bluuebunny/crossref_metadata_2025 huggingface dataset:
Reservoir Modeling - Prudhoe Bay Sadlerochit
Authors: van Poollen H.K.
Published: December 2007

Introduction

The basic objective of this study was to evaluate the relative oil recovery potential of the Sadlerochit Reservoir at Prudhoe Bay under a number of different operating conditions. The reservoir was modeled in cross section, using a six-layered, two-dimensional, three-phase mathematical fluid-flow simulator. This work was preceded by a published volumetric study and other preceded by a published volumetric study and other independent, confidential studies based on proprietary information which were designed to proprietary information which were designed to develop the best basic data with which to describe initial reservoir geometry, volume, fluid and energy conditions.

BOUNDARY CONDITIONS

General boundary conditions were established such that the following basic cases could be evaluated and compared:Depletion drive with gas cap expansion and gas reinjection into the gas cap from the start of producing operations—no aquifer. producing operations—no aquifer.Depletion drive with gas cap expansion and gas reinjection, supplemented by a moderate-sized aquifer.Depletion drive with gas cap expansion, gas reinjection and a moderate-sized aquifer supplemented by water injection.All of the preceding cases were also considered with gas cap sales of 2 MMMSCF/D, and some cases with 3 MMMSCF/D, and 4 MMMSCF/D.Special cases, all with aquifer, water injection and gas cap sales, where certain operating limits were changed:Five well groups were recompleted and GOR limits increased to 25,000 SCF/STB on allwells after 13 years (GOR limit otherwise was 15,000 SCF/STB and WOR limit was3 STB/STB for all cases).Two more well groups were added near the gas-oil contact after 14.75 years to control the potential loss of oil into the gas cap.Five of the above special cases had gas sales delayed.A range of maximum sustained oil-producing rates of 1.2 MMSTB/D, 1.6 MMSTB/D and 1.8 MMSTB/D was set for most of the preceding cases. All runs were scheduled to produce at 0.6 MMSTB/D for the first 3 months, 1.4 MMSTB/D for the next 12 months, and then at one of the above maximum rates until the start of decline.
Fast and Robust Algorithm for Compositional Modeling: Part II - Two-Phase Flash Computations
Authors: Pan Huanquan , Firoozabadi Abbas
Published: December 2007

In Part I of our study, stability analysis testing in the reduced space was formulated and its robustness and efficiency in comparison to the conventional approach was explored. In this paper, we present formulations including: 1) direct solution of the non-linear equations, and 2) minimization of Gibbs free energy for two-phase flash computations in the reduced space. We use various algorithms including the successive substitution (SS), Newton's method, globally-convergent modifications of Newton's method (line searches and trust region), and the dominant eigenvalue method (DEM) for direct solution of the non-linear equations defining two-phase flash and the minimization of Gibbs free energy. We also suggest a criterion based on the tangent-plane-distance (TPD) for the initialization from the equilibrium ratios. The proposed criterion has a significant effect on reducing the number of iterations.

The results from various algorithms reveal that the direct solution of the non-linear equations in the reduced space combined with the use of the TPD criterion for initialization in the combined SS and Newton's method can make flash computations extremely efficient. The efficiency and robustness of flash computations in the critical region are especially remarkable.
Single-Well Waterflood Strategy for Accelerating Oil Recovery
Authors: Guerithault Raphael , Ehlig-Economides Christine A.
Published: December 2007

Conventional primary production addresses from 3% (expansion of undersaturated oil) to about 15% (solution drive) of the original oil in place. An active water or gas cap drive may boost recovery significantly under ideal conditions, but otherwise pressure maintenance via water or gas injection is required. Simulations over a wide range of reservoir and fluid properties demonstrate that waterflooding from the start of production and maintaining pressure via reinjection of produced water can yield a target of 50% recovery of the oil in place in less than 5 years. The proposed single well with laterally parallel segmented horizontal branches accommodates water injection in one branch and production from the other branch with a downhole separation and reinjection system designed to reinject all produced water for up to 90% water cut in the producing branch.

A simple procedure provides the optimal length of the laterals and the optimal separation between them to achieve the target recovery factor, given the reservoir and fluid properties. When closer spacing is needed to achieve sufficient pressure support for the producer or to ensure sufficient connectivity between the wells, longer laterals can be drilled to reach the same total in-place oil volume. The procedure uses previously established formulas for line drive waterflood performance adjusted for vertical to horizontal permeability anisotropy.

The single-well waterflood avoids the need to lift and reinject produced water and accelerates the pore volume throughput, thus enabling the constant oil production rate (and equal surface water injection rate) characteristic of p-mode production. Also, the resultant constant reservoir pressure provides steady state conditions in the surface facility, greatly reduced risk of reservoir compaction or subsidence, and virtually no impact on the surrounding reservoir. Viability of the economics is easily demonstrated with net present value computations.
Multilateral Waterflood Development of a Low-Permeability Carbonate Reservoir
Authors: Bigno Y. , Al-Bahry A. , Melanson D. D. , Al-Hasani S. , Senger J. Ch. , Henning R.
Published: December 2007

The Shuaiba limestone reservoir of the Saih Rawl field (Oman) is a nearly unfaulted, low-relief structure of large areal extent. Permeability is matrix-dominated and relatively low (1 to 10 mD). The reservoir contains approximately 90 106 m3 of light oil (35 API) in column heights of typically 15 to 30 m.

Economical production only started in the early 1990's, 20 years after field discovery, when horizontal well technology could be effectively introduced. Today, multi-lateral wells of up to 7 legs are used in a pattern water-flood development. Total open-hole lengths drilled in the reservoir have reached 11 km for a single well. To date, 166 km of producing and 107 km of injecting open-hole have been drilled, representing 167 horizontal legs, and yielding an oil production level of up to 9,000 m3/d (60,000 bbl/d). The original producer to injector leg spacing of 250 m has gradually been decreased to 60 m and still fits the economic criteria.

In 2000–2001, a field development review was carried out to identify further development opportunities, both for the short and long term. A series of new reservoir management tools were put in place to predict the response of the reservoir to various development options. A pilot area was defined in order to test these concepts and perform extensive data gathering. Finally, new lab and feasibility studies were initiated. As a result from this review, a portfolio of short and medium term activities was identified, including infill drilling to 40 m spacing, and drilling additional injection legs in existing injectors. Also, upsides for developing the flank areas of the field (sub-15 m oil columns) were identified. Later, fishbone legs drilling and reversing water injection into existing producers will be piloted, while sweep optimization methods such as water shut-off and re-stimulation are envisaged to target recovery factors in excess of 50%.
Use of Satellite Radar Images in Surveillance and Control of Two Giant Oilfields in California
Authors: Patzek Tad W. , Silin Dmitriy B. , Fielding Eric
Published: December 2007

A global analysis of the evolution of an entire giant oilfield is now feasible. The oilfield can be viewed as a single complex system consisting of reservoir rock and fluids, and coupled injectors and producers. The vertically averaged areal signatures of primary and waterflood projects in the field can be tracked in time as the displacement of ground surface above these projects. The Synthetic Aperture Radar interferograms (InSAR) from satellites are the enabling technology. In this paper, we add a new element to our multilevel, integrated surveillance and control system: time-lapse satellite InSAR images of the oilfield surface. In particular, we analyze ten differential InSAR images of the South/North Belridge and Lost Hills diatomite fields, CA, between 04/95 and 12/99. The images have been reprocessed and normalized to obtain the ground surface displacement rate. In return, we have been able to calculate section-bysection the net subsidence of ground surface over the entire field areas. The calculated subsidence volumes are thought to be close to the subsidence at the tops of the reservoirs. The images show that the rate of subsidence has decreased in some parts of Lost Hills and Belridge, while it increased in others. Using the production and injection data from the California Conservation Commission and Chevron, we have been able to demonstrate the remarkable behavior of both fields: (1) There is recirculation of injected water through the "tubes" of damaged soft rock that link injectors with producers, resulting in diminished pressure support from the waterfloods. (2) Consequently, despite more water injection, there is more subsidence in Sections 29, 34, and 33 in Belridge and in Sections 29, 4, 5, and 32 in Lost Hills. (3) As much of the injected water is recirculated, the rate of subsidence is proportional to water production rate. (4) Compaction remains an important mechanism of hydrocarbon production. (5) In addition to accelerated compaction in the densest and most advanced waterfloods, there is a sizable oil production response to water injection. Means of controlling and improving the existing waterfloods are discussed.
Numerical Simulation and Inversion of Pressure Data Acquired With Permanent Sensors
Authors: Alpak Faruk O. , Torres-Verdin Carlos , Sepehrnoori Kamy
Published: December 2007

We have developed a new axisymmetric solution for the numerical simulation of single-phase fluid flow in permeable media. In this new solution, the governing parabolic partial differential equation (PDE) is transformed into a linear operator problem that is subsequently solved with an Extended Krylov Subspace Method (EKSM). The algorithm yields solutions for pressure at a multitude of times with the same efficiency of that of a single-time solution. Extensive comparisons with analytical solutions show that our simulator yields pressure results with accuracies better than 1%, and favorably competes with commercial simulators in CPU execution times and memory efficiency. Examples of numerical simulation are considered for water injection and variable flow-rate problems. In both cases, we have focused our attention to the description of pressure data acquired with permanent sensors deployed in direct hydraulic contact with the producing formation.

The inverse problem considered in this paper consists of mapping time and space variations of pressure and flow rate into a local distribution of permeabilities. We solve this inverse problem by minimizing a cost function written as the sum of the square differences between the measured pressure data and the corresponding pressure data yielded by our Krylov subspace simulator. A nonlinear Gauss-Newton fixed-point iteration search is used to minimize the quadratic cost function. We also test a dual coarse- and fine-grid approach to accelerate the solution of the inverse problem. Examples of inversion are shown with noise-free and noisy data aimed at understanding the role played by the flow-rate function and the location, spacing, and number of permanent sensors into the accuracy and stability of the inverted permeability values.
Growing Injection Well Fractures and Their Impact on Waterflood Performance
Authors: Gadde Phani B. , Sharma Mukul M.
Published: December 2007

Most water injection wells in waterflooded reservoirs have fractures that grow with time. These fractures can have a significant impact on the reservoir performance (oil production rates, o/w ratio and ultimate recovery).

A single well model that predicts the length of injection well fractures by modeling fracture growth due to fracture face plugging and thermal stresses is coupled with a reservoir simulator to simulate injection wells that have fractures that dynamically grow with time. The relative importance of the injected water quality, formation permeability, injection rate and the temperature of injected water on the rate of fracture growth are demonstrated. The single well model accurately accounts for all the physics of fracture growth at the injector while the reservoir simulator accounts for the large-scale reservoir structure.

The presence of high conductivity fractures in the injectors affects the waterflood sweep efficiency. Results indicate that fracture orientation, rate of fracture growth, injection water quality and reservoir heterogeneity play an important role in determining the oil production rates and ultimate recovery. The results of the simulations can be used to set injection well pressures and rates, specify water quality and to select injection well patterns to maximize oil recovery.
Representation of Fault Zone Permeability in Reservoir Flow Models
Authors: Flodin E. A. , Aydin A. , Durlofsky L. J. , Yeten B.
Published: December 2007

Faults can act as fluid flow barriers, conduits, or barrier/conduit systems in reservoirs. Their accurate representation in reservoir flow simulations is essential if realistic predictions are to be attained. In this work we compute the effective flow characteristics of faults using fine-scale field-based data. The faults we focus on are in porous aeolian sandstone and were formed by shearing along pre-existing joint zones. To find the bulk flow characteristics of the fault zones, we develop a computationally efficient upscaling methodology that combines numerical flow modeling and power averaging. By analyzing faults with different slip magnitudes, we are able to produce a relationship between fault permeability and fault slip. Slip magnitude is one of the few fault parameters that can be measured remotely in the subsurface and we show how it can be used to estimate the variation in permeability along a fault. We present three different flow simulation scenarios using variable fault properties derived using our new procedure. For each scenario, we present a second fitunedfl case where we replace our variable fault-zone permeability by a fault with a constant permeability and width. In one case, we find no significant difference in flow response between the variable and constant permeability faults. The other two cases display differences, mostly with regard to breakthrough time and liquid production rates. Because the reservoir flows considered here are relatively simple, we postulate that the differences between the variable and constant permeability fault descriptions will become greater for more complex systems.
Water Infiltration in Fractured Systems: Experiments and Analytical Model
Authors: Rangel-German E. R. , Kovscek A. R.
Published: December 2007

Capillary imbibition is an important mechanism during water injection and aquifer influx in fractured porous media. Better understanding of matrix-fracture interaction and imbibition in general is needed to model effectively these processes. Using an X-ray computerized tomography (CT) scanner, and a novel, CT-compatible core holder, we performed a series of experiments to study air and oil expulsion from rock samples by capillary imbibition of water in a three-dimensional geometry. The air-water system is useful in that a relatively large number of experiments can be conducted to delineate physical processes. Different injection rates and fracture apertures were utilized. Two different fracture flow regimes were identified. The "filling-fracture" regime shows a plane source that grows in length due to relatively slow water flow through fractures. In the second, "instantly-filled fracture" regime, the time to fill the fracture is much less than the imbibition time. Here, imbibition performance scales as the square root of time. In the former regime, the mass of water imbibed scales linearly with time.

A new analytical model is proposed for filling fractures incorporating implicit matrix/fracture coupling. Good agreement is found between experiments and calculation. This analytic coupling was obtained by means of solving the saturation diffusion equation with the appropriate initial and boundary conditions. The solution provides the location of the wetting phase front in the fracture and the saturation distribution in the matrix. The solution is analogous to that obtained by Marx and Langenheim1 for the areal extent of an equivalent heated zone in thermal recovery methods. Analogous terms among flow and heat transfer in porous media were found and are also presented.
Uncertainty Assessment of Well Placement Optimization
Authors: Güyagüler Baris , Horne Roland N.
Published: December 2007

Determining the best location for new wells is a complex problem that depends on reservoir and fluid properties, well and surface equipment specifications, and economic criteria. Numerical simulation is often the most appropriate tool to evaluate the feasibility of well configurations. However, since the data used to establish numerical models have uncertainty, so do the model forecasts. The uncertainties in the model reflect themselves in uncertainties of the outcomes of well configuration decisions.

We never possess the true and deterministic information about the reservoir but we may have geostatistical realizations of the truth constructed from the information available. An approach that can translate the uncertainty in the data to uncertainty in the well placement decision in terms of monetary value was developed in this study. The uncertainties associated with well placement were addressed within the utility theory framework using numerical simulation as the evaluation tool. The methodology was evaluated using the PUNQ-S3 model, which is a standard test case that was based on a real field. Experiments were carried on 23 history-matched realizations and a truth case was also available. The results were verified by comparison to exhaustive simulations. Utility theory not only offered the framework to quantify the influence of uncertainties in the reservoir description in terms of monetary value but also provided the tools to quantify the otherwise arbitrary notion of the risk attitude of the decision maker. A Hybrid Genetic Algorithm (HGA) was used for optimization.

In addition a computationally cheaper alternative was also investigated. The well placement problem was formulated as the optimization of a random function. The GA was used as the optimization tool. Each time a well configuration was to be evaluated, a different realization of the reservoir properties was selected randomly from the set of realizations all of which honored the geologic and dynamic data available from the reservoir. Numerical simulation was then carried out with this randomly selected realization to calculate the objective function value. This approach had the potential to incorporate risk attitudes of the decision maker and was observed to be approximate but computationally feasible.
MPP Simulation of Complex Water Encroachment in a Large Carbonate Reservoir in Saudi Arabia
Authors: Pavlas Emmerick Joe
Published: December 2007

Reservoir simulation has entered a new era with the advent of massively parallel processing and its ability to handle millions of cells. In this study a simulation model was constructed from the geologic model without scale up, the resulting model having 1.38 million cells. The majority of effort was spent on reviewing geologic and engineering data. History match changes were made at the well level and interpolated in Kh and Kv arrays using a deterministic mapping routine. Despite the complexity and model size, a successful history match was achieved in 40 runs. The model has been very successful in identifying well locations for bypassed oil recovery.
A Full Field Simulation Model of the Minagish Oolite Reservoir in Kuwait
Authors: AL-Mutairi Saad , AL-Medhadi Fahad , AL-Ajmi Hamad , Meadows David , Oosthuizen Ulrich R
Published: December 2007

The Minagish Oolite is a thick undersaturated carbonate oil reservoir in the Minagish field in West Kuwait (Fig. 1) containing several billion STB. It is a mature but relatively undeveloped reservoir. Since discovery in 1959, it has produced 10% of its OOIP under a combination of natural depletion, gas re-injection and aquifer drive. Initial reservoir pressure had declined by about 450 psi prior to the Gulf war in 1990. The well blowouts following the war caused a significant pressure drop of another 700 psi. Following the blowout, plans were made to redevelop the West Kuwait fields and increase the production rate starting in 2001 and to sustain the plateau for at least 5 years. This strategy called for threefold increase in the production rate of Minagish Oolite reservoir. Since the existing well inventory and the loss of the gas re-injection facility could not sustain the desired plateau rate, additional field development was required.

To achieve the production target, a multidisciplinary team was formed to evaluate options. The recommended plan required the drilling of additional producers and installing a field-wide peripheral waterflood. The reservoir, however, presented a number of significant challenges to waterflooding, such as the presence of a substantial and not well defined tarmat near the oil/water contact, and uncertainties of lateral and vertical heterogeneities. In 1997 a full-field simulation model was developed, but this model didn't capture the water movement properly because of insufficient reservoir data at that time. As new core was obtained, a refined reservoir description was developed. Building on lessons learned from the previous full-field model and sector models, a new full-field model was developed which significantly improved well-by-well history matches. Although containing twice as many grid cells, the new model ran up to four times faster than the previous model by making use of the Analytical Aquifer option within the model, improved relative permeability curves and other model refinements.

This paper traces the history of the field and the systematic evolution of the development plan. The reservoir simulation efforts including modeling strategy, history matching events, prediction runs, future direction and challenges are also addressed.
Semi-Automatic History Matching Using the Pilot Point Method Including Time-Lapse Seismic Data
Authors: Arenas Eliana , Kruijsdijk Cor van , Oldenziel Tanja
Published: December 2007

In this paper, we evaluate the benefit of using time-lapse seismic in reservoir simulation and handle some of the associated challenges. The problem is tackled from a reservoir engineering perspective, focusing specifically on the use of time-lapse seismic in history matching. A semi-automatic history-matching procedure is presented that uses both production and time-lapse seismic data as conditioning data. The actual integration of the production and time-lapse seismic data is handled in the objective or misfit function, which expresses the misfit between modeled and observed reservoir behavior. The pilot point method was chosen to reduce the large history matching parameter space 1–5. The optimum permeability values at the pilot points were determined using the Levenberg-Marquardt optimization algorithm.

The semi-automated method is tested on a 2D synthetic reservoir. The results indicate that for a case with abundant production data, time-lapse seismic sometimes yields only minor improvements in the final history matched model. However, when production data is limited, time-lapse seismic improves the history-matched permeability fields considerably by correctly identifying and locating the major heterogeneities of the permeability field. In addition, the sensitivity studies show that if pilot points are located in or near heterogeneities, the automatic history-matching algorithm has a better chance of correctly locating the heterogeneities. Furthermore, a seismic noise sensitivity analysis shows that seismic noise impedes accurate determination of the history-matched parameters.

The results of this research demonstrate that a history-matching procedure including time-lapse seismic can improve reservoir characterization and modeling. It can be used as a reservoir management tool to optimize in-fill well locations, enhanced oil recovery projects, and economic evaluations. The semi-automated procedure allows engineers to work more efficiently with larger reservoir models and extensive dynamic conditioning data sets.
A Case Study Challenges the Myths of Horizontal Wells in High-Productivity Reservoirs
Authors: Dashti Q. , Ma E. D. , Kabir C. S.
Published: December 2007

Numerous case studies substantiate the merit of horizontal drilling, especially in coning situations. Nonetheless, the burning question remains: do horizontal wells assure performance optimization in all cases? This paper explores the effectiveness of horizontal wells in a high-permeability (kh > 3,000 md), high-anisotropy (kv/kh < 0.01) Burgan Third Middle Sand (3MS) reservoir in Kuwait. To do so we built a sector model containing 35 wells to match 50-year history in a strong edge-water-drive system. With the history-matched model, we examined performance of horizontal wells under various scenarios. These scenarios included reservoir and completion considerations, such tubing size, well length, and high-slant configuration. For comparison, we measured the performance of a horizontal well against its vertical counterpart in terms of water-breakthrough time, oil acceleration, and incremental recovery.

Results show that horizontal wells do not appear to offer any decisive advantage over their vertical counterparts in terms of breakthrough time and ultimate recovery. That is because unique reservoir characteristics, such as high-anisotropy (kv/kh) and low-length-to-thickness (L/h) ratios, coupled with high productivity index (PI), all contributed adversely to horizontal wells' performance when compared with vertical wells. Horizontal wells' PI may be higher but the vertical well is equal to the task of delivering desired oil rates, although with a somewhat larger drawdown. In essence, the primary constraint on well performance is the tubing size, not PI. Therefore, a well with large tubing will achieve optimal performance, regardless of its orientation in the 3MS reservoir.
Propellant-Assisted Perforating in High-Pressure and Temperature Wells at Campo Bosque in Northern Monagas State
Authors: Ramirez Javier , Barrera Jose , Romero Roberto , Figueroa Frank , Almanza Edgar , Folse Kent
Published: December 2007

The Pirital Field is located in the eastern basin of Venezuela and is characterized by large high-pressure/high-temperature (HP/HT) reservoirs. The geology is complex with heavy faulting, natural fracturing and high-formation dip angles. To optimize the evaluation of the new HP/HT reservoirs in the Bosque block, a development and delineation project team was assembled. To fully assess the potential of the HP/HT reservoirs, two exploratory wells were drilled (PIC-25 and PIC-26) to confirm the feasibility of drilling and completing these wells. The mission of the project team was to deliver prolific producers with optimum completion efficiency while minimizing environmental impact.

One of the most important tasks was the perforation planning to ensure adequate connectivity to the reservoir in order to successfully test and evaluate each respective horizon. Available petrophysical data indicated that the reservoirs under study were of low porosity (<5%) and permeability (<0.8 md) at a measured depth of 21,000 ft. Several perforating strategies were evaluated, and the final decision was to use propellant-assisted perforating in scenarios where conventional hydraulic fracturing was not in the evaluation plans.

This paper covers the methodology used to validate the application of propellant-assisted perforating in HP/HT wells. The perforation-gun assembly selection, along with the analysis of generated peak pressures from the propellant burn process, will be reviewed. The mechanical configuration, wire line design and benefits derived from propellants will be fully explained.

The results presented in the two case histories presented will show the benefits observed in the form of low completion skin factors. Propellant-assisted perforating has shown to be an effective method for achieving perforation breakdown when testing tight, HP/HT sandstone reservoirs.
Analysis and Prediction of Microseismicity Induced by Hydraulic Fracturing
Authors: Warpinski N. R. , Wolhart S. L. , Wright C. A.
Published: December 2007

This paper presents an analysis of the stress and pressure changes caused by hydraulic fractures and evaluates the likelihood and causes of microseismic activity in the vicinity of the fracture. Coupled with the formation stresses, pressure, and properties, the analysis predicts where microseisms should occur in relation to the fracture and makes possible accurate interpretation of the significance of the microseismic events. The most important factor controlling the seismically active zone is the coupling of the fracturing pressure into the formation. Thus, liquid saturated reservoirs experience much more widespread activity than gas reservoirs. The analysis also shows that the fracture tip induces large shear stresses that result in a local zone of instability. Such a zone is the primary reason that microseisms accurately map out the length and height of the fracture since considerable microseismic activity occurs around the tip as it propagates
Fluid Characterization for Placing an Effective Frac/Pack
Authors: Morales R. H. , Gadiyar B. R. , Bowman M. D. , Wallace C. , Norman W. D.
Published: December 2007

While fluid characteristics are vital for effective proppant placement during any fracturing treatment, they become even more critical for frac/packing high permeability formations. Fluid properties are also important for proper clean up and flowback after pumping. Properly designed fluids can minimize production skin. This paper addresses the selection of conventional guar fluids for frac/packing applications.

The discussion focuses on the shear versus viscosity behavior within the fracture before and after the onset of tip screen out. It also deals with the near-wellbore and fracture cool down caused by the injection of the cooler fluids that are pumped ahead of the frac/pack treatment. Shear rate and temperature are used to select the appropriate fluid. The paper presents criteria for estimation of breaker loading to assure post-treatment clean up.
Challenges in Designing the Worlds First 15,000 PSI Subsea Completion
Authors: Grant Dick , Sones Greg , Speegle Steve , Clark Terrell
Published: December 2007

This paper describes the challenges confronted and the solutions / conclusions drawn during the completion design and implementation phases of the Gyrfalcon Project, Green Canyon 20, Well #1.
Optimization of Acid Fracturing Program In the Khuff Gas Condensate Reservoir of South Ghawar Field Saudi Arabia by Managing Uncertainties Using State-of-the-Art Technology
Authors: Al-Qahtani Mohammed Y. , Rahim Zillur
Published: December 2007

The Khuff reservoir in South Ghawar, Saudi Arabia is a heterogeneous tight carbonate reservoir. Acid fracturing program has been initiated to enhance gas production from this reservoir to deliver 1.2 BSCFD of gas. The complex nature of the tectonic stresses, geomechanical properties, reservoir geology and quality, coupled with aerially varying fluid properties (H2S) have sometimes reached the limits of reservoir simulation and stimulation.

During the early stages of development, numerous diagnostic tests were conducted on every well before, during, and after fracture treatment. These tests include pre- and post-fracture pressure transient analysis, radioactive tracer or temperature log runs during mini and main fracture treatments, production tests, and production logging. Several acid fracturing fluids, such as, 28% HCl, emulsified 28% and 15% HCl, were applied to achieve optimum fracture length and conductivity, and avoid CO2 corrosion. Complete reservoir characterization, history matching of actual fracture treatment and production forecasts were performed for every well. The objective of these tests and detailed evaluation is to optimize future acid fracture design.

This paper presents in detail the integrated optimization process of acid fracturing in the Khuff reservoir. The paper demonstrates that early investment in technology, management of uncertainties, and state of the art reservoir and fracture modeling significantly improved the optimization process.

The paper presents detailed assessment of several key wells, comparison between various acid fracturing fluids and techniques, and calibration of results of the stress and fracture models. The paper also discusses the need and importance of some of the tests and the quality of the results that may be obtained from them.

Finally, the paper presents reservoir modeling and history matching of acid fracture treatment using state of the art coupled geomechanical single well simulation model. Predictions of acid fracture performance versus time under the Khuff abnormal stress conditions are presented.
Using Magnetic Resonance Logging to Evaluate Permeability of a Carbonate Reservoir Containing Highly Viscous Oil: A case Study
Authors: Hassan Medhat , Nour Mohamed , Zeidan Selim , Elsherif Ahmed
Published: December 2007

The study reservoir is the Thebes formation of early and middle Eocene age. It was recently discovered in the south Geisum area, Gulf of Suez. The rock formation was deposited in a shallow marine environment and is composed mainly of cherty limestone of complex nature.

In GB-1 well, we have carried out a formation evaluation program to appraise the Thebes discovery using traditional open hole logs in addition to the newly introduced technologies, the Nuclear Magnetic Resonance and the Dipole Sonic measurements.

Eventually, two intervals were perforated and tested. The DST gave a permeability of around 5 md and 70 md for the lower and upper zones respectively. The Magnetic Resonance calculated permeability was around 1 md and 4 md respectively. The produced oil was highly viscous. The Magnetic Resonance was reinterpreted to determine the effect of the highly viscous oil on the permeability calculation.

In field practice, a T2 cut-off of 100 msec is used for carbonate reservoirs. In general, the oil bulk relaxation falls in the free fluid area. However, for 28 cp oil viscosity, the bulk relaxation time for the oil is around 40 to 60 msec. This means that the oil signature is coming inside the bound fluid volume, although it should be free since we assume the rock is water wet.

The oil volume in the invaded zone was deducted from the bound fluid volume and then added to the free fluid volume. The Timur-Coates permeability equation was then used to re-calculate the formation permeability using the adjusted volumes of bound and free fluids, thus resulting in permeability corrected for the viscous oil effects. The recalculated permeability showed a good match with the permeability obtained from the drill stem test data.
Capillary Pressure Data from NMR Logs and Its Implications on Field Economics
Authors: Altunbay M. , Martain R. , Robinson M.
Published: December 2007

The analogous behaviors of capillary pressure and 1/T2 decay versus saturation data provide a methodology for deriving synthetic capillary pressure information directly from NMR logs even if core data are not available. Estimations of irreducible water saturation4 from NMR log-based synthetic capillary pressure profiles have numerous benefits. One benefit is the enhanced accuracy of permeability estimations by using synthetic bulk volume irreducible in the bound water model. Availability of synthetic bulk volume irreducible data from capillary pressure modeling eliminates the requirements for determining the T2cutoff time from core analysis data or assuming generally accepted constants for it (33 ms for clastics and 92 ms for carbonates). In addition to the bound water model, an alternative permeability profile can also be generated from Purcell's7 capillary pressure-permeability relation. Another benefit derived from a synthetic capillary pressure profile is the determination of Oil Water or Gas Water Contact (OWC, GWC) by simply converting the capillary pressure information to height above free water level. This information can also be compared with the Free Water Level (FWL) from formation test tools. The relative positions of FWL and OWC assist in inferring wettability14 and the degree of wettability magnitude for the subject reservoir.

Relative permeability estimations from synthetically created capillary pressure data provide an avenue to make the firstapproximation profiles of the effective permeability values to the phases contained in the pore space. Consequently, effective permeability profiles in conjunction with other petrophysical and fluid properties and the pressure information lead to the anticipated production rates and overall evaluation of the economic viability of a well(s) and field. Applications of the technique with inherent assumptions, limitations, and remedies for the limitations are reviewed and explained through a case study presented in this paper.
Array Induction Measurements in Complex Environments: A Comparison Between AIT and HDIL Responses
Authors: Gonfalini M. , Galli M. T.
Published: December 2007

With the recent introduction in the oil industry of multiple-frequency, multiple-coil Array Induction tools, the vertical resolution and range of resistivity measurements have been improved by the use of well site processing based on the Born approximation.

By using this technology, we can obtain several resistivity curves with different depths of investigation, and matched vertical resolution of 4, 2 or 1 ft., directly at the well site: this looks promising not only for obtaining true resistivity (Rt) measurements, both in low and high resistivity environments and even in the presence of thin beds, but also for improving the characterization of complex invasion profiles.

Nevertheless, with the experience developed in recent Array Induction acquisitions in many different operational environments, we are now aware of the fact that the quality of such measurements is strongly affected by the presence of dipping beds and very high resistivity contrasts.

This reduction in quality is mainly related to the signal processing techniques used at the well site which can not be completely suitable for all geological environments.

This paper presents:

the results of a comparison among Array Induction acquisitions from wells with Oil Based Muds, by using both AIT and HDIL tools, in different geological environments;

the results of the quantitative evaluation of Water Saturation in the reservoirs.

All measurements were taken in clastic reservoirs in Italy.

The paper provides also some information about the available corrections that may be applied to the measurements, in a post-processing phase, to improve the quality of the petrophysical interpretation, and about the use of Resistivity Modeling techniques to better understand the physical behavior of the tool responses.

The conclusions achieved are aimed at optimizing the use of all available technologies in future operations in similar environments.
Field Applications of a New Nuclear Magnetic Resonance Fluid Characterization Method
Authors: Freedman R. , Heaton N. , Flaum M.
Published: December 2007

This paper discusses the application of a new magnetic resonance fluid (MRF) characterization method to field data acquired by a nuclear magnetic resonance (NMR) well logging tool. The theoretical and experimental foundation underlying the method was discussed in a paper presented at the 2000 SPE meeting.1 The MRF method provides a detailed formation evaluation of the near wellbore region investigated by modern NMR logging tools. This information includes total and bound-fluid porosities, hydrocarbon saturations, oil viscosities and hydrocarbon-corrected permeabilities.

In this paper we first provide a short review of the main ideas and key equations that make up the MRF method. We discuss the generalization of the MRF method to logging data acquired by the CMR* Combinable Magnetic Resonance tool and apply the method to mixture data acquired by a CMR tool on crude oil and water samples.

We also discuss the existing database of MRF results on partially saturated rocks, and present new laboratory results that include blind tests on Yates field dolomite rocks measured at initial and residual oil saturation.

The sources of uncertainty inherent in NMR diffusion-based viscosity estimation in reservoir rocks are discussed, and we propose a strategy that accounts for the uncertainties and provides "best estimates" of oil saturations and viscosities. The strategy is applied to the MRF analysis of the field data in this paper.

The MRF method is applied to CMR station log data acquired in three wells. Analysis of the MRF data and the results from each of these wells is discussed.
Field Experience with a New Carbon/Oxygen Logging System in Complex Wellbore and Formation Conditions
Authors: Simpson Gary A. , Truax Jerome A. , Younse Gary A.
Published: December 2007

Carbon/oxygen (C/O) tools have been designed for helping evaluate reservoirs under relatively simple conditions, such as cased wells with tubing removed and a single fluid present and reservoirs that have relatively high formation porosity. However, to reduce costs, tubing is often not pulled and wellbore conditioning is minimized. A new generation of small-diameter C/O tools capable of logging through-tubing has therefore been developed to deal with these circumstances. Logging through-tubing, despite its advantages, presents its own set of problems. Obtaining reliable measurements is often highly challenging because of different tubulars, various borehole fluids, and multiple contacts in a single well.

A new high-resolution C/O system has recently been developed for use under such complex conditions, specifically in tubing of 2⅞-in. and larger diameters with various fluids in the tubing/casing/formation. The tool has been run successfully in borehole conditions with wells flowing and shut-in. Sometimes the conditions included multiple wellbore contacts of gas, oil, and water within casing and multiple contacts in a tubing/casing annulus. Despite the various and changing borehole environments encountered by this tool, advanced electronics and detector designs, careful characterization, and comprehensive software have resulted in high-quality measurements.

This paper illustrates performance of the new C/O system under extremely inhospitable conditions in the Asia-Pacific area. Conditions include multiple contacts with water, oil, and gas in the borehole, as well as multiple contacts with water, oil, and gas in the tubing/casing annulus. Furthermore, reservoir porosity in the subject borehole was in the low range of 8 to 15%, where success with C/O logs has previously been minimal. Nevertheless, the tool obtained extremely useful data that provided an accurate assessment of the reservoir conditions, and thus allowed decisions to be made for secondary workovers and other reservoir product management remedies.
Real-Time Geological Positioning of a Well in the North Sea
Authors: Schroeder Tom , Boonen Paul , Illfelder Herb , McElhinney Graham , Templeton Gerhard
Published: December 2007

This paper describes the pre-job and real-time geological modeling of a horizontal well in a field in the North Sea. Using the PayZone Steering™ (PZS™) system, LWD gamma ray and resistivity data were used to continuously locate the wellbore in the geological section, modifying the geologic model in real-time as needed. Drilling was assisted by the real-time transmission and display of the LWD information, including downhole pressure and computed ECD, at multiple locations both onshore and offshore.

The well was planned to develop the Brent Sand by traversing two fault blocks, the second being downthrown and the primary target. The original geologic interpretation suggested major lithologic and stratigraphic differences between the two blocks. Therefore pre-job modeling was performed using three offset wells within the second fault block.

In the drilled well, the formation in the second block proved approximately 20 meters higher than expected as confirmed by comparison with the offset wells. Significant facies changes in the channel sands made detailed correlations with the offset wells difficult. Fortunately for concurrent detailed analysis, the geology in both blocks proved similar and the drilled well penetrated the target sand in both the upthrown and downthrown blocks. As a result, the LWD logs acquired in the first (upthrown) block provided the best correlations with the horizontal section, allowing for accurate determination of the well's geologic position.

The project team was thus able to successfully detect formation tops that were different from the modeled geology, continuously locate the position of the wellpath in the geologic section, and update the geologic model in a timely fashion. This information was then used to dynamically modify the drilling program.
Sensitivity Analysis of Horizontal Well Productivity under Steady-State Conditions
Authors: Shedid Shedid A. , Zekri Abdulrazag Y.
Published: December 2007

Many horizontal wells are being drilled all over the world to increase their productivity in comparison to that of vertical wells. Horizontal wells increase reservoir contact area and thus increase productivity. Therefore, it is essential to be able to predict the horizontal well productivity. The major objectives of this investigation are to: (1) develop a comprehensive evaluation of currently-used steady-state productivity equations of horizontal well, (2) investigate the effect of horizontal well length and pay zone thickness on the productivity ratio of horizontal well to vertical well, when both having the same drainage area and under identical flow conditions, and (3) study the influence of pressure drop on production rate of horizontal wells using different steady-state flow equations.

In this study, six different steady-state equations of the open-hole horizontal wells under identical conditions of flow parameters and reservoir geometry are subjected to a wide ranges of horizontal well lengths (100 to 3,000 ft), pay zone thickness (50 ft to 500 ft), and pressure drop (10 psi to 200 psi). These horizontal wells were used to calculate the productivity and to study the influences of flow rate and pressure drop on the sensitivity of these equations.

The obtained results showed that all steady-state equations provide similar horizontal well productivity for horizontal well length < 1000 ft, while a remarkable difference appears and increases when well length increases > 1,000 ft. In addition, the results using all steady-state equations confirmed the recommendation of the application of horizontal well for thin formations and do not recommend it in thick ones (h > 250 ft) for wells having identical rock and fluid properties. Comparing the performance of steady-state equations showed that all of these equations are sensitive to the increase of pressure drop, which yields an increase in flow rate of horizontal well. The results of this study have important implications in reservoir simulation studies, since it evaluates some important variables including pay zone thickness, well length, and pressure drop on the performance of each flow equation.