bluuebunny/crossref_metadata_2025 huggingface dataset:
Autonomous Perforating System for Multizone Completions
Authors: Entchev Pavlin B. , Angeles Renzo , Kumaran Krishnan , Subrahmanya Niranjan , Tolman Randy
Published: October 2011

Autonomous downhole tools offer a range of advantages over conventional tools controlled manually via umbilicals. For instance, perforating guns or bridge plugs could be dropped or pumped downhole without the use of wireline (slick or electric line), coiled tubing or tractors. Because umbilical intervention is no longer required, the tools may automatically perform an action (e.g., perforate a desired interval) with substantial cost reduction and enhanced safety. The elimination of wireline lubricators, lifting equipment, wires, additional personnel and vehicles minimizes the potential for accidents in this already confined space. This is particularly important during hydraulic fracturing operations where this method may enable faster pumping rates and increased fracture volumes during daylight hours. Use of this technology will also reduce air emissions from support equipment that would no longer be required.

This paper describes an autonomous perforating tool currently being developed by ExxonMobil Upstream Research Company. This patent pending technology is based on using a self-destructing disposable perforating tool which is run without a wireline. To accomplish this objective, the custom designed tool has three frangible components: 1) a logging device; 2) an on-board navigation system; and 3) friable perforating guns. The on-board navigation system reads the log signals and performs real-time processing of the depth data. Upon matching of the desired depth, the system issues a firing command to the friable perforating gun assembly. The latter simultaneously initiates the self-destruction of the tool. Thus, the tool is completely destroyed after perforating and the remaining debris fall to the bottom of the hole, where they could be left, flowed back to surface or removed during cleanup prior to tubing installation. The volume of debris is small and does not require drilling additional rat hole.

The delivery of the tool is achieved by either gravity free-falling in low-angle wells or by pumping it downhole during hydraulic fracturing or any other pumping operation in high-angle or horizontal wells. An important part of the overall design is the safety system built into the tool to make the system as safe as, or safer than currently used perforating practices.
Borehole and Invasion Effects of Formate-Based Mud Systems on LWD Density, Neutron, PE, and Gamma-ray Logs
Authors: Cooper P. , Galford J. , Goodyear G. , Moake G. L. , Truax J.
Published: October 2011

The popularity of formate-brine drilling muds continues to increase as a result of the benefits in the drilling and completion stages of well construction, as well as the lessened environmental impact when compared to some other muds. Growth in use of these muds has caused operators and service companies to re-examine environmental correction algorithms because of the substantial effects these mud systems can have on nuclear logs. In addition, because formate muds generally contain lower solids than conventional muds, they can be strongly invasive. Thus, the influence of formate muds on LWD logging measurements includes both borehole environmental effects to be corrected and formation invasion effects that affect log interpretation.

A combination of laboratory experiments and Monte Carlo simulations have been used to develop a better understanding of the influences formate muds have on LWD gamma-ray, density, PE, and neutron porosity logs. Several hundred lab experiments and numerical simulations have been conducted in this investigation to fully characterize LWD responses to formate muds for families of sensors comprising two collar sizes used in a large range of hole sizes. The results were used to develop borehole corrections for the nuclear logs.

Formate brines are formulated to achieve a desired fluid density by using a mixture of dissolved compounds: sodium, potassium, and cesium formate. In some instances, the mixture results in a fluid with a substantially lower-than-normal hydrogen index. The mud may also have a larger-than-normal potassium concentration. Because invasion consists of nearly the whole formate mud, correct log evaluation in porous, permeable formations requires interpretation techniques that are beyond the scope of customary borehole corrections. We have taken lab measurements to attempt to quantify the effect of this invasion on LWD tool responses.
Evaluation of the Clearwater Formation Caprock for a Proposed, Low Pressure, Steam-Assisted Gravity-Drainage Pilot Project in Northeast Alberta
Authors: Uwiera-Gartner M. M. , Carlson M. R. , Palmgren C. T.
Published: October 2011

In northeast Alberta, Canada, steam-assisted gravity-drainage (SAGD) is used to produce bitumen from the Athabasca oil sands. In some regions, bitumen resources are located within 100 m of the ground surface and have average caprock thicknesses of about 50 m. The caprock unit overlying the bitumen reservoir is comprised mainly of mudstones and shales from the Early Cretaceous, Wabiskaw Member and Clearwater Formation. These shales form a baffle, impeding vertical steam migration and confining the stress and strain fields developed during the SAGD process, which are crucial for maintaining caprock integrity at SAGD operations.

In May 2006, an unexpected, catastrophic failure of the caprock seal occurred at the Joslyn Creek SAGD project, resulting in a steam release, which caused considerable caprock and ground surface deformation. Because of this failure, the Alberta Energy Resources Conservation Board modified the existing application guidelines and directives to include an assessment of caprock integrity at the maximum operating pressure specified for the thermal project applications.

The authors recently completed a core based, caprock integrity assessment for a proposed, shallow, low pressure SAGD, pilot project in northeast Alberta. This paper describes the information reviewed, assessment method and results of this study. From this evaluation, information about the geomechanical characteristics, the potential for containing the induced stress and strain fields and the geologic risks associated with caprock integrity for the proposed pilot project were determined. An assessment of the underburden seal was also performed as this seal can influence caprock properties. Results of the underburden seal assessment are also presented.
Wettability Alteration in High Temperature and High Salinity Carbonate Reservoirs
Authors: Sharma Gaurav , Mohanty Kishore K.
Published: October 2011

The goal of this work is to change the wettability of a carbonate rock from mixed-wet towards water-wet at high temperature and high salinity. Three types of surfactants in dilute concentrations (<0.2 wt%) were used. Initial surfactant screening was done on the basis of aqueous stability at these harsh conditions. Contact angle experiments on aged calcite plates were done to narrow down the list of surfactants and spontaneous imbibition experiments were conducted on field cores for promising surfactants. Secondary waterflooding was conduceted in cores with and without the wettability altering surfactants. It was observed that barring a few surfactants, most were aqueous unstable by themselves at these harsh conditions. Dual surfactant systems, a mixture of a non-ionic and a cationic surfactant increased the aqueous stability. Some of the dual surfactant systems proved very good for wettability alteration and could recover 70-80% of OOIP during spontaneous imbibition. Secondary waterflooding with the wettability altering surfactant increased the oil recovery over the waterflooding without the surfactants (from 29% to 40% OOIP).
The World's Deepest Frac-Pack Completions Using a Single-Trip Multi-Zone System: A Gulf of Mexico Case Study in the Lower Tertiary Formation
Authors: Ogier K. Scott , Haddad Ziad , Moreira Oswaldo , de Moraes Flavio Dias , Shipley Jonathan
Published: October 2011

Single-trip multi-zone (STMZ) Frac-Pack completions can significantly reduce the time to complete wells with long productive intervals. This technique was used successfully in two Lower Tertiary completions in the deepwater Gulf of Mexico (GOM) Cascade/Chinook project in 2010 (26,000 ft TVD, 8900 ft water depth). With interval lengths exceeding 1,000 ft, reservoir pressures greater than 18,500 psi, and bottomhole temperatures higher than 250°F, these STMZ completions were the first of their kind.

With a STMZ completion, all completion intervals in a well are perforated at once. Then all the lower completion hardware (screens, sleeves, packers, etc.) is assembled and run in the well and the packers are set. Through the manipulation of sliding sleeves, each interval is individually opened and frac-packed sequentially from the bottom interval to the top. Before moving to the next interval, the sleeves are closed and pressure tested, providing isolation between the wellbore and the reservoir.

The steps are repeated until all the intervals are stimulated. The STMZ system saves a great deal of rig time over conventional stacked frac-pack systems by significantly reducing the number of trips in and out of the well with the work string.

This paper discusses the challenges, planning, execution, and results of these STMZ completions with a focus on the downhole completion hardware. Also discussed are some planned modifications to the system that will reduce risk and improve performance in the future.
Potential Pitfalls from Successful History-Match Simulation of a Long-Running Clearwater-FM SAGD Well Pair
Authors: Doan Q. , Ali S. M. , Doan M.
Published: October 2011

Canada's oil sands deposits in northern Alberta contain more than 1.35 trillion barrels (~215 billion m3) of bitumen. Such a large resource base, even allowing for (relatively) low recovery factors, still constitutes the world's second largest oil reserves (behind only Saudi Arabia's). In-situ recovery technologies for these deposits, in view of the extremely viscous bitumen typically existing in them, commonly require thermal heating and/or solvent dilution to mobilize the bitumen and enable it to be produced. Steam-Assisted Gravity Drainage (SAGD) and Ccyclic-Steam Stimulation (CSS) are currently two technologies accounting for the bulk of in-situ bitumen production in Canada.

This paper briefly reviews key developments of the SAGD process. It next analyzes the production performance of a long-running Clearwater-FM SAGD well pair, followed by the presentation of history-match simulation results for this SAGD well pair. Discussion of the results is given from the viewpoint of Level-I (matching rates, volumes, fluid ratios) and Level-II (matching steam chamber behaviour) history match. These results demonstrate clearly the challenges of history-match simulation for the SAGD process, as well as the utility (or lack of) of Level-I and Level-II matches. Discussion and conclusions are also offered of the potential pitfalls associated with interpretation of history-match simulation results for the SAGD process, and subsequent implications for SAGD reservoir management.
Particle Size Distribution-Engineered Cementing Approach Reduces Need for Polymeric Extenders in Haynesville Shale Horizontal Reach Wells
Authors: Williams H. , Khatri D. , Vaughan M. , Landry G. , Janner L. , Mutize B. , Herrera M.
Published: October 2011

Recently discovered Haynesville gas-shale trends have transformed the regional and global outlook for natural gas supply, but offer unique challenges to the operator and service company during mud removal, cementing, and completion operations. To counter these challenges, recent advances include improved drilling, centralization, mud-removal, cementing best practices and implementing a broad particle size distribution-engineered (PSDE) cement system for use in high temperature horizontal intervals reaching across high pressure, high temperature (HPHT) gas-shale trends. For PSDE cement systems, rheological properties are based on inter-particulate interactions to achieve the desired viscosity and not based on polymeric extenders/antisettling additives. Since PSDE fluids are not dependent on polymeric thermal thinning behavior, they demonstrate consistent rheological properties over a wide temperature range and are more suitable for placement in narrow annuli.

In this paper, Haynesville cement placement and extensive laboratory testing best practices will be discussed. Also, a case study will be presented that describes a typical and successful placement of PSDE cement fluid in the Haynesville shale at bottom hole circulating temperatures (BHCT) up to 182 °C [360 °F] and bottom hole pressures (BHP) up to 82.7 MPa [12,000 psi]. After successful job completion and time allowed for the cement to properly set, an annular seal pressure test was successfully completed, with minimal pressure bleed-off.

Since introduction in 2009, over 390 production jobs have been successfully cemented using the PSDE cement technology, with 99.5% placement success rate. Acquired well head pressures (WHP) were less than or equal to predicted WHP for most production jobs. PSDE Cement Technology has become a proven approach for cementing high-temperature, horizontal tight-gas shale environments in relatively narrow annuli where fluid stability and zonal isolation are needed during placement and subsequent hydraulic fracturing treatments. This approach has been applied to Haynesville and Eagleford shale horizontal reach production wells and is being investigated for use in other high temperature, high pressure applications.
Integrated Capacitance Resistive Model for Reservoir Characterization in Primary and Secondary Recovery
Authors: Nguyen Anh P. , Kim Jong S. , Lake Larry W. , Edgar Thomas F. , Haynes Byron
Published: October 2011

This paper presents a new procedure to obtain unique estimates of interwell connectivities, pore volume, and productivity index in primary and secondary recovery. This method approaches the problem by analytically integrating the simplified continuity material balance equation. The proposed procedure uses linear multivariate regression on rate, initial reservoir pressure and bottom hole pressure (BHP) data. The method quantifies compressible pore volume – the capacitance, productivity index (PI), and degree of communication between well pairs – the resistance to flow. Hence, it is called the integrated capacitance-resistive (ICR) model.

The ICR model fits cumulative production against rates, BHP, and cumulative water injected. For primary recovery, the model has been validated on synthetic field data generated by numerical simulator, covering the effects of initial oil saturation, heterogeneity, and number of wells. The model was also tested on a real field. For secondary recovery, the procedure was tested on synthetic fields with high permeability channels.

In all primary recovery synthetic fields tested, good fit and less than 13% error of estimated pore volume and PI were observed. Real field application also shows good agreement with geological knowledge. For waterflooded synthetic fields, the estimated parameters are consistent with the geology and the results obtained from the capacitance resistive model (CRM) fit. The confidence intervals of the parameters are narrow enough to conclude regression coefficients are statistically significant. Hence, the ICR model can be used to quickly estimate reservoir properties and infer interwell communication in primary and secondary recovery from available data with high confidence.

The ICR model is comparable to CRM in terms of number of inputs. Hence, both models can be used in large fields with hundreds of wells. However, the nature of the CRM's nonlinearity makes it difficult to establish confidence intervals of the model parameters and obtain a unique set of model parameters for a large number of wells. In the proposed method, a unique solution can always be obtained regardless of the number of parameters via linear regression. The simpler formulation of the ICR model would reduce the computation time and easily establish the confidence intervals of model parameters.
Modeling of Transport Phenomena and Multicomponent Sorption for Shale Gas and Coalbed Methane in an Unstructured Grid Simulator
Authors: Leahy-Dios Alana , Das Mita , Agarwal Anshul , Kaminsky Robert D.
Published: October 2011

Shale gas and coal bed methane (CBM) assets have become increasingly important over the last decade, and are expected to become major energy sources for the future generations. However, there are unanswered fundamental physics and transport questions for each of these resources. Various physics-based approaches have been proposed and implemented to understand and simulate the flow mechanisms. However, the connectivity of organic and mineral matter is not fully understood and thus the exact transport mechanism in shale gas is still uncertain. This in turn can significantly limit the quality of resource potential and production forecast estimates.

This work addresses the challenges for shale gas and CBM simulations and presents a coupled sorption-transport model for both assets, along with its implementation in an unstructured grid compositional simulator. The models presented have been designed to capture key physics while still being straightforward to apply. A model for handling multicomponent isotherms based on pure component data is described. Existing experimental data were fit with the model and the results are discussed. A general transport mechanism workflow, which can be applied to both shale gas and CBM, is proposed. Results and findings are provided for the overall proposed scheme from gas desorption in the organic matter to the different transport mechanism in the matrix and the fractures.
Improved Upscaling for Flow Simulation of Tight Gas Reservoir Models
Authors: Zhou Yijie , King Michael J
Published: October 2011

Tight gas and shale gas reservoirs provide almost half of the current U.S. domestic gas production, with significant projected increases in the next several decades. These reservoirs constitute an important play type, with opportunities for improved reservoir management in the optimization of depleted volumes as functions of well spacing and fractured well design. Reservoir simulation, together with detailed 3D geologic models, may be used for improved management, but only if the flow simulation through these models can capture the essential heterogeneity and 3D continuity of these intermittently connected rock packages. The current work will examine tight gas reservoirs, but we recognize that similar issues will arise in source rock plays.

The current approach has three key technical elements: (1) We explicitly preserve the local continuity of the reservoir sands in the geologic model through the design of the simulation grid. Each simulation cell is a 1×1×N amalgamation of the geologic scale corner point cells, where "N" will vary depending upon the local sand thickness. (2) We have developed a "Well Index" based upscaling, to determine the upscaled permeability and which preserves the local reservoir quality. It does not require knowledge of the well locations within the upscaled simulation model, but it will preserve the performance of these wells. (3) The heterogeneity within each sand is preserved through the use of transmissibility upscaling, which we show performs systematically better than the usual permeability upscaling. In combination, these three elements provide simulation results which are almost indistinguishable from the fine scale model. We also examine additional approximations in which we further coarsen the model areally, and reduce the simulation time further. We develop and demonstrate our calculations on a sector model taken from the center of a full field onshore U.S. tight gas reservoir. The results are then validated using the full field model.

Our approach differs from earlier studies which have attempted to preserve the global heterogeneity of the reservoir models though layer-based statistical calculations. Although these statistical approaches are superior to uniformly coarsened models, they are not as robust or as accurate as the current work constrained by local continuity. Our approach also differs in the use of accurate property upscaling techniques that simultaneously preserve the internal contrast of permeability within each sand, and the performance of wells within the model.
A Practical Approach to Determine Low-Resistivity Pay in Clastic Reservoirs
Authors: Chu Wei-Chun , Steckhan Jan
Published: October 2011

Low-resistivity pay (LRP) has been a challenging problem in formation evaluation for many years. This is because conventional petrophysical interpretations are unable to identify pay intervals in low-resistivity reservoirs. This paper lays out a robust workflow for identifying LRP in thinly laminated sands with silty and/or shaly layers.

The workflow is essentially a two-step process which integrates data from gas while drilling (GWD), conventional logs and nuclear magnetic resonance (NMR) logs which identify potential pay intervals for further examination using wireline formation tester (WFT). This approach allows one not only to identify pay intervals but also their phase and their flow characteristics without the need of a conventional drill-stem-test (DST).

It is common for LRP to have high water saturation (60-70%) computed by conventional petrophysical interpretation while producing sustained water-free oil for few years. A petrophysical study was undertaken to integrate core data analyses including conventional, NMR and mercury injection capillary pressure (MICP). Data from over 100 sidewall cores (SWC) were examined. This novel approach for estimating irreducible water saturation (Swi) was developed based on

A good relationship was recognized between Swi from capillary pressure data as compared to that estimated from NMR de-saturated core. A correlation was established between Swi of de-saturated core and T2, LM. A validation was performed for zones producing water-free oil to link between NMR-MICP core analysis and NMR logs, using the following two methods for estimating Swi from capillary pressure data that is computed with knowledge of the height above free water level (FWL), T2, LM of NMR logs using the correlation developed in Step 2.

The benefits of this methodology are that it improves decision in well completion, predicts well performance accurately and reduces uncertainty in reserve estimation. In addition, it allows the user not only to identify zones of pay that would have been missed using conventional analysis, but also to estimate FWL elevations with higher accuracy from a saturation height model (SHM). Saturation profiles derived by this approach and those ones modeled from saturation height equations based on MICP capillary pressure data can be fitted better due to substantial reduction in uncertainties of log derived saturation data. Consequently the initialization of in-place volumes for hydrocarbons will be enhanced.
Stress Shadowing and Microseismic Events: A Numerical Evaluation
Authors: Nagel Neal B. , Sanchez-Nagel Marisela
Published: October 2011

In horizontal well shale completions, multiple stages, each often with multiple clusters, are used to provide sufficient stimulated area to make an economic well. Each created hydraulic fracture alters the stress field around it. When hydraulic fractures are placed close enough together, the well-known stress shadow effect occurs in which subsequent fractures are affected by the stress field from the previous fractures. The effects include higher net pressures, smaller fracture widths and changes in the associated complexity of the stimulation. The level of microseismicity is also altered by stress shadow effects. For example, it is commonly seen that the number of microseismic events is significantly reduced from the toe to the heal of the well, where the first frac stage is conducted at the toe of the well.

In this paper, we present the results of a numerical evaluation of the effect of multiple hydraulic fractures on stress shadowing as a function of fracture spacing, shale rock mechanical properties, and the in-situ stress ratio. In addition, utilizing the inherent ability of discrete element models to evaluate shear and tensile failure along fracture surfaces, shear failure, as a proxy for microseismicity, is evaluated as a function of fracture-induced stress and stress shadowing. The results of the study provide a means to optimize shale completions by understanding the effect of stress ratio, rock mechanical parameters, and hydraulic fracture spacing on the stress shadow effect and the potential for changing fracture complexity.
Case Studies of an Innovative New Drilling Tool Using Rate of Penetration Modulation
Authors: Farley Steven Reid , Maranuk Christopher A. , Jasper Clint
Published: October 2011

Mud motors have been used for decades to help steer wells in a desired direction. They are typically oriented with a bent sub in the motor and are pointed in the planned direction to kick-off the well or drilling section. They use a combination of rotating and sliding to keep the well on target and, depending on various drilling and formation parameters, may need to slide the majority of the time to maintain hole projection. Sliding often creates issues with hole cleaning, ledging, and decreased rate of penetration (ROP). Rotary-steerable tools, on the other hand, continuously rotate in the hole eliminating many of the problems associated with an oriented positive displacement motor (PDM). A new system for wellbore directional control has been developed that uses a positive displacement motor and a bent sub to provide continuous rotation throughout the wellbore. This new system offers many advantages of a rotary-steerable system but also capitalizes on the proven technology of a positive displacement mud motor.

Steering is accomplished by managing the pressure fluctuations within the drillstring, creating slight oscillations in the flow rate through the mud motor. These controlled undulations in flow rate allow high-frequency variations in drilling parameters to steer the well in any targeted azimuth. If the planned objective cannot be achieved using ROP modulation in rotary mode, then the motor can still be oriented in the desired direction and slid, using the more conventional mud motor orienting technique.

This paper will review several operations where the new steering system was used to help drill the well. It will discuss the operational challenges of drilling the wells, as well as how the new system helped overcome those challenges.
History Matching with a Multiscale Parameterization Based on Grid Connectivity and Adaptive to Prior Information
Authors: Bhark Eric , Datta-Gupta Akhil , Jafarpour Behnam
Published: October 2011

We introduce a novel reservoir parameterization approach to mitigate the challenges associated with field-scale history matching. In this approach, the reservoir property field is mapped to and updated in a low-dimensional transform domain using a linear transformation basis. The transformation basis vectors are the eigenvectors of a Laplacian matrix that is constructed using grid connectivity information and the main features in a given prior model. Because the grid connectivity information is computed only within a small multi-point stencil, the Laplacian is always sparse and is amenable to efficient decomposition. The resulting basis functions are ordered from large to small scale and include prior-specific spatial features. Therefore, the variability in reservoir property distribution can be effectively represented by projecting the property field onto subspaces spanned by an increasing number of leading basis vectors, each incorporating additional heterogeneity features into the model description. This property lends itself to a multiscale history matching algorithm where basis elements are sequentially included to refine the heterogeneity characterization to a level of complexity supported by the resolution of data. While the method can benefit from prior information, in the extreme case where reliable prior knowledge is not available the transformation reduces to a discrete Fourier expansion with model-independent parameterization properties.

We present the derivation and theoretical justification of the proposed method and review its important properties for reservoir parameterization including efficient one-time construction of the basis prior to calibration, applicability to any grid geometry and strong compression performance. The multiscale history matching algorithm begins by updating the prior reservoir model using a parameterized multiplier field that is superimposed onto the grid and assigned an initial value of unity at each cell. The multiplier is sequentially refined from the coarse to finer scales during minimization of production data misfit. This method permits selective updating of heterogeneity at locations and levels of detail sensitive to the available data, otherwise leaving the prior model unchanged as desired. We successfully apply the parameterization approach to history match several reservoir models, including a field case, using an adaptive multiscale algorithm.
Coreflood Measurements of CO2 Trapping
Authors: El-Maghraby Rehab M. , Pentland Christopher H , Blunt Martin J.
Published: October 2011

We present a coreflood experiment that measures three properties that control the long-term fate of CO2 injected into the subsurface during carbon capture and storage (CCS): the residual saturation of CO2 after brine flooding as a function of initial saturation; the amount of CO2 that can dissolve in the brine; and the primary drainage capillary pressure. We employ a porous plate method to establish initial saturation, a stirred reactor ensures that the injected brine is pre-equilibrated with CO2 and we use isothermal de-pressurization to determine CO2 saturation. The fluid pressure was 9 MPa and the temperature varied between 33 and 70°C - the CO2 is in a super-critical (sc) phase at a temperature and pressure typical of likely storage aquifers with a density between 211 and 705 kgm−3. We find that significant quantities of the CO2 can be trapped, with residual saturations up to 35%; the variation of trapped saturation with initial saturation is accurately matched using the Spiteri et al. model (a quadratic function). We compare the results with experiments performed at similar conditions using decane as the non-wetting phase. More decane is trapped than CO2, suggesting that the CO2-brine systems are not completely water-wet.

We show that temperature (density) variation has no effect on the saturation of scCO2 that is residually trapped. The measured dissolution constant lies between 0.84 and 0.97 moles CO2/kg brine. The primary drainage capillary pressure is consistent with a strongly water-wet system and the same - to within experimental error - as that measured on an analogue decane-brine system.
Comparison of Oil Recovery by Low Salinity Waterflooding in Secondary and Tertiary Recovery Modes
Authors: Gamage Pubudu , Thyne Geoffrey
Published: October 2011

Oil recovery by low salinity waterflooding in secondary and tertiary modes was investigated in the present study. Cores from Berea outcrop sandstone and Minnelusa reservoir sandstone were used in the single phase and two phase experiments. Two types of Minnelusa crude oils were used in the two phase experiments. The single phase experiments provided the baseline for pH and pressure changes in the two phase experiments.

Set of experiments were performed by using low salinity brine for the tertiary waterflood recovery method where oil saturated cores were first flooded with high salinity brine to simulate the secondary recovery method. In the second set of experiments, oil saturated cores were directly flooded with the low salinity brine. Conductivity and pH analysis of effluent brines were performed in all the single phase and two phase experiments.

Increase in oil recovery with low salinity brine as the invading brine was observed in both secondary and tertiary modes (28% OOIP) with Berea sandstone. However, higher oil recoveries (5-8% OOIP) were observed when low salinity waterflooding was implemented as a secondary recovery method. Minnelusa reservoir cores had little to no response to low salinity brine when it was used as a tertiary recovery method. However, Minnelusa cores showed an increase in oil recovery (10-22 % OOIP) with both types of crude oils when it was used as a secondary recovery method. An increase in pH of the effluent brine was observed during the low salinity brine injection in both Minnelusa and Berea cores. However, magnitude of the pH increase was smaller with the Minnelusa cores compared to Berea cores.

The level of investigation into the mechanism of low salinity incremental production has sharply increased in the past two years. Most of the studies focus on core floods using the tertiary mode. Our work contributes systematic coupled secondary and tertiary mode experiments that offer an expanded dataset for all researchers to use in investigation of the mechanisms.
New Fracture Stimulation Designs and Completion Techniques Result in Better Performance of Shallow Chittim Ranch Wells
Authors: Pandey Vibhas J. , Agreda Aquiles J.
Published: October 2011

The Sacatosa Field in West Texas was discovered in 1956. Since then over 1500 wells have been drilled and completed in the main reservoir section known as the San Miguel 1. The San Miguel 1 is primarily a low permeability sandstone, with several shale layers dispersed throughout. Economic development of the field requires effective well stimulation and an active waterflood program to provide pressure maintenance. Unfortunately, the available injection water is of poor quality and can rapidly plug up pore throats with solids, resulting in significant near wellbore formation damage. When these factors are considered, hydraulic fracturing of both injector and producer wells is a viable option for improved long-term well performance. However, because of relatively shallow depths, traditional hydraulic fracturing practices can lead to a multiplane fracture system with a mix of horizontal and vertical components. A significant presence of horizontal fractures can be detrimental to fractured well performance because of their low fracture conductivities. In producer wells, this could impair production if the reservoir is laminated and has low vertical permeability. In injectors, water front movement and sweep efficiency would be greatly diminished.

This paper discusses the steps taken to plan and develop a strategy to place vertical fractures in shallow San Miguel 1 sands. These findings can easily be extended to similar shallow depth reservoirs worldwide. Some major modifications in completion design included changes in perforation strategy, redesign of the pump schedule and implementation of a staged stimulation. Fracturing treatments were pumped on a total of 26 injectors and 8 producers using a variety of methods, including Coiled Tubing fracturing. Post-fracture analysis suggests a strong vertical fracture component and analysis of injectivity tests shows fracture parameters in line with design objectives. At least a two-fold increase in production was observed in producers that were fracture stimulated using these techniques.
Kerogen Pore Size Distribution of Barnett Shale using DFT Analysis and Monte Carlo Simulations
Authors: Adesida Adelola G. , Akkutlu I. Yucel , Resasco Daniel E. , Rai Chandra S.
Published: October 2011

Porosity and permeability are fundamental properties of hydrocarbon reservoirs that are important to estimation of the original hydrocarbon in-place and the production rates. These petrophysical properties are often characterized by the pore size distribution. Scanning electron microscopy studies performed on organic-rich gas shale samples have provided two- and three-dimensional images of organic pores with maximum resolution of 4-5 nm. However these images also suggest that the some of the pores and the paths connecting the pores are even smaller. In this study a different set of experimental and computational procedures based on low-temperature gas adsorption measurements are used to provide information about the porous structure of kerogen. The experimental approach involved nitrogen adsorption on crushed Barnett shale samples with sizes less than 500 microns at 77°K. Following the measurements, BET, t-Plot and DFT analyses are carried out and statistical analyses were performed to determine the distribution and the effective pore size of each sample. Monte Carlo simulations are performed in the Gibbs ensemble to predict thermodynamic states of methane in model pores with the resulting effective sizes and to estimate the amounts of adsorbed and free gases under Barnett shale reservoir pressure and temperature. Analysis show that the average organic pore widths of the samples range between 5-7 nm. The amount of adsorbed gas in a pore of this size under reservoir pressure and temperature conditions constitutes about 25% of the total gas in-place. The work is important for reservoir characterization and engineering analysis of gas shales.
Steam Chamber Development In Diatomites: The Role of Microseismic Monitoring in identifying Conformance and Out-of-Zone Fracture Growth
Authors: Baig Adam M. , Urbancic Theodore I. , Seibel Margaret
Published: October 2011

The treatment of diatomite reservoirs with cyclic steam is intended to enhance the mobility of the oil in reservoir, thereby stimulating hydrocarbon production. With optimized array geometries, the advanced analysis of the microseismicity resulting from these treatments can yield much more information on these events, such as their failure mechanisms through the process of moment tensor inversion. When these mechanisms suggest that the strain induced by the events is occurring on natural or newly created fractures, their orientations may be gleaned from the moment tensor.

In this study, we monitor microseismic events observed during the injection and production stages of a ‘Huff and Puff’ steaming operation in a diatomite. Our focus is on analyzing the growth of two event clusters that occurred during production cycles after steaming. Since the events are located using three downhole, we can invert for the components of failure.

One cluster showed significant vertical growth and the mechanisms of the microseisms were consistent with dilatational opening of fractures, closures of the fractures, or double-couple (shear) events. While the trend of the cluster of events is reflected in the fracture orientations of some of the events, many of the events have fractures occurring at defined angles to the overall trend. This observation allowed us to infer that the stress regime under which most of the events were responding is dynamically changing as the strain induced by surrounding events evolves in the reservoir. The second grouping of events was spatially contained and consisted of inflationary or deflationary failure mechanisms, suggesting containment that reflects steam chamber development; further exemplified by the variability in fracture azimuths, suggesting that the local stress conditions played a more significant role in the observed failures.

Based on this study, we suggest that advanced microseismic analysis has the potential to outline when steam chamber development occurs within design specifications and when the regional/local stress conditions influence steam chamber development, such as observed in the example of poor containment. In both examples, the occurrence of events during production suggests that failures occur as a result primarily as a result of stress unloading and stress re-distribution locally.
Performance of a New 2.35-in. Wireline or Memory Quad Combo for Through-Bit or Small-Hole Logging
Authors: Truax Jerome , Galford Jim , Moake Gordon , Torres David , Cherry Ron , Mandal Batakrishna , Mishra Arabinda , San Martin Luis , Quintero Alberto
Published: October 2011

A new UltraSlim™ quad combo has been developed and deployed with log quality very comparable to that of larger tools. The suite of logging tools is backed up by a full complement of swivels, knuckles, flex joints, springs, weights, cable head, and latches adaptable to the situation. The string can be conveyed by wireline using conventional power and telemetry, either through-and-below drill pipe or in a conventional open-hole log run. The combo can also be run in the hole by slickline inside drill pipe, then pumped out and latched beneath the bit, using its downhole battery and memory.

The tool string has been logged successfully in more than twenty commercial operations in operator wells and two of Halliburton's test wells. The combo and its peripheral equipment have performed without incident. Some of these log runs were made back-to-back with standard-sized logging equipment for the purposes of certifying that the log quality is comparable. The string features an array induction log with number of coils and spacings identical to its larger siblings, array sonic with dual transmitters, deployable-pad density with PE and caliper, dual-spaced neutron, gamma ray, and borehole environmental measurements.

This paper describes the UltraSlim logging system and provides details of its reliability, repeatability, accuracy, and petrophysical performance in comparison to standard-size logging tools, by means of visual and statistical log analysis.
Laslau Mare Field, a Successful Case of Production Optimization in Brownfield Rehabilitation
Authors: Charry Lina , Blades Amanda , Strasser Ralf , Rotar Dumitru , Stancicu Sorin
Published: October 2011

Romgaz, the Romanian national gas company, and Schlumberger joined forces in 2003 through a 15-year collaborative agreement for the rehabilitation of the Laslau Mare gas field. One of the main focuses of the agreement is the acquisition of data in order to develop a deeper understanding of the field, and thereby optimize the field management plan. After a First Work Program campaign, executed in 2004—2005, field production was increased by 40%; the result of workover jobs performed and elimination of surface network bottlenecks.

In addition to a portfolio of rig workovers, the approved Work Program for 2009 included an aggressive and challenging campaign of rigless interventions to optimize and maintain field production. The total production from the field has increased by 17% as a result of this rigless campaign, which mainly comprises coiled tubing interventions for water unloading (identified by slick line fluid level measurements) and the verification of the mechanical status of all active wells in the field. An additional 6% production increment was achieved with optimization of well soaping schedules, which is the current continuous water lifting method in Laslau Mare field.

The encouraging results of the rigless campaign and the additionally achieved incremental production rate were realized by implementation of the production optimization workflow outlined in this paper. This workflow aims at close monitoring of individual wells, identification of production gaps and intervention opportunities. Finally, well candidates are selected based on economic analysis.

The success of the campaign is demonstrated by the production gains and the short payout times achieved. The entire rigless intervention program paid out in a couple of months.

This paper presents the optimization workflow, its implementation to select candidates for the rigless campaign and the production and economic results of the executed work in 2009.
Evaluation of the Effect of Low Salinity Waterflooding for 26 Fields in Wyoming
Authors: Thyne Geoffrey , Gamage Pubudu
Published: October 2011

This report evaluates the effectiveness of low-salinity waterflooding in the Minnelusa Formation in the Powder River Basin of Wyoming. The Minnelusa sandstone play constitutes a resource of over one-hundred fields with cumulative production of more than 600,000,000 barrels of oil. We conducted initial laboratory screening using Minnelusa oil and rock with synthetic brine, supplemented with geochemical models of low-salinity injection, to evaluate the potential for low-salinity waterflooding in this formation. The laboratory experiments showed little or no incremental recovery from low-salinity injection. Calculation and comparison of recovery factors for 51 Minnelusa reservoirs were used to further evaluate the effectiveness of low-salinity waterfloods at the field scale. There was no increase in recovery for fields that used low salinity injection (26) compared to fields with mixed or formation water injection (25). Since some Minnelusa fields have relatively fresh formation water, the amount of dilution was quantified using the salinity ratio (SR), defined as the ratio of salinity of injected water to salinity of formation water. This analysis showed that while some fields actually had little or any salinity reduction (13), the remaining fields with significant dilution (38) still showed no correlation between dilution and recovery factor. Since some postulated mechanisms involve change in wettability, injection of low-salinity water may produce later water breakthrough. Analysis of water breakthrough timing and watercut evolution for 23 fields found no significant difference between fields with low-salinity injection and mixed-water or saline injection.
Characterization of Microbial Diversity in Treated and Untreated Flowback Water Impoundments From Gas Fracturing Operations
Authors: Mohan Arvind Murali , Gregory Kelvin B. , Vidic Radisav D. , Miller Peter , Hammack Richarad W.
Published: October 2011

Operators in the Marcellus shale have a strong desire to recycle and reuse waters, particularly flowback for continued use. Recycling water provides many benefits, such as; reduced total water consumption, reduced community impact through decreased truck traffic, and energy savings through avoiding advanced water treatment technologies. With all of the benefits water recycling and reuse has presented, the practice also presents a new set of logistical challenges for the industry that demand an even greater understanding of the unique nature of flowback water.

Flowback water from the Marcellus shale often contains higher concentrations of total dissolved solids than traditional produced waters from drilling as well as some metals and hydrocarbons. When impounded prior to treatment and reuse, microbial populations arise and their activity changes the composition of the organic fractions, solubility of metals, and may result in aesthetic issues associated with the odors from gaseous sulfur and nitrogen compounds from microbial metabolism. In order to develop the type of sustainable process the industry, regulators and the communities desire, we characterized and enumerated microbial communities in treated and untreated flowback water impoundments from the Marcellus Shale to gain a comprehensive understanding of those microbial communities and how they are impacted by pre-treatment. We examined the communities at several depths in each impoundment using 16S rRNA gene clone libraries to enable description of the populations with species-level specificity. Results show that flowback water impoundments develop microbial populations that are distinctly different with pretreatment. Within each treated and untreated impoundment, the microbial communities also varied with depth. The treated impoundment was predominately enriched with bacteria closely related to known aerobic hydrocarbon degraders in the α-proteobacterial clade. Untreated impoundments were more diverse and featured populations most closely related to fermentative organisms, those associated with anaerobic sulfur cycling, hydrocarbon degradation and biogenic methane production. Quantification of 16S rRNA genes indicated higher biomass in the untreated impoundments as compared to the treated impoundment. This is the first study to characterize microbial communities in flowback water from the Marcellus shale. Specific knowledge of microbial populations that thrive in flowback water will help producers develop effective management strategies.