often leads to a better understanding of well/reservoir parameters.
Productivity Impairment Due to Fines Migration: Steady State Production Regime
Authors: Bedrikovetsky P.. , Vaz A.. , Machado F.. , Zeinijahromi A.. , Borazjani S..
Published: September 2011

Permeability decline during corefloods with high rates has been widely reported in the literature. It has often been explained by the lifting, migration and subsequent plugging of pores by fine particles, which has been observed in numerous core flood tests. The phenomena have been connected to well productivity impairment during fines production that also has been widely observed in oilfields. The present paper derives formula for skin factor based on the modified particle detachment model with maximum retention function. The fines migration induced skin is shown to increase with increase of rate and initial attached fines concentration.
Successful Application of a Distance-to-Boundary Technology Under Tough Drilling and Reservoir Conditions
Authors: Salim D.. , Samaroo R.. , Barbosa J.. , Silva C.. , Guedes A..
Published: September 2011

Accurate placement of a horizontal well within a reservoir can be complicated and with uncertainties (McLennan, 2006). That was the case for the 8.5-in. horizontal well in the study being reported. Uncertainty in the structural geology existed due to distance from the closest well (~500 m) and also the vast number of faults identified on the seismic data.

With the well supposedly landed in the reservoir, the expectation on start drilling sand was not met upon drilling out the casing shoe. Approximately 180 m MD of shale was encountered before making a decision to use the well for appraising the upper seismic reflector. The section was subsequently abandoned for a sidetrack that aimed at producing the upper sand lobe.

From the original casing shoe of the landing point, to access the upper sand lobe with the shortest shale section possible, a strong build in inclination to >90° would be required upon exiting the shoe. Once the wellbore entered the reservoir sand package through the base, a change in trajectory was immediately required to avoid exiting through the top of the thin sand. The sooner the well entered the sand, the greater the success of the well because drilling more than 410 m MD would intersect the drainage radius of another producing well; hence, creating undesired production interference.

A new model was developed and the well plan was executed. Based on the model, approximately 140 m MD of shale was expected before intersecting the base of the reservoir; however, in actuality, 167 m MD of shale was drilled prior to intersecting the reservoir entrance. Within 20 m MD inside of the reservoir, an indication of the top of the reservoir was observed on the distance-to-boundary inversion. As a result, the trajectory was adjusted accordingly to prevent exiting the reservoir that resulted in achieving 60% of reservoir sand.

This case study will highlight how the combination of real-time distance-to-boundary mapping technology and proactive steering decisions aided in eliminating a second consecutive sidetrack of the horizontal section.
Designing Completions after Predicting Wellbore Dynamic-Shock Loads During Perforating
Authors: Burman J.. , Schoener-Scott M.. , Le C.. , Suire D..
Published: September 2011

Oilwell casing perforation has been used in the industry since 1932 and was pioneered by the Lane-Wells Company who introduced the bullet-gun perforating technique. Shortly after the introduction of the bullet gun, explosive jet perforators were introduced, which provided a different and more aggressive way to perforate casing.

With the increased demand for oil and gas over the past decades, operators have been forced to explore deeper, hotter reservoirs to find the most prolific reservoirs. These deepwater opportunities have required constant changes to equipment and services to increase their technical capabilities for performing in more critical environments. Perforating with higher-shot densities, propellants, and larger perforating guns has been ongoing to meet these new challenges.

A major problem with these increases, however, is the difficulty in predicting dynamic wellbore behaviors that cause tubulars to collapse and bend and packers to unset as perforating guns were detonated. Research to understand the pressure behavior during the perforation event, in addition to the solid loading that is imparted to the tubulars, packers, and other completion hardware in the perforating assembly, was needed to enable the industry to go forward with a high level of confidence that wells could be completed safely and cost effectively.

This paper discusses a shock-wave computer modeling program that evaluates the mechanical risk factors of well components to ensure that the health, safety, environment, and service quality needs in a design are addressed. A time-marching, finite-differences technique is applied as the numerical method for both fluids and solids. The software is installed on a personal computer and typically executes the models within several minutes to several hours, depending on the complexity of the job design.

The physics-based model has been validated (Schatz et al. 1999 and Schatz et al. 2004) with special high-speed recorders that sense pressure, temperature, and acceleration at a sampling frequency of 115,000 samples per second.

This paper provides data from offshore oil and gas wells in the Gulf of Mexico to demonstrate the success of the design.
Flexible Core Sample Acquisition Program for Deepwater, Offshore Brazil
Authors: Romero P.. , Lofts J.. , Lovera O.. , Georgi D..
Published: September 2011

Deepwater operations (with high rig spread rates) like those offshore Brazil require an operator to very carefully consider the benefit-versus-cost of a full coring acquisition program. Yet, core-based information is invaluable in the exploration phase of a field's potential, and the basis of thoroughly understanding reservoir rock potential (petrophysics) is founded on these core measurements. With the drive for cost efficiency, conventional full-core acquisition is often curtailed and subsurface teams must rely on percussion or rotary sidewall core samples. This choice is made even though it is known that for many core analysis measurements, the accuracy of the measurement is directly proportional to the pore volume.

A new rotary sidewall coring technology applicable for deepwater environments has been applied offshore Brazil that enables the recovery of more than three times the core volume when compared to cores recovered with standard rotary coring tools. The resulting increase in pore volume positively impacts the accuracy of the core porosity measurement and other measurements that depend on pore volume (e.g., capillary pressure, water saturation, and SCAL measurements, in general). Recovery of up to 60 samples during a single trip in the well is achievable, enabling a good lithology sample spread in one acquisition. Acquisition time per core is more than three times faster that of the previous-generation rotary coring tools, resulting in significant reduction of coring time, especially for offshore operations. Coupled with a new bit design, optimized to take advantage of the increased rotational speed, cores can be cut at even higher levels of overbalance pressure (> 1,000 psi [6.89 MPa], depending on porosity and permeability). The ability to take up to 60 larger-volume cores in one run provides operators, like those in deepwater operations of Brazil, the flexibility to continue to vary the design of core acquisition programs to meet the benefit-versus-cost dilemma of full-core acquisition. They also enable much better contingency data gathering if full-core programs are not successful.
Large-Bore Expandable Liner Hangers Significantly Improve Operational Cost in a Deepwater Gulf of Mexico Well
Authors: Johnson M.. , Ardoin K.. , Bullard B..
Published: September 2011

When drilling offshore wells, well-bore architecture will typically require casing strings larger than 13-5/8-in. to be "hung-off in the casing hanger located at the wellhead. To date, this has been the most widely used method, albeit a time consuming and usually costly approach. With solutions needed to alleviate these issues, a new expandable technology has been developed as an alternative to the conventional approach.

An expandable large-bore liner hanger that allows an operator to set a liner instead of a full string of casing has recently been designed. Plans for operations within the Gulf of Mexico region began after successful applications of the new large-bore expandable liner hanger were run in other parts of the globe. With internal diameter restrictions coming into play at the wellhead in the Gulf, the original product required some design modifications.

The contents of this paper will cover the development and successful installation of the first large-bore expandable liner hanger (LBELH) in deepwater Gulf of Mexico operations for ENI's Triton well. Advantages in this installation included casing placement flexibility, redundant seals at the top of casing, improved load support reliability, the capability of rotation and reciprocation during cementing, cost reduction, elimination of requiring the casing hanger to seal in the casing adapter, and complications with shallow deviation.

Due to the successful installation of the large-bore expandable liner hanger, the customer was able to save on costs of 2,300 feet of 16 in. casing, greatly improving economics for the project. With the slick-bore design of the system, equivalent circulating densities were greatly lowered. Coupling this feature with the capability to rotate and reciprocate during cementing greatly improved the cementing quality, as well as run-in speeds, with no mud loss. These two features are expected to increase well life and reduce future remedial work to the well.

By eliminating the requirement to properly and precisely space out liner jobs on floating rigs in deepwater regions, pressure integrity issues of conventional systems can be avoided.
Advanced LWD Imaging Technology in the Niobrara – Case Study
Authors: Koepsell Randy , Han Shim Yen , Kok Jeffrey , Munari Michael , Tollefsen Edward
Published: September 2011

The Niobrara formation is an increasingly active exploration target in the Denver-Julesburg basin that contains both reservoir rock and source rock. The reservoir rock consists of up to four laterally continuous chalk benches and the source rock is comprised of three organic-rich interbedded shales. Both permeability and porosity in the Niobrara chalk are relatively low and production is expected to be enhanced by natural fractures related to: horst and graben structures, dissolution of evaporite beds, wrench faulting, listric faulting, regional stresses, and pore pressure. To develop the Niobrara formation, horizontal drilling combined with multistage hydraulic fracturing increasingly is used. To enhance reservoir understanding and optimize field recovery, advanced logging-while-drilling (LWD) services are now available for real-time acquisition and transmission of high-resolution electrical images of the borehole, azimuthal gamma ray, and multi depth measurement of formation resistivity. Analysis of this information in real time with high data rate LWD acquisition telemetry allows proactive well-placement decision making by comparing apparent dip of the formation to the borehole trajectory. This is effectively used for maximum reservoir contact of the lateral wellbore in the desired chalk bench. In addition, the analysis of the high-resolution images facilitates fracture identification, fault estimation, and structural analysis for the optimization of stage designs for hydraulic fracturing. This paper will expand the use of LWD with high-resolution image interpretation, formation evaluation, fracture system analysis, and structural analysis for the purpose of drilling better-performing wells through optimized well placement and hydraulic fracturing operations.
Building Real-time, Remote Pressure Management Service Capability to Enhance Safety and Reduce Drilling NPT
Authors: Sadlier Andreas , Wolfe Chris , Reese Mike , Kenda Bill
Published: September 2011

As drilling environments become more challenging and complex, the need to increase safety margins and reduce drilling non-productive time (NPT) costs continues to intensify. It is also likely that our industry's future will face greater pressure from regulators and the public to ensure safer drilling practices. More and more operators are turning to remote surveillance services as a way to provide real-time interactions with wellsite personnel to mitigate drilling hazards.

Through remote monitoring services, dedicated personnel can actively monitor multiple operations and spot potential problems that busy rig hands mightotherwise overlook or lack the specialized training to recognize. In addition to the health, safety, and environmental benefits of fewer personnel on location, remote service engineers/specialists can easily collaborate with a team of experts located in an offsite center of excellence, providing greater wisdom for real-time decisions compared to any one person at the wellsite.

Developing a value-added remote service from scratch requires many elements for success. For example, providing a remote, real-time integrated pressure management service requires careful planning and development of service components. These include facilities and communications infrastructure, software and data-management tools, clearly defined service integration processes and communications protocol, trained and available personnel for job execution, and customer partners willing to field test service solutions.

This paper offers a case study on how a successful remote, real-time integrated pressure management and wellbore stability service has been developed in the US Gulf of Mexico. It discusses the various aspects of the service's development from defining the service objectives, components, and deliverables to the communications protocols and the personnel competencies and training requirements for staffing. It also describes aspects of the physical facilities, communications infrastructure, and real-time software tools that provide automated alarms, which aid personnel in keeping the drilling operation out of trouble. Finally, a customer field trial that helped to improve the service further is examined and a brief summary of future developments is provided in the paper.
Sensors and the Way Forward for Sensing Efficiently and Effectively
Authors: Aminzadeh Fred , Al Yateem Karam , Puecher Leonardo
Published: September 2011

Sensors provide engineers with the necessary data for their day-to-day activities and assure smooth operation, monitoring wells and equipments in a field. Almost every new well drilled has a number of sensor during the drilling and completion. Sensors are an integral and vital part of the digital oilfield and the real time monitoring, and control. These are all simple requirements for the intelligent filed in order to better understand the well performance and ensure safe and efficient operation. They are most beneficial in remote areas where HSE is of a major concern. They optimize the placement of new drillings and work over sidetracks through making it possible foreseeing change in real-time, supporting the initiation of a remedial action in case of anomalies occurrences. Overall, their existence in any reservoirs optimizes the ultimate oil recovery.

This paper will discuss the general history of sensing along with their oil industry record. We will focus on the established methods of-well-sensing, as well as the current issues, capabilities, requirements, and visualization. Data mining and integration of sensor data using soft computing technologies is of paramount importance. The paper will address their various functions, signal type, robustness, technical background and the purpose of placement. It will also discuss communication infrastructure, networking, and reliability challenges. The focus will be on In addition, we will provide an in-depth investigation of various types of sensors and their functionality, advantages and drawbacks. We will also illustrate desired smart network embedded system/module and wireless systems. We will conclude with examples of oilfield applications, lessons learned and future trends.
Modeling, History Matching, Forecasting and Analysis of Shale Reservoirs Performance Using Artificial Intelligence
Authors: Mohaghegh Shahab D. , Grujic Ognjen , Zargari Seed , Kalantari Masoud
Published: September 2011

Producing hydrocarbon from Shale plays has attracted much attention in the recent years. Advances in horizontal drilling and multi-stage hydraulic fracturing have made shale reservoirs a focal point for many operators. Our understanding of the complexity of the flow mechanism in the natural fracture and its coupling with the matrix and the induced fracture, impact of geomechanical parameters and optimum design of hydraulic fractures has not necessarily kept up with our interest in these prolific and hydrocarbon rich formations.

In this paper we discuss using a new and completely different approach to modeling, history matching, forecasting and analyzing oil and gas production in shale reservoirs. In this new approach instead of imposing our understanding of the flow mechanism and the production process on the reservoir model, we allow the production history, well log, and hydraulic fracturing data to force their will on our model and determine its behavior. In other words, by carefully listening to the data from wells and the reservoir we developed a data driven model and history match the production process from Shale reservoirs. The history matched model is used to forecast future production from the field and to assist in planning field development strategies. We use the last several months of production history as blind data to validate the model that is developed.

This is a unique and innovative use of pattern recognition capabilities of artificial intelligence and data mining as a workflow to build a full field reservoir model for forecasting and analysis of oil and gas production from shale formations. Examples of three case studies in Lower Huron and New Albany shale formations (gas producing) and Bakken Shale (oil producing) is presented in this paper.
Drilling Automation: An Automatic Trajectory Control System
Authors: Pirovolou Dimitrios , Chapman Clinton D. , Chau Minh , Arismendi Hector , Ahorukomeye Mbaga , Penaranda Juan
Published: September 2011

In the last decade, the oil and gas industry has witnessed the emergence of rotary steerable systems (RSS) that led to certain achievements that were not possible with conventional mud motors. Rotary steerable systems enable faster drilling, smoother wellbores, and extended-reach drilling (ERD).

Still, a drilling assembly built around an RSS tool is sensitive to factors such as bit type, operating parameters, type of drilling fluid, lithology, and borehole diameter. Therefore, it is not always optimal for a human operator (typically a directional driller) to select and issue the right commands to the drilling tool at the right time. This situation becomes even more challenging when those decisions have to be made in a matter of minutes.

Steering the well accurately is paramount to geo-steering, optimal well placement in the reservoir, and anti-collision.

This paper discusses a new system that monitors all real-time data that is available, "learns" the steering behavior of the drilling assembly, and uses the acquired information to create more accurate projections for the directional driller. The system recommends the optimal command to direct the drilling tool according to plan.

This tool is currently being used by a number of field locations as an advisor. The next version of the system, being field tested, autonomously issues downlink commands directly to the RSS tool, making it an automatic trajectory controller. The concept is very similar to the autopilots used in commercial airplanes today. The anticipated value from this technology is better service quality and higher performance that can be delivered predictably and consistently.

Preliminary results look very encouraging. During the evaluation period, the system has accumulated approximately 5,000 running hours, corresponding to approximately 72 runs. These tests are in various hole sizes and well profiles, using different RSS tools.
An Improved Methodology to Obtain the Arps’ Decline Curve Exponent (b) for Tight/Stacked Gas Reservoirs
Authors: Yu Shaoyong
Published: September 2011

Production performance forecasting and the estimated ultimate recovery (EUR) evaluation are two of several uncertainties in the study of tight gas reservoirs. Using the Arps’ decline curve analysis to extrapolate the estimated ultimate recovery (EUR), based on the future production forecasting, is still a widely employed engineering tool in the oil and gas industry today. Tight gas reservoirs usually have a long transient/transitional flow period due to its low permeability. Simply by using the best fit "b" value to estimate the best EUR could generate an error as much as 100% from the true EUR. There has been a number of technical papers published dealing with this issue.

This paper will present a new improved methodology to determine a more accurate "b" value to be used in the Arps’ decline curve analysis for tight gas reservoirs. This new approach, using a newly developed relationship between Qcum, Qcum, t→∞, qt and t, is more rigorous and much easier to use in comparison with all other existing ones. This new improved methodology will not only make future production forecasting more accurate, but also estimate the original-gas-in-place (OGIP) controlled by the well much easier.

In Western Canadian Deep Basin, there are many extremely "tight" gas reservoirs that consist of multiple stacked shorefaces. Permeability in each shoreface varies very significantly, generally with the upper shoreface having a better permeability and the middle and lower ones having a permeability as poor as 0.01 mD. By using a reservoir simulator, a number of simulation runs have been performed by the author to answer the following questions:

Could Fetkovich's b-values recommendation (mostly b<= 0.4 ~ 0.5 for single gas layer, b>=0.5 for multi-layer without crossflow) still be applied to the tight gas reservoirs? In a multi-stacked shoreface reservoir, does the lower perm zone contribute to the overall production? Moreover, how and when will it influence the production profile? When using the Arps’ decline curve analysis, what are the reasonable b-values to be used for the tight/stacked gas reservoirs?

Both synthetic production decline profiles generated from simulation runs and a field example are presented in this paper to illustrate this new proposed methodology and to answer the above three questions.
Leveraging a Technical Domain Taxonomy to Enhance Collaboration, Knowledge Sharing and Operational Support
Authors: Perry Phil , Wise Wade , O'Neill Dennis , Jensen Mary
Published: September 2011

The E&P industry is a highly technical and complex world which is inhabited by skilled professionals of many different specializations and backgrounds working all over the globe. In order for an organization to perform effectively, it is very helpful to have a shared view of that world and a common vocabulary to describe its artifacts, processes and challenges.

Over the past two years, we have developed a multi-faceted taxonomy that describes the realm of technical services in the upstream E&P domain. It comprises the areas of E&P disciplines, application methods and environments, technical services, and problem diagnoses.

This taxonomy is finding wide use within our technical communities and has been embodied into computer-based applications in the areas of collaboration (workspaces and wikis), knowledge capture, expertise identification, field technical support and "smart" enterprise search.

This paper discusses our methodology in establishing and reviewing the E&P taxonomy within a large technical community and how we are applying it to solve real-world business problems.
Reducing Complexity: A Case History of De-manning Traditional While Drilling Wellsite Services
Authors: Dwyer James , Swanson Aaron , Laing Moray , Brady James
Published: September 2011

All technology and new concepts evolve at different rates. Adoption is driven or slowed due to costs, complexity or accessibility. This was true for the automotive industry, computers and is also true for the digital oilfield. Using travel as an analogy it is easy to conceptualize technology adoption hurdles that have occurred. The evolution of getting from one place to another changed from travel by foot to traveling by car. Similarly the evolution of information and data transfer evolved from hand writing or the use of a type writer into the computer and digital age. In fact our industry has undergone its own evolution to help improve the extraction of hydrocarbons. One such evolution in our industry has been slowed. This is the movement of personnel from the well site to the web site.

With the growth of the global oil industry, there is a greater need to have experienced personal monitoring and analyzing the real-time data that is gathered. This growth in demand has lead to a vacuum in availability of experience necessary to perform this analysis on a daily basis. To fulfill this global void, the accessing the data and rig site remotely came into play more than 20 years ago.

Although this concept of removing the personal from the rig site isn't a new one, recent increase in technological capabilities of communication, increases in the complexity of data sets, and an increase in the quantity of experience personal have driven the industry to relook at the option of remote utilization. This paper will not detail the big crew change or attempt to promote the value of the movement of personnel from the well head to the office. Rather this paper will provide, by means of a case history, an example of how to reduce the complexity involved well site ‘demanning’. The case will illustrate a simple staffing and support methodology. The case will illustrate what was done, technology used to effect the change and describe the outcome
Radio Frequency Identification of Remotely Operated Horizontal Frac
Authors: Tough John , Mason Jane , Biedermann Randal , Visotto Al
Published: September 2011

There is a very significant move today towards multiple zone fracturing operations in a single well where zones are separated and individually fractured, particularly in shale gas completions. This technique has to date involved the use of ball seat activated sliding sleeves located across each zone, with consequent reductions in internal diameter (ID) and attendant flow characteristic limitations or selective perforating, fracing and isolation with a bridge plug in a cemented casing string while working up the hole. Both approaches involve many downhole intervention operations such as perforating, shifting sleeves, running plugs and subsequently milling them up with coiled tubing (CT) intervention, all of which extend the length of the operation and add to the overall costs.

To simplify the process of multiple fracturing operations, especially in open hole, a new approach has been designed which uses Radio Frequency Identification (RFID) techniques to remotely operate sliding sleeves. The number of sleeves that can be run in a well using this technology is essentially unlimited, each one having the same ID and a unique electronic address which allows it to be operated remotely at will. This approach provides for a means of making considerably more zones available for treatment without physical intervention with CT or wireline and thereby speeds the multiple frac operations and allows for wellbore clean up from the toe to the heel of the well.

In this paper the authors will describe the design and operation of the RFID operated frac sleeves and the advantages they provide. They will go on to detail the Worlds’ first remotely operated horizontal openhole frac completion where frac sleeves and swell packers were used in an extended reach horizontal shale gas well.
Shear Sensitivity of Borate Fracturing Fluids
Authors: Bjornen Kevin H. , Hodge Richard M. , Cawiezel Kay E. , England Kevin W.
Published: September 2011

Borate-crosslinked fracturing fluids have been used in the oil and gas industry for nearly 40 years. These fluids consist of three basic components (polymer, crosslinker, and pH buffer) which are considered relatively simple to optimize for a variety of field applications. Among the unique features of this fluid is the ability of the crosslink viscosity to "re-heal" or "recover" after exposure to high shear rates. Based on laboratory tests described in SPE 134266, it was determined that the "re-healing" time can be excessive for some borate-crosslinked fluids exposed to high shear, resulting in limited near-wellbore viscosity and screen-outs in the field.

Using a laboratory-scale flow loop to simulate the wellbore shear environment, various borate-crosslinked fluids were exposed to a wide range of shear history conditions before loading into a high temperature, high pressure rheometer. In addition to the common viscosity versus time profile, the early-time viscosity development of each fluid was analyzed to quantify the effect of shear history on recovery time.

This paper defines critical shear rates and exposure times that adversely impact early-time viscosity development of borate-crosslinked fracturing fluids. Also, the test results show that the impact of wellbore shear conditions on recovery time can be minimized by adjusting the concentration of the polymer, borate crosslinker, and/or pH buffer.

The techniques and guidelines provided in this paper can be used to identify detrimental wellbore shear conditions that will lead to excessive recovery times. The paper also demonstrates optimizing borate-crosslinked fluids with common on-site tests can result in fluid compositions with increased shear sensitivity.
A New Analytical Method for Analyzing Production Data from Shale Gas Reservoirs Exhibiting Linear Flow: Constant Rate Production
Authors: Nobakht M. , Clarkson C.R.
Published: September 2011

Hydraulically-fractured vertical and horizontal wells completed in shale gas and some tight gas plays are known to exhibit long periods of linear flow. Recently, techniques for analyzing this flow period using (normalized) production data have been put forth, but there are known errors associated with the analysis. In this paper, linear flow from fractured wells completed in tight/shale gas reservoirs, subject to a constant production rate constraint, is studied. It is shown analytically that the square root-time plot, a plot of rate-normalized pressure versus square root of time which is commonly used to interpret linear flow, depends on the production rate. It is also shown that depending on production rate, the square root-time plot may not be a straight line during linear flow; the higher the production rate the earlier in time the plot deviates from the expected straight line. This deviation creates error in the analysis. To address this issue, a new analytical method is developed for analyzing linear flow data for the constant gas rate production constraint. The method is then validated using a number of numerically-simulated cases. As expected, based on the analytical derivation, the square root-time plots for these cases depend on gas production rate and for some cases it does not appear as a straight line during linear flow. Finally, it is found that there is excellent agreement between the fracture half-lengths obtained using this method and the input fracture half-lengths to numerical simulation.