bluuebunny/crossref_metadata_2025 huggingface dataset:
Modeling and Operation of Oil Removal and Desalting Oilfield Brines With Modular Units
Authors: Barrufet M. , Burnett D. , Mareth B.
Published: December 2007

Oilfield brine is the largest volume of waste generated by the oil and gas industry; typical produced brine volumes may easily exceed the oil production by 10 times with total dissolved solids ranging from 1,000 to over 250,000 ppm. Handling costs of produced brine may lead to the premature abandonment of many oil and gas wells. At the same time that oil and gas operators are trying to cope with excess produced water, many states are critically short of freshwater resources.

This paper describes and validates a process to treat this brine to meet the standards for irrigation-quality water. Components of the proposed brine-conversion plant include both microfiltration and a pretreatment system for the removal of solid particles and oil using sorption pellets made of a modified clay material, and reverse osmosis (RO) units with a variety of interchangeable semipermeable membranes for the removal of dissolved salts.

We collected experimental data for oil/water separation of controlled mixtures using packed columns with modified clay particles. The average oil loading capacity of these particles is better than activated carbon (over 60%) and our experimental results indicate that packed beds can remove over 90% of the oil.

We screened a variety of RO membranes and selected one to conduct a series of experiments with brines with salinity up to 40,000 ppm, transmembrane pressures up to 1,000 psia, and various rates. Our experiments indicate salt rejections of 95 to 99% depending upon the initial salt concentration, transmembrane pressure, and rate.

Based upon these experiments, we modeled and coupled these two processes. Our model can scale up a process to any desired throughput rate and concentration specifications. Simulation results indicate that at proper integration and configuration of oil adsorption and RO units, depending upon initial total dissolved solids (TDS), up to 90% of the brine may be recovered as fresh water.
Technology and Methods Used To Reduce Water Production in the Lower Delaware Sands of Southeastern New Mexico and West Texas
Authors: Shahan T. , Briney M. , Reyes R. , Creel P. , Dalrymple D.
Published: December 2007

Producing hydrocarbons from the lower Delaware formation in SE New Mexico and West Texas is often associated with high water production. In the Matthews Field in West Texas (Reeves County), an operator was encountering water production of over 600 BWPD (bbl of water per day) from wells that had been treated. The stimulation techniques and processes were modified in an attempt to improve the production results. Multiple stage treatments using coiled tubing (CT) with selective placement controls and reduced rates were performed to lower the fracture height growth. This method included using conventional fracturing fluids, specialized coiled tubing perforating and controlled fracturing placement, and a relative permeability modifier (RPM) capable of reducing the potential for water production by coating the formation rock. This paper will detail how these operations were performed.
Treatment of Produced Water with an Ultrafiltration (UF) Membrane—A Field Trial
Authors: Lee J. M. , Frankiewicz T.
Published: December 2007

A hydrophilic ultra-filtration membrane was pilot tested for its ability to clean oilfield produced water over a four month period at a West Texas location.The UF membrane has a pore size of 0.01 microns and was operated in a cross flow mode to maintain surface cleanliness.The pilot skid included desanding and deoiling hydrocyclones as pretreatment devices.Process variables investigated included the permeate flow to reject flow ratio, membrane cleaning frequency, and the effect of feed water quality on membrane performance.Based on this test, design criteria were determined and operating costs estimated for a full scale facility.

The pilot skid routinely discharged permeate water with total oil and grease < 2 mg/liter.The effectiveness of pretreatment was essential to maintaining membrane permeability.During the test, the hydrocyclone's solid and oil removal efficiencies averaged 73% and 54% respectively.Emulsified oil droplets were found to be carrying 5-10 micron oil coated solids into the membrane unit.

Based upon this pilot test program, the operating cost for a full scale membrane unit, to produce 25,000 BPD of permeate water with < 2 mg/liter residual oil, is estimated at 9.7 cents/bbl.Overall water recovery would exceed 98%.The successful implementation of this technology is dependent on the water quality fed to the membrane unit.The preferred specifications for the UF membrane feed water are < 50 ppm oil and < 15 ppm solids.
Mechanistic Basis for Hysteresis in Multiphase Transport Properties
Authors: Gladkikh M. N. , Bryant S. L. , Herrick D. C.
Published: December 2007

Macroscopic properties of porous media containing two immiscible fluids, such as capillary pressure, relative permeabilities, and resistivity index, are fundamental to petroleum engineering. In this work we present a methodology for obtaining a priori understanding of hysteresis in these macroscopic properties. The approach is based on the mechanistic modeling of fluid displacement processes at the grain scale in a random dense packing of equal spheres. The method allows computing pore-level fluid configurations, which, in turn, allows direct calculation of macroscopic properties. Meniscus motion at the grain scale is entirely mechanistic, so any hysteresis that emerges does so exclusively from the interaction between the mechanics and the grain space geometry. Our model predicts that hysteresis during the fluid displacement cycle (drainage then imbibition of the wetting phase) has a significant effect on relative permeability and resistivity index. In particular, the usual assumption that the electrical parameter n in Archie's equation, determined by a drainage experiment, is equally applicable to imbibition is unwarranted. The results for electrical properties are also presented as electrical efficiency, which was developed specifically to account for the effects of pore-level geometry.

The predictions made in this work are compared with existing experimental data and found consistent with them. The methodology allows quantifying the influence of hysteresis in other conditions (consolidated rocks, varying wettability).
Sand-Arch Strength Under Fluid Flow with and without Capillary Pressure
Authors: Arii H. , Morita N. , Ito Y. , Takano E.
Published: December 2007

There are more than 15 sand control methods and one of the frequently used methods is the rate control method. There are mainly two cases where the rate control method can be applied: (1) permeability is significantly damaged around a well and the sand problem induced by erosion failure due to abnormally large drawdown can be controlled by the rate control method, and (2) the stability of a sand-arch built by disintegrated sand particles can be controlled by rate control. A series of laboratory tests were conducted in this work to measure the sand-arch strength using a polyaxial confining cell. The parameters changed in these experiments were the ratio of grain size to cavity diameter, grain distribution, cavity diameter, oil-water ratio, confining stress and directional stress. A similar experiment was previously conducted by the Colorado School of Minesand IKU, however, the tests conducted by the Colorado School of Mines used 20-40 mesh loose sands which are too coarse compared with actual reservoir sands, and IKU used air instead of liquid flow. Both of them used some immobile water saturation while the saturation change from 0 to 30% significantly reveals the complex phenomena of water effects upon sand-arch strength. The main objective of the laboratory tests was to separate the mechanical arch strength and the strength induced by the capillary pressure. It used a large grain size to observe large mechanical arch strength without capillary pressure effects andan intermediate grain size to observe capillary pressure effects. An analytical solution of a spherical cavity growth due to erosion of the post-failure zone is also developed to verify the observed phenomena in the laboratory tests.
Integration of Fracture Data into 3D Geomechanical Modeling To Enhance Fractured Reservoirs Characterization
Authors: Macé L. , Muron P. , Mallet J.-L.
Published: December 2007

Natural fractures have a dramatic impact on reservoirs in terms of oil recovery because they often control the hydraulic flow as conductors (open fractures) or barriers (sealed fractures). However, fracture parameters are poorly constrained by reservoir data, due to the low seismic resolution and to the clustering of 1D data along wells.

To enhance flow prediction, we suggest improving the characterization of Naturally Fractured Reservoirs by integrating well data with the history of stresses obtained by three-dimensional structural restoration (3D balanced unfolding). When unfolding a layer, boundary conditions are applied to mesh displacements to unfold the upper horizon and remove the latest brittle and ductile deformation increment. A linear isotropic elastic model governs restoration behavior, accounting for mechanical contrasts in the reservoir. Three-dimensional strains and stresses are derived from these displacements. Orientation of theoretical tectonic fractures is then geomechanically deduced from the principal strain directions.

Moreover, the orientations of fractures observed at wells (cores or image logs) provide implicit information on the principal directions of paleo-stress. Considering a given failure criterion, the observed fracture orientation is used to constrain the relative directions of paleo-stress components. Through this original approach, the 3D deformation is calibrated by observed geological data.

Therefore, the hybrid geometrical and geomechanical restoration that has been developed accounts for reservoir heterogeneities and is globally constrained by paleo-stresses deduced from fractures observed along wells.

This methodology is applied to a real reservoir located in North America and the strains predicted are used to generate 3D Discrete Fracture Networks. The key benefit of this approach, as compared to conventional methods, is to enhance fracture characterization by directly integrating observed fracture data into the geomechanical process.
Prediction of Well Performance Instability in Thin Layered Reservoirs
Authors: Belfroid S. P. C. , Sturm W. L. , Alberts G. J. N. , Peters M. C. A. M. , Schiferli W.
Published: December 2007

By using a full dynamic model for both the well and the near well reservoir, a large range of instabilities can be simulated. These instabilities include gas lift heading, severes slugging and compressibility effects. To simulate these types of fluctuations it is necessary to use an integrated dynamic model for the complete system. Using a constant productivity index to describe the inflow or using lift curves for the well are not sufficient to capture the dynamics. In this paper a well is described where reservoir-well interaction leads to unstable well behaviour. In order to investigate the cause for the unstable production a full dynamic model was developed for both the well and the near well reservoir. The simulation results are compared to field data of this well. The instabilities encountered at this well were explained by a combination of severe slugging in the well and the influence of the dynamics of the reservoir. The wellbore could act as a gas storage volume in which a pressure build up can take place. The well model used was a three phase dynamic models based of the drift flux formulation. For the reservoir basic single phase oil model was used to simulate a radial inflow. In the reservoir the compressibility of the oil is taken into account.
4D Monitoring of an Underground Gas Storage Case Using an Integrated History Matching Technique
Authors: Langlais V. , Mezghani M. , Lucet N. , Huguet F.
Published: December 2007

As time lapse seismic data are frequently available to guide the understanding of fluid flow behavior, a methodology has been developed to produce a fine scale geological model constrained by time dependent data, wells and 4D in a quantitative way. This enables us to keep the coarse model used in fluid flow simulations consistent with the fine scale geological model [1]. The objectives of this work are to validate the proposed methodology on a realistic synthetic case and to assess the impact of 4D in prediction improvements. Are we doing a better job by using 4D in history matching?

A synthetic reference case was derived from a Gaz de France gas storage site where gas injection and production are alternated over a 20-year period. Seven geological units showing various degrees of heterogeneities describe this full field dynamic model. A fine scale reference geological model was built (9.7 million cells), then upscaled and used in flow simulator. This model honored the observed static and dynamic well data (17 wells). Saturation maps from fluid flow simulation and a petro elastic model (PEM) were used to derive acoustic and elastic parameters. This reference data set will provide a point of comparison to assess and quantify the prediction performances as the time period is divided into history and prediction.

A workflow was developed to build a consistent fine scale geological model, a fluid flow model and seismic data using a PEM and accounting for the various scales. The forward modeling part of the workflow was used to compute simulated well data, impedances Ip, Is and time shift data. Then using an optimization loop, the models were constrained to observed well data and time lapse seismic data. The case study validates the methodology and shows an efficient way to include quantitatively 4D information while keeping consistency through the modeling chain. The model constrained by well data and 4D seismic data lead to more accurate predictions than the model constrained by well data only.
Bean-up Guidelines for Sand-Control Completions
Authors: Geilikman M. B. , Dria D. E. , Stewart D. R. , Wong G. K.
Published: December 2007

This paper presents a model that quantifies the production impairment caused by fines mobilization and induced by the transient gradient of pressure from the bean-up operations. Laboratory flow tests using field core samples and synthetic cores composed of different mixtures of sand and fines materials, all stressed under representative in-situ stress conditions were performed. They systematically assessed mechanisms of fines mobilization and amounts of permeability impairment as functions of different sizes of fines, amounts of fines, and flow velocities. Results of flow tests and transient gradient pressures generated by bean-up operations were combined to determine the additional production impairment or skin induced by flow velocity for the well. Application of this model allows engineers to calculate the well skin as a function of drawdown, total time of bean-up, time between choke changes, and number of steps or choke changes in the bean-up operations.

Application of this method provided some general qualitative bean-up recommendations (based on production impairment caused by fines mobilization): Bean-up with smaller incremental drawdown and shorter time between choke changes is preferred to bean-up with a higher drawdown but with a longer waiting time between choke changesContinuous bean-up is better than step-wise bean-upSkin inflicted by bean-up is more sensitive to a higher drawdown than to a shorter total bean-up time.Bean-ups with the same drawdown can be performed faster for reservoirs with higher diffusivity constant

The applied field example of a cased hole gravel pack well showed the bean-up inflicted skin ranged between 1 and 3 units. The effect of eliminating the transient gradient of pressure entirely only resulted in a reduction of 1 skin unit. Therefore, at least for this case, the impact of bean-up on production impairment based on fines mobilization was low. Other factors such as flow assurance; rock failures and sand production (and their impacts on sand control completion impairment and reliability) in the near well bore area may be more critical for optimizing the bean-up operations. Further studies in these areas are encouraged. Consideration of fines impairment for bean-up of sand control well is still warranted for formation sand with large amounts of "bad" fines and under low in-situ effective stress conditions.

This paper should be of interest to both the completion and production engineering communities.
The Key to Successfully Applying Today's Lost Circulation Solutions
Authors: Wang H. , Sweatman R. , Engelman B. , Deeg W. , Whitfill D.
Published: December 2007

Though strengthening boreholes with particulate treated mud has achieved tremendous success in the past year, the theory behind the process still has not been widely accepted. Rock mechanics analysis and laboratory data review are performed in this paper to illustrate deepened understanding on some key points that are controversial. Algorithms have been developed and demonstrated for obtaining critical parameters in designing such jobs for improving hoop stress, by which a wellbore can be strengthened while drilling.

Discussion of mechanisms and case histories has led to the development of systems that are designed to improve wellbore-pressure containment (WPC) by improving least principal stress. These systems are designed to function independent of formation permeability, unlike high fluid-loss and high solid-content squeeze pills. This method is normally applied when long fractures exist and when lost circulation has occurred.

Since the first approach is proactive and the latter remedial or corrective, combining the two approaches can create synergy for borehole strengthening.

A computer-aided design (CAD) process is also demonstrated for better use of available information in designing a deformable, viscous, and cohesive (DVC) system.
Semianalytical Stream-Function Solutions on Unstructured Grids for Flow in Heterogeneous Media
Authors: Hazlett R. D. , Babu D. K. , Lake L. W.
Published: December 2007

This paper outlines a Boundary Element Method (BEM) for a piece-wise analytic solution of the Laplace (Poisson) equation for pseudo-steady state, single phase flow on unstructured, rectangular grids.The method models flow through a reservoir that has been segmented into interacting homogeneous rectangular regions; no further discretization of the solution space analogous to grid refinement in numerical schemes is required for improved accuracy.Previous work on pressure distribution modeling is extended to analytically capture the stream-function.Stream-function solutions can then form the basis for other performance measures, such as improved oil recovery efficiency estimation or tracer flow analysis.Moving beyond structured grids into unstructured grid geometry allows for advanced flexibility in problem development and improved efficiency in solution construction.The analytic approach avoids the need for numerical differentiation of the pressure field and particle tracking methods to recover streamlines.Capturing flow around thin impermeable barriers, without local grid refinement, is demonstrated to showcase the robustness of the technique in handling complex reservoir architecture.
Implementation and Application of a Hybrid Multipoint Flux Approximation for Reservoir Simulation on Corner-Point Grids
Authors: Juanes R. , Kim J. , Matringe S. F. , Thomas L. K.
Published: December 2007

Accurate and robust discretization of the fluid flow equations is required to account for the extreme heterogeneity of oil and gas reservoirs, and the combined effect of anisotropy and grid distortion, necessary to adapt the grid to the geology. There is a growing need for handling distorted unstructured grids and full permeability tensors that appear after upscaling of the fine-scale permeability field. The classical cell-centered finite difference method results in a 7-point stencil and is insufficient to account for these effects. A number of closely related methods, coined as multipoint flux approximations (MPFA), have been proposed recently and are currently under active development. The basic principle of MPFA is that the flux across an interface between two gridblocks depends on the state variables (pressure and saturations) of more than two gridblocks. MPFA leads naturally to an enhanced finite volume method with a 27-point stencil.

In this paper, we implement a variant of the MPFA method for corner-point geometry hexahedral grids. Motivated by the very high aspect ratio of gridblocks in typical reservoir models (ratios as high as 100:1 are not uncommon), we propose a hybrid method that employs a multipoint flux approximation in the areal direction and a two-point flux approximation in the vertical direction. This restricted MPFA method leads to an 11-point stencil, therefore reducing the computational effort significantly. We discuss the implementation of the method in detail. We evaluate its performance on a number of test cases and show that, for typical applications, this simplification does not greatly compromise the accuracy of the solution.
What is the Characteristic Length Scale for Permeability? Direct Analysis From Microtomographic Data
Authors: Bauget F. , Arns C. H. , Saadatfar M. , Sheppard A. P. , Sok R. M. , Turner M. L. , Pinczewski W. V. , Knackstedt M. A.
Published: December 2007

Rock formation permeability is arguably the most important flow parameter associated with subsurface production and injection. Its importance is reflected by the number of techniques (well-log evaluation and correlation, core measurement and well testing) used to estimate it. Clearly permeability should be linked to other porous media properties (e.g., surface area, porosity, pore/grain size). There have been numerous attempts over the last sixty years to establish a relationship between the permeability of a rock and other characteristic rock properties. Most empirical approaches for the prediction of permeability, which has units of length squared, propose a function of a characteristic length scale, formation factor (tortuosity) and porosity. The most widely used is the Carmen-Kozeny equation where the length scale is equated to the hydraulic radius (pore volume / pore surface area). Other length scales used include a critical pore radius associated with mercury injection experiments (Katz-Thompson), lengths associated with NMR relaxation (e.g., T2) and grain size and rock fabric measures.

To uncover the relationship between permeability and other pore scale properties requires directly measuring the geometric and transport properties of the pore system. This is now possible with 3D microtomographic imaging (Knackstedt et.al. SPE 87009, Arns et.al. SPE 90368). In this paper we describe a comprehensive study of permeability correlation across a range of rock types. We directly compute permeability, formation factor, NMR response, hydraulic radius, rock fabric and texture, pore size and capillary pressure on 3D microtomographic images of 39 porous materials including over 30 clastic and carbonate samples from a wide range of reservoirs. Subsampling enables one to generate more than 6500 "independent" samples. Empirical correlations between permeability and various length scales are tested for a range of lithotypes including unconsolidated sands, homogeneous sands, consolidated reservoir sands, limestones and reservoir carbonates. We find that the most robust length scale correlation is based on the critical pore radius. All correlations which use the Formation factor as a measure of tortuosity give good predictions. Empirical correlations for permeability based on grain size perform well for permeabilities greater than one Darcy.
Deepwater Reservoir Modeling Using Sequence-Stratigraphic and Geomorphic Constraints
Authors: Pranter M. J. , Reza Z. A. , Weimer P.
Published: December 2007

In deepwater-reservoir modeling, it is important to properly represent the spatial distribution of architectural elements to account for pore-volume distribution and the connectivity of reservoir sand bodies. This is especially critical for rock and fluid-volume estimates, reservoir-performance predictions, and development-well planning.

This new integrated stochastic reservoir-modeling approach accounts for stratigraphic and geomorphic controls to generate the reservoir architecture. Information on stratal-package evolution and sediment provenance can be integrated into the reservoir-modeling process. A slope-area analytical approach is implemented to account for topographical constraints on channel and sheet-form reservoir architectures and their distribution. Inferred paleo-channel direction statistics (from outcrop and stratigraphic studies) and simulated high-frequency eustatic sea-level curves are also used to constrain the architectural-element statistics. Based on these geomorphic and sedimentological constraints, architectural elements (channels, lobes, sheets) are built into the model sequentially (in age order).

Integration of realistic geological and engineering attributes into numerical reservoir models is vital for optimal reservoir management. This approach is unique in that it is constrained more directly to geomorphic and sedimentological parameters than traditional object-based or surface-based techniques for stochastic deepwater reservoir modeling.
Insights into Deepwater Frac-Pack Completions Using Radioactive Tracers
Authors: Pourciau R. D. , Waltman R.
Published: December 2007

Frac packing has become the standard sand-control completion technique for many deepwater operators because of low completion failure rates[1] and excellent production performance.[2] These treatments are engineered to optimally place the stimulation fluids and proppants based on gravel- pack (GP) tool operational procedures and fracture model simulations.[3] Direct near-wellbore measurements from radioactive (RA) tracers can be used to help minimize both engineering and operational uncertainties of this process.

A comprehensive review of 30 Gulf of Mexico frac-pack completions within four deepwater fields has been completed, in which RA tracers have been used. These logs allowed initial assessment of the sand control and resulted in better frac-pack designs. The average perforation length of these 30 completions is 94- ft and the average deviation is 41°.Three of these wells have more than 200- ft of perforations and seven have over 60° of hole deviation.
Analysis of Long-Term Production Performance in Acid-Fractured Carbonate Wells
Authors: Rahim Z. , Ahmed M.
Published: December 2007

Gas condensate wells within the Khuff Carbonate formation in Saudi Arabia are typically acid fracture stimulated following drilling.Pressure transient tests conducted after stimulation indicate excellent fracture conductivity and reasonable lengths.After tie-in the wells experience some early production change, which stabilizes after three to five months. The producing bottomhole pressure of many such wells also reaches near or below the dew point pressure during this period.

This paper identifies some reasons of production and pressure behavior.Possible causes of early rate change followed by stabilization that include near well liquid drop-out, fracture conductivity deterioration with increased effective in-situ stresses, reservoir permeability loss also due to increased effective stresses and pressure drop, and non-Darcy flow were investigated.The paper presents the changing total skin with time and allocates it to each of the potential damage mechanisms.This was accomplished using a full geomechanics and reservoir simulation model, which treats multiphase flow effects and stress-dependent matrix permeability as well as fracture conductivity.By doing so, the production behavior was matched and the main controlling factors were identified.

The paper introduces a generalized skin factor equation combining all major variables controlling production, separate individual terms with respect to well rates, and identify the main mechanism impacting production behaviour.
Decline Curves from Deconvolution of Pressure and Flow-Rate Measurements for Production Optimization and Prediction
Authors: Kuchuk F. J. , Hollaender F. , Gok I. M. , Onur M.
Published: December 2007

In this work, we propose a methodology for monitoring well productivity index (PI), forecasting production, and estimating reserves using pressure and flow rate data. Within this context, we also provide a system identification technique by computing constant-pressure rate (deconvolved rate) behavior based on deconvolution of pressure and rate measurements. These measurements can be subsurface, surface, or a combination of both. As downhole permanent monitoring systems become more widely used, data quality, frequency, accuracy, and resolution will improve.

For system identification, deconvolved rate is compared with the exponential decline of the system under depletion as a base. Any deviation from the exponential decline may indicate nonlinearities about the system. With this step's input, a geologically based well/reservoir model is constructed for parameter estimation (e.g., reservoir size, pore volume, etc.) using pressure and/or flow-rate measurements. Any available pressure-transient-test data will also be considered.

The methodology proposed in this work can be integrated into data-acquisition softwares for permanent sensors, to provide a real-time monitoring/diagnosis tool for well performance and prediction. Furthermore, deconvolution results and estimated parameters can be verified continuously through a convolution of pressure and rate data, without interrupting production. It is, therefore, well suited for a single well or group of wells under extended testing, equipped with downhole gauges, and flowing through surface separation and metering systems. Wells completed with permanent downhole rate and pressure instrumentation are also ideal candidates for this type of analysis. Two field examples are presented to demonstrate the application of the methodology.
Impact of Formation Type on Cement Bond Logs
Authors: Vidick B. , Krummel K. , Kellingray D. S.
Published: December 2007

Frequently, poor cement logs are observed in low gamma ray formations (sand). Contrarily, very good bond is often noted across high gamma ray formations (shales). In some cases this has resulted in a squeeze decision where no injectivity can be obtained incurring significant costs and delayed oil. Most commonly the problem has been ascribed to an artifact of the logs, presence of mud cake, cement shrinkage and squeezing shales.

However after studying many such logs the first observation is the sharp contrast between the logs across shales and sands. This can occur over an interval of less than a meter. We have also noted that within the same interval in a low gamma ray formation, very good and poor bonds can coexist. It is also shown that the frequency of poor bonding across shale does show a dependence on depth. It was concluded that these observations imply that fluid influx could be partially responsible for the poor bonding and mud cake was not the sole explanation for the effect. This influx is different to conventional gas/fluid migration and is associated with fluid entry into the cement after the cement has reached a oint of being able to prevent migration. Deeper analysis and correlation with reservoir pressure support this hypothesis, explaining why the log is very good in some sand intervals and poor across others. It would also explain the sharp contrasts in the log, as it is postplacement related while all fluids in the annulus are under static conditions. The remaining contrasts could be explained by greater bulk shrinkage of the cement across shales than across sands and squeezing shales. The larger fluid loss would allow influx of oil from the sands during cement setting, contaminating the slurry and therefore inducing poor logs. The paper describes, supports, and explains those mechanisms in detail. The role played by the liner top packer is also considered.
A Method to Normalize Log Data by Calibration to Large-Scale Data Trends
Authors: Kane J. A. , Jennings J. W.
Published: December 2007

Wireline log data is subject to numerous potential errors due to the acquisition environment and assumptions made during acquisition.The literature sites log quality problems on the order of fifty percent of all well logs.The implication of this is that wireline log normalization is a critical step in obtaining meaningful log data for any reservoir characterization or modeling study.Often insufficient information is available to properly normalize logs using common or traditional methods.A new method is introduced in this paper that relies only on a sufficiently thick log interval to properly estimate the parameters needed for the normalization.Through the use of first vertical averaging of data by well to minimize localized reservoir variations, followed by areal averaging of multiple wells to estimate correction terms for tool calibration affects, a robust method of well log normalization is presented.An example using data from the Fullerton Clear Fork Field is presented to illustrate the method.
Case History: Designing and Implementing Wireline Tractor Operations for Deepwater, Extended-Reach, Sand-Control Initial Completions and Interventions
Authors: Whiteley D. , Pourciau R. , Schwanitz B.
Published: December 2007

Wireline tractoring technology has set world and Gulf of Mexico records for several logging applications during the initial completion and intervention of two extended-reach, deepwater frac pack wells and one extended-reach, deepwater water-injection well. This paper reviews some of the challenges involved with conventional conveyance methods in extended-reach wells, describes the planning process for wireline tractoring operations, including prejob modeling, and summarizes the results of a project.The authors will also share the lessons learned and best practices implemented. Proper utilization of this technology has led to significant cost savings for the example project.
Foamed Conventional Lightweight Cement Slurry for Ultralow Density and Low ECDs Solves Lost-Circulation Problem Across Coal Formations: A Case History
Authors: Marriott T. , Griffith J. , Fyten G. , Mallett C. , Szutiak G.
Published: December 2007

Cementing gas wells in coalbed methane (CBM) formations can present a cement-circulation challenge because the coal formations tend to have low fracture gradients and break down under the hydrostatic pressure of the cement column. The use of conventional lightweight cement slurries and/or foam cement significantly increases the prospect of maintaining circulation throughout cement placement. However, wells with exceedingly low fracture gradients can suffer either partial or complete loss of circulation during cement placement even with lightweight slurries.

Both conventional lightweight cement slurries and foam cements have restrictions. Conventional lightweight cement systems use low-density materials (i.e. hollow spheres, gilsonite) and high water-to-cement ratios as a means of reducing the equivalent circulating density (ECD). The lightweight materials and high water requirements detract from the compressive strength of the cement, thereby limiting ultra-low densities while achieving adequate compressive strength. For foamed cement, the gas-to-slurry ratio should stay within a specific range to help ensure optimal cement properties; otherwise, the set cement could become permeable. This requirement has led to the hybridization of two systems to create an effective cementing solution. By combining the two systems, the best attributes of both can be captured. Starting with a lightweight cement system provides a low base-slurry density that allows the gas to be added to lower the density further while maintaining the compressive strength and foam stability.

This paper discusses an operator's challenge and the use of the above solution to cement wells in the Western Canada Sedimentary Basin (WCSB) across CBM formations.
Injection Strategies for Foam Generation in Homogeneous and Layered Porous Media
Authors: Li Q. , Rossen W. R.
Published: December 2007

Foam generation plays a crucial role in the use of foam for improved oil recovery, acid diversion and environmental remediation.This sandpack study extends previous work to layered media, the effect of surfactant concentration, and injection strategy, including alternating-slug (SAG) injection and pulsed injection rate and pressure.As in earlier studies, three foam states were observed: high-mobility coarse foam at low pressure gradient, low-mobility strong foam at high pressure gradient, and, in between, an intermediate state with nearly complete gas plugging.

With co-injection of gas and liquid in homogeneous sandpacks, foam generation occurred at lower pressure gradient and lower gas velocity at higher liquid injection rates, higher permeability, and higher surfactant concentration. Within the plugged state, the pressure gradients required for foam propagation were remarkably high (of order 10 psi/ft) given the high permeability of the packs.

In flow from lower- to higher-permeability layers, foam generation occurred at lower pressure gradient than expected in either medium by itself. However, a minimum threshold pressure gradient for foam generation was still observed when the permeability contrast was of order 5:1, contradicting theory for foam generation at a sharp permeability transition. Foam generation was observed at all pressure gradients when the permeability contrast was 20:1. With co-injection of gas and liquid into layered packs, the low-mobility zone near the transition in permeability spread downstream if pressure gradient was sufficient.

During gas injection in SAG processes, a low-mobility front traveled the length of homogeneous packs and then exited. In heterogeneous packs, SAG injection gave persistent low mobility near the transition in permeability. Gas mobility in SAG processes was from 10 to 100 times higher than with co-injection of gas and liquid.

Briefly raising injection pressure in steady co-injection helped trigger foam generation in layered media, but had no lasting effect in homogeneous packs.

Foam was not uniform within packs, especially in the plugged state. Therefore, properties averaged over the pack do not represent a homogeneous state. Care is needed in using such data to fit mechanistic models for foam behavior.
10K Dual Splitter Wellheads: First Worldwide Application on the Development of an Offshore Gas Field
Authors: Faget J. B. , Monneyron J. C. , Bourgeois A. , Payer N. , Cherng L. H.
Published: December 2007

Splitter wellheads allow to drill several wells from the same conductor pipe, which can bring significant benefits for conventional offshore developments by reducing the size and/or number of new wellhead platforms or by giving access to additional reserves from available platform slots. In April 2003, Cameron 9" dual Conductor Sharing Wellheads (CSW) were successfully installed by Total E&P Indonésie on Peciko offshore gas field development as the first worldwide application in a 30" conductor pipe of a 9" × 10,000 psi dual splitter wellhead and 4-1/2" × 6,500 psi Xmas-Tree. As a result, 120 MUSD could be saved on surface facilities costs by reducing the total number of wellhead platforms from 10 to 7 while targeting the same gas reserves. Drilling and completion costs remained in line with initial budgets, as the higher costs of long departure wells induced by the reduced number of platforms were balanced by the savings made with the slimmed down well architectures.
Wettability Alteration ro Intermediate Gas-Wetting in Gas-Condensate Reservoirs at High Temperatures
Authors: Fahes M. , Firoozabadi A.
Published: December 2007

Wettability of two types of sandstone cores, Berea (permeability of the order of 600 md), and a reservoir rock (permeability of the order of 10 md), is altered from liquid-wetting to intermediate gas-wetting at a high temperature of 140°C. Previous work on wettability alteration to intermediate gas-wetting has been limited to 90°C. In this work, chemicals previously used at 90°C for wettability alteration are found to be ineffective at 140°C. A new chemical is used which alters wettability at high temperatures. The results show that: (1) wettability could be permanently altered from liquid-wetting to intermediate gas-wetting at high reservoir temperatures, (2) wettability alteration has a substantial effect on increasing liquid mobility at reservoir conditions, and (3) wettability alteration does not have a measurable effect on the absolute permeability of the rock when a suitable chemical is used. We also found out that the reservoir rock, unlike Berea is not strongly water-wet in the gas-water-rock system.
Smart Operations: Cutting Costs by Use of Simple Completion Solutions on the South Pars Field, Offshore I.R. Iran
Authors: Teigen A. S. , Johannessen B.
Published: December 2007

In this paper we will discuss optimization of completion solution in the South Pars field. By means of simplified completion methods, completion and testing time has been cut by more than 50% compared to the time spent on previous completions in the South Pars field.

We will discuss why we decided to change the "standard South Pars completion solution" commonly used by all other operators in the same field, and we will present the operational results from the first fourteen wells.
Analyses of the Accuracy and Reliability of Magnetic Directional Surveys
Authors: Nyrnes E. , Torkildsen T.
Published: December 2007

Multi-station processing techniques can be used to improve the accuracy of wellbore directional surveys by removing the effects of systematic errors. The main intention of this paper is to provide improved understanding and documentation of such methods when applied to magnetic surveys. Basic properties of the method are discussed in detail. The combined use of statistical tests and multi-station estimation techniques are evaluated, together with the ability to improve the accuracy of wellbore positions. This is demonstrated for a wide range of surveying conditions.

Due to a number of reasons; poor geometry, low redundancy, high random noise levels, the presence of gross errors, and errors in the Earth's gravity and magnetic field references, it is often possible that there will be a misinterpretation of the estimation results. This may lead to reduced accuracy and quality of the surveys. Even under the best possible conditions it is demonstrated that the processing of multiple surveys does not necessarily improve accuracy, rather it impairs accuracy and produce unreliable results.

The study also shows the importance of having a sound understanding of the simultaneous effects of potential uncorrected systematic effects, in order to increase the chance of making correct conclusions.
A New Approach to Modeling Hydraulic Fractures in Unconsolidated Sands
Authors: Zhai Z. , Sharma M. M.
Published: December 2007

Field data show that fracturing in poorly-consolidated rocks is not adequately represented by traditional models for brittle, linear-elastic rocks. This is not unexpected since unconsolidated sands do not exhibit brittle- elastic behavior. In addition, sands have very low tensile and shear strengths.

A model is presented for the propagation of "fractures" in unconsolidated sands. The model departs radically from current models in that brittle fracture mechanics is not used. Instead the propagation of pore pressure is computed and the porosity and permeability of the sand is specified as a function of the effective stress. This results in the creation of an anisotropic zone of increased porosity and permeability along the plane of maximum in-situ stress (normal faulting stress regime) or at a certain angle to it (strike slip faulting regime). This region of enhanced porosity defines a "fracture" in unconsolidated sands. The physics of creation and propagation of this oriented, high permeability zone, is modeled for the first time.

It is shown that in-situ stress anisotropy and shear failure play a very important role in determining the dimensions of this fracture zone. In addition, the permeability anisotropy generated due to the stress anisotropy in the sand is the critical driving force behind the creation of the oriented "fracture".

During the hydraulic fracturing of an unconsolidated formation, a high permeability zone (channel or fracture) will form in response to the difference in situ horizontal stresses and the decrease in the net effective stress near wellbore. To correctly model the fluid distribution, the fluid flow behavior must be coupled to the mechanical behavior of the sands. Based on the coupled geo-mechanics and reservoir simulation (model, iterative-coupled 2-D finite difference software is developed to simulate the strain, stress change due to the injection. Based on the constitutive relationship of permeability and porosity, we modeled permeability and porosity as a function of effective stress.
Interpretation of Distributed Temperature Data During Injection Period in Horizontal Wells
Authors: Gao G. , Jalali Y.
Published: December 2007

This paper presents an analytical solution describing the variation of temperature along the length of a horizontal well, given an initial reservoir temperature and injection fluid temperature at the heel of the well. The solution can account for the variation of the heel temperature over time (e.g., decreasing heel temperature with injection time, which happens when a ‘cold’ fluid is injected into the wellbore, causing cooling along the well column, and decreasing heel temperature). The solution can also account for an arbitrary distribution of injection profile along the length of the well. This includes injection profile that is uniform, or is skewed towards the heel or the toe, or exhibits some discontinuity (e.g., leakoff into a high-permeability streak or fracture).

The analytical solution is obtained from a theoretical treatment accounting for mass transfer from the wellbore into the reservoir, and heat transfer from the reservoir into the wellbore. The treatment is 1-D linear in the wellbore and 1-D radial in the reservoir. The solution is valid for ‘early-time’, that is, the period during which fluid propagation (mass transfer) is not affected by bed boundaries. This may represent a period of days to weeks.

The solution can be used to generate the temperature profile in a horizontal injection well, for any assumed distribution of injection profile along the length of the well. The solution can also be used in the opposite sense, to infer the injection profile based on the observed temperature profile. Temperature profile in the wellbore can be measured with fiber optic Distributed Temperature Sensors (DTS).

This paper presents the theory, the analytical solution, synthetic examples and a case study from a horizontal water injection well in the Middle East.