bluuebunny/crossref_metadata_2025 huggingface dataset:
Estimation of Aquifer Parameters Using the Numerical Inversion of Laplace Transform
Authors: El-Khatib Noaman A. F.
Published: December 2007

A new method is presented for the estimation of parameters for a circular aquifer by nonlinear regression analysis using numerical inversion of Laplace transform. The parameters estimated are the relative aquifer size ReD, the storativity hfCt and the transmissibility kh/μ. These parameters are necessary to calculate water influx needed in performance prediction of oil and/or gas reservoirs by material balance based methods.

Water influx data are fitted to the van-Everdingen and Hurst (VEH) unsteady state solution to obtain the required aquifer parameters by nonlinear regression analysis using the method of least squares. Because the solution in Laplace space is simpler than the solution in the real time domain, numerical inversion of Laplace transform was used to obtain the partial derivatives of the VEH solution with respect to aquifer parameters needed for least squares method. The Levenberg method was used for parameter estimation to guarantee convergence. This procedure proved to be efficient and free of computational and convergence problems encountered when using real time solution.

Two approaches are used to represent the variable pressure history: the step pressure SP and the linear pressure LP methods.The two approaches are used to generated water influx data and the values obtained by both methods are compared with the actual (assumed) data. The LP method is found to yield more accurate results and is used in the parameter estimation algorithm.

The developed algorithm can be applied for performance prediction of oil and gas reservoirs under water drive and for the simultaneous estimation of original hydrocarbons in place (OHIP) and aquifer parameters based on material balance equations.
The Coefficient of Isothermal Compressibility of Black Oils
Authors: Al-Marhoun Muhammad Ali
Published: December 2007

This paper presents a new correlation for the coefficient of isothermal compressibility of black oils at pressures above the bubble point. The correlation is expressed as an empirical function of oil relative density at bubble point pressure, reservoir temperature, bubble point pressure and the reservoir pressure. A total of 3412 data points from 186 laboratory PVT analyses from Middle East fields were used to develop the oil compressibility correlation. The data encompassed a wide range of gas-oil ratios, oil and gas relative densities, reservoir pressure, and reservoir temperature.

Multiple linear and nonlinear regressions were used to develop this model. This model is chosen from large number of models tested. The evaluation of the correlation includes comparative studies of the new and existing mathematical models of oil compressibility correlation.

The model is validated by using three different data sets from other geographical region of the world not used in the development of the model.

The newly developed mathematical model and correlation outperforms the existing mathematical models and correlations for oil compressibility based on low value of average absolute percent relative error and standard deviation.
A Probability Approach to Development of a Large Carbonate Reservoir with Natural Fractures and Stratiform Super-Permeabilities
Authors: Pham T. R. , Stenger B. A. , Al-Otaibi U. F. , Al-Afaleg N. I. , Al-Ali Z. A. , Sarda S.
Published: December 2007

This paper describes a development strategy with peripheral water flood for Haradh Arab-D reservoir, a large oil bearing carbonate part of the greater Ghawar field. In a heterogeneous matrix permeability background, geological discontinuities such as faults, fractures, and stratiform high permeability streaks lead to a decisional divergence between development options. In this regard, optimizing the field development plan aims to find a proper balance among several conflicting requirements.

In the case of Haradh Arab-D, the field development options are divided into two components. The first component is a development scheme that is the most cost effective with respect to production plateau, oil recovery and reservoir conformance. This option involves a multi-disciplinary team addressing the development challenges by extracting information from nearby development experience, quantifying uncertainty with deterministic and stochastic modeling techniques. An array of different reservoir simulation models (Single media full field model, Dual-porosity-permeability model, Local grid refinement model, and Streamline model) was used for the purpose (1). This results in a preliminary development plan with the application of the horizontal well options with respect to well placement, horizontal direction, completion interval selection and the length of the horizontal section.

The second component, the focus of this paper, is the sensitivity analysis and risk assessment running concurrently with reservoir simulation to develop a Pareto chart for different reservoir parameters such as Fracture density and connectivity, Super-permeability layers, Skin damage, Aquifer size, and Kv/Kh ratio. The most sensitive parameters with respect to oil recovery are identified for re-assessment and further improvement and optimization of the development plan. Data acquisition program, reservoir performance evaluation and production injection strategies are conducted with these sensitivities in mind. They are executed with the highest priorities given to the most sensitive parameters.

In order to ensure that the target objective is achievable, wells drilled during the initial development phase are tested to validate the development strategy. Monte Carlo simulations again are run on periodic basis with actual field data input to further optimize the development.
Identification of High Residual Gas Saturation Zone and Evaluation of its Impact on the Development of the Central-C Gas Condensate Field- Oman
Authors: Al-Kindi Azhar , Al-Shammakhi Khamis
Published: December 2007

The active government gas exploration programme in Oman has recently added another sizeable gas-condensate discovery that was drilled and tested by Central-C-1. Destined to unlock the first CA sandstone gas-condensate field, the well results indicated a very prolific reservoir.

In the process of data gathering, a number of challenging aspects were identified and assessed. Residual gas saturation is the most interesting and potentially high impacting aspect. This paper addresses variations on the gas saturation profile as calculated from the petrophysical logs, the identification from the special core analysis measurement of high residual gas saturation rocks, and all relevant findings inferred from the production testing and the static pressure gradient measurement.

Despite cautioned applicability of the SCAL measurement results to reservoir conditions, a potential evidence for part of the CA reservoir accommodating high residual gas saturation was recorded. Number of scenarios were modelled to assess the impact of high residual gas saturation in relation with other reservoir uncertainties normally associated with exploration reserve bookings.

These scenarios ultimately studied the impact of the residual gas saturation uncertainty on the development economics of the field. This paper explains why major economic measures, such as gas and the condensate recovery efficiencies, well placements and aquifer influx were seen sensitive to this uncertainty.

For a comprehensive evaluation of its impact, a relationship between rock properties distribution and residual gas saturation was invisaged as a comprehensive evaluation method. In a deeper concept this translates into a relationship between the interpreted original depositional model and the adopted charge model. This interesting relationship was evaluated in the simulator using a special saturation-porosity dependence that was primarily based on the SCAL measurements.

This paper details the analytical and the numerical approach used to evaluate the impact of the uncertainty in residual gas saturation. It highlights how this uncertainty features within the appraisal data gathering targets and within the surveillance strategy of this field.
Integrated Development Approach For A Mature Oil Field
Authors: Murty Challa R. K. , Al-Haddad Abdulla
Published: December 2007

Bahrain field, discovered in 1932, is a highly faulted asymmetrical anticline trending in North - South direction (Fig. 1). There are as many as seventeen oil producing and three gas producing reservoirs within Jurassic to upper Cretaceous formations apart from the Khuff gas zones below in Permian limestone formations (Fig-2). These reservoirs occur with divergent lithology, rock and fluid properties. Some of them are saturated while some are highly under saturated. Some of them are oil wet and some water wet. They operate under various drive mechanisms and pressure maintenance schemes. Gas injection in Mauddud, which is one of the major oil producing zones in Bahrain field, has been in operation for the last 65 years. Gas injection in Arab-D is in progress from 1986. Pilot peripheral water injection is in progress in wara sands in NE area of the field since 1995. Additionally, different production mechanisms like gas lift, pumping and stop cocking for GOR control is applied. The field being mature and structurally complicated naturally demands an integrated approach for effective reservoir management to ensure maximum recovery. Due to application of diverse reservoir management techniques, reservoir characterization, Geo statistical application for anisotropy and increased accuracy for simulation, the field has been producing with minimum annual decline (Fig-3). By integrating the Geological, Seismic and reservoir / production data the productive limits of various reservoirs have been extended adding substantial reserves. This paper briefly discusses the approach adopted in the effective reservoir management of this giant mature oil field.
Successful Use of a Cost-Effective Temporary Non damaging Gel Plug System to Isolate a Highly Permeable Producing Zone During a Stimulation Job of a Low-Permeability Gas-Producing Zone in Khuff Gas Reservoir in Bahrain — A Case History
Authors: Mirza Mohammed Saeed , Kritzler Torsten , Gazi Naz H.
Published: December 2007

In recent decades Bahrain has experienced a rapid growth in gas demand for industrial use, electricity generation, gas injection, and artificial lift. The main source of gas for these needs is the Khuff reservoir. The Khuff gas is currently being produced from 29 prolific gas wells.

To enhance the productivity of the Khuff reservoir a matrix acid stimulation program was undertaken using coiled tubing and a temporary non damaging gel plug system with complete regained permeability to isolate the high-permeability producing zone while the low-permeability gas-producing zone was being stimulated. Because the isolated zone is also producing, the gel system has to be completely non damaging with full regained permeability to this isolated formation.

The success of stimulating a low-permeability interval where a high-permeability producing zone is also present is primarily dependent on the ability to divert the respective stimulation fluid into the zone of lower permeability and productivity. Several methods are commonly used to divert the stimulating fluid in the non productive zone. These methods are dependent on the type of stimulation and configuration of the completion.

If coiled tubing is used for through-tubing stimulation in cased holes, inflatable packers are normally considered for isolation. However, inflatable packers have limited expansion ratios and pressure capabilities. The previous use of ball sealers gave very limited results of only 10% incremental gas production.

This paper will present the successful stimulation techniques and results of a unique and cost effective solution for a well where two intervals with different permeabilities were isolated without the high risks and costs of using a mechanical packer. Coiled tubing was used to stimulate the lower interval while the upper producing interval was isolated using a temporary chemical packer. Temperature in this well exceeded 270°F.
New Rigless Gaslift Application in Onshore Well
Authors: Abu Grain Hussain S. , Zabihi Mohammad , Al-Dusari Khalifa H. , Abbott James W.
Published: December 2007

In April 2002, the first retrievable straddle pack-off gas-lift assembly was installed in a Safaniya onshore well, which had been dead due to high water cut since 1993. This gas lift assembly has successfully increased the well production to an average daily liquid production rate of 2600 barrels with 30% water cut. The significant incremental production of 1800 BOPD is regularly contributing to company profit.

This paper discusses in detail the new gas lift equipment, principles of operation, installation, and trial test results. The assembly can be installed and retrieved with wireline, eliminating the need for a workover rig. It is equipped with gas lift mandrels to convert them to gas lift without pulling out the tubing. Based on its simplicity, successful operation, and considerable economical impact, there is a vast potential for this technology in Saudi Aramco.
Lessons Learned from the First Openhole Horizontal Well Water Shutoff Job Using Two New Polymer Systems - A Case History from Wafra Ratawi Field, Kuwait
Authors: Uddin Shahab , Dolan Jimmy D. , Chona Ricardo A. , Gazi Naz H. , Monteiro Ken , Al-Rubaiyea Jamal A. , Al-Sharqawi Anwar
Published: December 2007

With the introduction of water injection in the Wafra Ratawi Oolite reservoir, in the Partitioned Neutral Zone of Saudi Arabia and Kuwait, came the water production problems, especially after drilling horizontal wells. An economical method to reduce this unwanted water influx was needed.

The process was complicated in the horizontal openhole producing wells. Not only the water producing section of the part of the horizontal section has to be treated to reduce unwanted water production. A good, cost-effective method of temporarily protecting the producing horizontal section during this treatment was also needed to protect the potential oil-producing zone for future post-treatment production.

This requirement necessitated a good placement technique and the use of two gel systems, one to temporarily protect the oil zone and the other to permanently damage the water producing zone.

This paper describes the application and techniques of placing a nondamaging temporary gel system to isolate the oil-producing heel side of a horizontal section in an openhole horizontal well and the use of another organically crosslinked polymer system to shut off water from the toe side of this horizontal openhole wellbore.

A candidate openhole lateral horizontal well was selected for this application and the suspected high water cut from the toe side was caused by interference between a nearby injection well and this producing well.
A Feasibility Study of Mixing Disposal Water with Aquifer Water for Downhole Injection
Authors: Raju K. U. , Nasr-El-Din H. A. , Al-Shafai T. A.
Published: December 2007

Disposal of wastewater produced from various gas oil separation plants is a major concern for many oil companies. Mixing of wastewater with injection water has many economical and environmental advantages. The objective of the present study is to determine the feasibility of mixing produced water with the injection water obtained from a shallow aquifer.

Several samples were collected from disposal water and injection water locations. Measurements of hydrogen sulfide and total iron were conducted on site using standard techniques.

The concentration of H2S in disposal water was found to be in the range of 550 - 765 mg/L. The aquifer water contains 4 - 5 mg/L of total iron. Compatibility tests conducted in the lab and on-site showed the formation of iron sulfide. Acid solubility tests and XRD analysis confirms that this iron sulfide is present in a non-crystalline, acid-soluble form (amorphous).

The presence of iron sulfide in disposal waters is a major concern because it can cause formation damage and subsequent loss of well injectivity. Various chemicals were evaluated to mitigate the formation of iron sulfide. These chemicals ranged from formaldehyde, triazine, to tetrakis hydroxymethyl phosphonium sulfate, to oxidizers (sodium hypochlorite, hydrogen peroxide and sodium nitrite). Similarly, some iron chelating agents, such as citric acid, ethylenediamine tetraacetic acid, and nitrilotriacetic acid were evaluated.

This paper will discuss various types of H2S scavengers, reactions with H2S, advantages and disadvantages of each chemical based on extensive lab and field studies. Chelating agents for dissolved iron were also evaluated. Higher dosages of either sodium hypochlorite (hydrogen sulfide scavenger) or citric acid (iron sequestering agent) can mitigate the precipitation of iron sulfide species up to 15 vol% of disposal water in the mixture.
Sour Crude Production Practices in Inhabited Onshore Saudi Arabian Field
Authors: Al-Dejain A. A. , Al-Ghamdi A. A. , Zainalabedin Zainalabedin , Ahmad G.
Published: December 2007

Oil field operations involve a certain amount of risk. The risk factorincreases significantly when dealing with sour hydrocarbons due to the highlytoxic nature of hydrogen sulfide. This aspect takes a great deal of importancewhen large areas of such field are inhabited in addition to high populationdensity towns in very close proximity to the field.

This paper will address the challenges and safety concerns when developingsour crude oil fields in inhabited areas from production engineeringperspective. Application of proven technologies such as smokeless flare system, permanent downhole monitoring system, and remotely controlled wellheadequipment and data acquisition will be discussed. These systems can minimizethe impact of oil well clean-up operations on environment, frequent wellinterventions and well-site visits for safe operations in a field producingfrom reservoirs with relatively high hydrogen sulfide content in thehydrocarbons. Utilization of these systems will enhance the safety of oil fieldoperations as well as the inhabitants in the nearby areas.
Production Improvement by Controlling the Flow Regime of Gas Rich Fluid Mixtures with Slugging Devices
Authors: Ivannikov Vladimir I. , Ivannikov Ivan V. , Bakker Tom W.
Published: December 2007

Technology based on the use of slugging devices placed in the production tubing is presented. This technology significantly improves the performance of oil production from wells flowing at high Gas to Oil Ratio's (GOR's) and leads to better use of solution gas for the lifting process, lower waste of reservoir energy and lower production impairment due to free gas separation in the formation.

Due to this technology tests indicate that it is possible to typically increase daily oil production in high GOR wells some 20-30% and simultaneously reduce the utilization of gas by at least 1.5-2 times, depending on the particular well and reservoir conditions. As a consequence of better gas utilization for the liquid lifting process, a significant improvement of the ultimate oil recovery from a high GOR reservoir may be realized.

The technology also can be employed to improve the efficiency of gas lifting.
Applying Improved Recovery Processes and Effective Reservoir Management to Maximize Oil Recovery at Salt Creek
Authors: Genetti D. B. , Whitaker C. A. , Smith D. P. , Price L. M.
Published: December 2007

The Salt Creek Field, located approximately 110 miles northeast of Midland, TX, is a heterogeneous, Pennsylvanian-aged carbonate build-up in the Permian Basin. Successive implementation of infill drilling and improved recovery processes, coupled with effective reservoir management, have led to oil recovery of over 50 percent and expected ultimate recovery as high as 60 percent.

Salt Creek field was discovered in 1950 and a centerline water injection program began in 1953. A 40-acre development program was initiated in 1970 and was completed in 1984. The waterflood pattern was also changed from a centerline drive to a field wide inverted nine-spot. In 1985, a reservoir continuity study led to a 20-acre infill drilling program that added over 150 wells, changing the pattern to a five-spot. A miscible carbon dioxide (CO2) flood was initiated in 1993, and then expanded to the underlying residual oil zone.

Reservoir management has been a key element in maximizing recovery at Salt Creek. Consistent acquisition and maintenance of appropriate well and reservoir data has allowed detailed zonal tracking of production and injection volumes (CO2 and water). Geologic models, in combination with production logs and production data, have been used to manage and optimize CO2 and water injection at the flow unit level. Effective communication processes have been established between the field operators and the technical staff to calibrate engineering and geologic data with field experience and to enhance real-time decision making. A 3D seismic survey covering the entire field was acquired in 2000 to better define productive field limits and reservoir geometry. Currently, a study integrating engineering and geoscience data is underway to further improve reservoir characterization. The study is expected to result in improved sweep efficiency through better conformance control and additional drillwells to capture unswept reserves.
Low Salinity Oil Recovery – Log-Inject-Log
Authors: Webb K. J. , Black C. J. J. , Al-Ajeel H.
Published: December 2007

Many laboratory coreflood studies have shown increased oil recovery is achieved by waterflooding using low salinity water, compared with injection of seawater or high salinity produced water. The reasons for this improved oil recovery are thought to be due to effective wettability changes and / or controlled removal of clay constituents. This paper describes a log-inject-log field test, designed to identify whether this phenomenon could be observed within the near well region of a reservoir. The log-inject-log test was meticulously designed and executed, to ensure that flow rates were maintained at low rates, and that cross flow was minimised, to ensure that the results were representative of bulk reservoir waterflood displacement. A producing well was selected for the test to ensure that all saturation changes occurred under stringently controlled test conditions and that the results would not be affected by previous high rate water injection. 10 - 15 ‘pore volumes’ of high salinity brine, were injected into the ‘volume of interest’, to obtain a baseline residual oil saturation. This was followed by sequences of more dilute brine followed by high salinity brine for calibration purposes. Multiple log passes were conducted during injection of each brine. At least three further passes were run to ensure that a stable saturation value had been established after injection of each brine. Extensive water sampling was conducted to confirm brine salinities and increase confidence in the quantitative saturation results. The results were in line with previous laboratory tests from other fields, and showed 25 - 50% reduction in residual oil saturation when waterflooding with low salinity brine.
Managing the Challenges of Voidage in a Mature Carbonate Water Flood
Authors: Aihevba 'Leste O. , Al-Harthy Mohammed , Passmore John
Published: December 2007

Integrated field and well reviews followed by logical activities are being taken to address the voidage and declining pressure in Yibal. This is to ensure that target daily oil rates are achieved, and UR is maximized, in the largest oil producing asset in Oman, which delivers almost 15% of the total country production from a heavily faulted and fractured carbonate anticlinal structure, on stream since 1969. Water injection initiated in 1972 has gone through a series of stages; vertical oil phase injectors for lateral sweep, vertical aquifer injection for vertical sweep and later some horizontal deep aquifer injectors. The injection serves the dual purpose of pressure management and produced water disposal. The field has suffered negative voidage for quite some time, leading to rapid reservoir pressure depletion. Past studies have identified uneven vertical and lateral sweep due to uneven subsurface water distribution as a result of the complicated fracture and fault patterns as well as the subsurface hydro-dynamics and flow mechanisms. This has left the remaining oil in pockets that are becoming more difficult to produce. The high field average BSW has led to a situation where oil wells are closed in for surface facilities constraint and, or subsurface water injection capacity. Further, the uncertain water movement into producing wellbores makes production optimization activities risky. Recently, quite a number of injectors have been taken offline for integrity repairs and are only gradually coming back on stream after extensive and often expensive repairs.

The implementation of a voidage replacement program which includes understanding the reservoir dynamics, identification of the worst hit low pressure areas, and prioritization of the short, medium and long term remedial activities is on going. Increased focus on gross offtake management, injection well stimulation, water shut off in producers, conversion of poor producers to injectors, and drilling of new injectors is showing returns in flattening of the decline rate of oil production. The issues around water injection as well as oil producer integrity are gradually being addressed. Several learning points for the implementation of the proper reservoir and voidage management have also been captured. The importance of human resources both in terms of numbers, level of experience and skills set, has also been recognized and the optimum balance of these is being worked on.
Applications for a Full Wave Sonic LWD Tool in the Middle-East
Authors: El-Wazeer F. , El Farouk Omar , Deady Ron , Russell Richard
Published: December 2007

In recent years MWD/LWD formation evaluation applications have evolved to apoint where many applications usually reserved for wireline logging can now beattained from LWD data. The latest area is the applications attained from LWDsonic measurements. In a drilling environment a sonic tool has applicationsthat extend beyond standard porosity-type evaluations. MWD/LWD sonic logs canalso provide real-time seismic tie-in as well as assist in drillingoptimization. Conventional perceptions are that there are two key aspects thatcould minimize or preclude the use of sonic technology in an MWD/LWDenvironment. First, drilling noise is assumed to exist within the frequencyrange of the measurements, and minimization of it was considered impractical.Second, the interference of the tool-body mode (acoustic waves coupled to thereceivers as a result of tool body waves) is thought to be dominant, to theextent where significant manual post-processing is required to generatereasonable logs.

This paper presents some fundamental design choices and case histories fromthe Middle-East where a new Full-Wave Dual-Mode MWD/LWD sonic tool has recentlybeen run. The tool is constructed such that it operates in two modes (operatorselectable and available as either/or or both): (i) classical compressionalwave sonic tool (the equivalent to the traditional monopole source mode); (ii)enhanced shear-wave detection mode (dipole-type source). The tool has multipletransmitters and multiple receivers (arranged in a combination of arrays) thatallow operation in both modes. The tool utilizes a unique set of isolationsections that minimize the effects of drilling noise and tool-body mode. Thedesign of these isolation sections was based on extensive lab testing withscale models, as well as, the use of sophisticated 3-D analytical models. Thesestudies led to a comprehensive understanding of the dynamics of the tool bodymode and drilling noise and the best ways to reduce them. Implementation of thefinal design resulted in a negligible tool mode and nearly complete isolationfrom drillstring noise. The success of this design has been verified indrilling environments throughout the world where sonic LWD logs have beensuccessfully obtained in hole sizes from 30" down to 5 7/8".

Case histories will be presented from Abu Dhabi where the sonic LWD tool wasrecently run. The tools response in the varied formations of the Arabian Gulfand its application as a porosity device will be examined. Further applicationssuch as fracture detection will also be discussed.
Optimizing Petrophysics: The Ghawar Field, Saudi Arabia
Authors: Eyvazzadeh Ramsin Y. , Cheshire Stephen G. , Nasser Rami H. , Kersey David G.
Published: December 2007

Transformation of borehole logging measurements into accurate and precise porosity, lithology, permeability and fluid saturation data is the most important result of a petrophysical analysis.

A fundamental petrophysical problem is how to minimize systematic and random errors associated with data acquisition from different logging tools, variable borehole conditions and reservoir properties. Historically, errors were minimized by increasing the number of logs and/or calibration of results to core data. In the 1980's, a major development in petrophysics was the utilization of error minimizing routines to optimize the accuracy of petrophysical results. This optimization analysis combines input data with a set of response functions to find the best solution by minimizing the differences between predicted answers and actual inputs. Even though this technique appears to have technical advantages, acceptance has been limited due to underlying complex mathematics and consequently, the process is less understood.

A recent study was completed to determine the strengths and weaknesses of this type of analysis on Ghawar field, Saudi Arabia. Due to its vast areal extent, unique reservoir properties and extensive logging and core data, this field provided an ideal basis to evaluate optimizing analytical models. Data from several logging companies was used to show the combined effects of tool types and vintages, borehole conditions and reservoir properties on the utility of optimized petrophysical methods in Ghawar field.
Quantitative Characterization of Carbonate Pore Systems by Mercury- Injection Method and Image Analysis in a Homogeneous Reservoir
Authors: Beiranvand Bijan
Published: December 2007

The quantity of direct interest in the flow through porous media is not the properties of the matrix (e.g. grain size distribution) but rather the properties of the pore (e.g. pore size distribution). The determination of representative capillary pressures is of vital important for the mapping of the reservoir fluid distribution. Mercury porosimetry or mercury injection-capillary pressure curves are commonly used to measure the distribution of pores and pore throat sizes. Pore aperture size estimated from mercury injection tests has been used to categorize the rock by pore type, evaluate seals for traps and to explain the locations of stratigraphic hydrocarbon accumulations.

In image analysis, the OM (Optical Microscopy) images provide macroporosity information, whereas the ESEM (Environmental Scanning Electronic Microscopy) images yield information on microporosity. Comparison of total porosity determined from plugs indicates that macroporosity and microporosity values based on image analysis match the plug data, confirming the validity of the method. The combination of macroporosity and microporosity data yields pore size distribution and pore shape information that can explain the distribution of physical properties, in particular permeability. Permeability can mainly controlled by the macropore shape in high-permeability samples, and by the amount of intrinsic microporosity in the low permeability samples.

In this investigation three pore and port geometric systems have been recognized, 1) Type-1 system that belongs to mud dominated bioclastic peloidal packstone, at the top of reservoir, with good porosity and fair permeability shows large and smooth pores and ports as bimodal, 2) Type-2 system presented in mud dominated bioclastic peloidal packstone / grainstone with fair porosity and low permeability shows moderate to small pores and ports and 3) Type-3 system that has been seen in ploidal bioclastic grainstone and mud dominated planctonic foraminiferal packstone, packstone /wackestone and wackestone with low porosity and low permeability shows small pores and ports as matrix porosity.
Downhole Measurement of Methane Content and GOR in Formation Fluid Samples
Authors: Dong C. , Hegeman P. S. , Carnegie A. , Elshahawi H.
Published: December 2007

Formation fluid sampling early in the life of a well ensures that vital information is available for timely input to field planning decisions. For example, in subsea wells, flow assurance is a major concern, and formation fluid samples from openhole logging help operators optimize investment in both upstream and downstream facilities.

When a formation fluid sample is taken from a well drilled with Oil-Base Mud (OBM), the sample contamination by the OBM filtrate is a critical factor for the accurate measurement of the sample PVT properties. The Oil-Base Contamination Monitoring (OCM) technique uses optical means to monitor the buildup of both color and methane absorption signals during sampling. The technique provides real-time analysis of sample contamination. Methane detection is essential for condensates and for lightly colored crude oils; for such fluids, the color buildup becomes difficult to detect, but the high methane content of these fluids makes possible a reliable methane-based OCM algorithm.

Gas/Oil Ratio (GOR) is an important property of crude oil, which has profound value in the design of production facilities. Conventionally, GOR is measured at a PVT lab and may take many weeks before the lab can provide this critical information. In this paper, we describe the development of an in-situ GOR measurement technique, which uses the optical properties of methane and oil components in crude oil. With this technique, GOR can be measured downhole in real time, when the sample is taken and without requiring phase separation.

Downhole GOR has many advantages over the conventional wellsite GOR measurement techniques. It does not require tampering with the sample, which helps the operator maintain the fluid in a single-phase during and after sampling. It can also aid in fingerprinting oils from different layers and provides early indications of GOR that can be compared to PVT lab results.

Both the OCM and the GOR algorithms work well for most crude oils. However, for dark oils, the contamination prediction from methane component and the GOR prediction become unreliable because of the color effect. In this paper, we describe the methodology for downhole GOR measurement and we provide details of a decolorization technique which we have recently developed to remove the color effect of dark oils from the methane, oil and base channels in the LFA* Live Fluid Analyzer tool. This technique significantly improves real-time contamination monitoring and GOR prediction results for dark oils.
The Ec-Factor: A New Correlation for Optimizing Completion Efficiency
Authors: Al Qahtani Abdullah M. , Al Shehri Dhafer A.
Published: December 2007

The optimization of new wells completion designs will increasingly become a critical parameter for reducing development costs and maximizing wells potentials. This is particularly true as more and more reservoirs become mature with their associated complications resulting from increased water cuts and aging facilities.

This paper presents a new method for optimizing the partial completion of oil wells. The optimization criterion is the minimization of well's combined skin due to the partial completion placement, the well deviation angle and the perforation skin effect. These skin components are different from the damage skin that may be negated through well stimulation. That's why the design of well partial completion is imperative.

This work develops and presents simplified correlations for the different skin components associated with partial reservoir completions. The models presented employ uniform and consistent dimensionless variables. This should make the models easier to understand and apply for quantifying the flow efficiency of perforated completions.

The efficiency of a partial completion design is represented here as the completion efficiency factor of a partially completed well, Ec.. This efficiency factor is introduced as an optimizing parameter that can be quantified easily using the newly developed correlations as it captures all parameters affecting partially completed wells for a quick and handy way for engineers for optimizing a well completion. For any reservoir and wellbore geometry, the optimum perforation length is determined for any combination of well and perforation design.
Getting Reliable On-Site H2S and CO2 Concentrations for Anti-Corrosion Measures in Gas Wells
Authors: Williams J. M.
Published: December 2007

This paper demonstrates the importance of valid on-site measurements of hydrogen sulphide (H2S) and carbon dioxide (CO2) in gas wells in relation to corrosion management, notably for the proper selection of tubular goods, where material choice can result in cost changes of millions of dollars.

The problems of loss of H2S during sample storage are well known, providing a strong justification for on-site measurements. This work has looked at the ways to measure and validate both H2S and CO2 on-site. Conflicting values recorded on-site confirm the difficulty of getting reliable H2S and CO2 measurements.

H2S measurements at three gas-condensate wells were made on bottom hole samples involving a special non-reactive wireline sampler service. The intention was to obtain more accurate reservoir concentrations by avoiding anticipated losses through reaction or absorption on the production tubing. However, comparative surface measurements on the separator gas stream gave higher concentrations in nearly all cases, and a thorough investigation of the data confirmed that the separator gas measurements, made using simple equipment, were significantly more reliable.

In addition to the measurements themselves, it is demonstrated that well history, well conditioning and producing interval must be taken into account when interpreting measurements. For example, one test measured H2S production only after an acid fracturing treatment, implying that the original formation fluid contained extremely low or possibly no H2S.

The paper makes recommendations for on-site measurements and their validation including the use of two independent methods for H2S determination.
Simulation of Gas Injection Processes Using Compositional and Multiple-Gas Black Oil Methods
Authors: Al-Awami Amal , Ponting Dave
Published: December 2007

Compositional models are commonly used to simulate recovery processes in which injection gas and reservoir gases have distinctly different properties. Such processes include vapourising miscible drives, condensing miscible drives and low-pressure air injection. Recovery is typically enhanced by changes in fluid properties and a reduction in interfacial tension, leading to a variation of the relative permeability endpoints. These changes are due to mass transfer, in particular the solution of intermediate hydrocarbon components in the oil. Extensions of the black oil model such as that due to Todd and Longstaff can also treat such processes, although the mechanisms considered are rather different – in particular the amount of inter-phase mixing which occurs.

In this paper we attempt to unify these two approaches. The traditional black oil model is extended to multiple gases and property data constructed which yields a measure of the surface tension after mass transfer. Once the surface tension is known, a common end-point shift treatment can be used in both compositional and extended black oil treatments.

Traditional black oil numerical methods based on saturation variables have problems in treating the effect of partial pressure on the amount of dissolved gas when the gas saturation is low. This may be overcome using mass-based variables, but these have typically been less efficient due to the addition of an extra volume balance equation. A reduced mass variable formulation is described which retains the efficiency of the saturation-based approach whilst being easy to generalize to multiple gas components.

The multiple gas black oil and full compositional methods are assessed on some generic examples of gas injection processes.
Application of Multiphase Pumps in a Remote Oil Field Onshore Abu Dhabi
Authors: Saadawi Hisham , Al Olama Sharif
Published: December 2007

A multiphase pump was recently commissioned in a satellite oil field onshore Abu Dhabi. The pump is used to boost the flow from a well, located in a remote desert location, to a crude oil gathering centre, which is located 27 km away.

This paper describes the multiphase pump installations and the unique features of these facilities. Pump specifications and key design considerations are discussed. The paper also addresses the project implementation strategy as well as early operating experience.
Gas Flow Simulation in Discrete Fracture Network Models
Authors: Basquet Rémy , Laurent Jeannin , Lange Arnaud , Bourbiaux Bernard , Sarda Sylvain
Published: December 2007

Advanced characterization methodologies are now able to provide realistic pictures of fracture networks. We recently developed a software to simulate the transient and pseudo-steady-state flows of a slightly compressible fluid in Discrete Fracture Network (DFN) models. This simulator is used to validate the fracture network geometry and to calibrate the hydraulic properties of the fractures via dynamic data obtained from flow meters, interference and well tests. This paper is dedicated to the extension of the methodology to gas cases, taking into account the high fluid compressibility and the non-Darcian effects near the well bore.

The main specific features of our simulator are described and illustrated through demonstrative examples. Our DFN simulation approach is based on an optimised explicit representation for both matrix and fracture media and a specific treatment for matrix-fracture and matrix-matrix exchanges. A pseudo-pressure function is included in the diffusivity equation to take into account highly compressible fluids. The hydrodynamic behaviour of gas fluid flow near the well bore is taken into account via a skin effect proportional to the flow-rate for both matrix-well and fracture-well transmissivities.

This innovative numerical simulator is validated against existing analytical solutions and compared with finite-volume solutions computed with a suitable grid. Then, for application purposes, a complex realistic case involving a multi-scale natural fracture network with small-scale fractures and major objects such as seismic and sub-seismic faults is presented. An interference test is simulated on a representative DFN model and on the equivalent dual-porosity model built thanks to up-scaling procedures. This up-scaled reservoir model is shown to remain consistent with the geological DFN model in terms of gas flow. This example illustrates the practical use of DFN models in our fractured reservoir modelling workflow.
Characterization of Conductive Faults and Fractures Responsible for Inter-reservoir Communication in the Shedgum Leak Area of the Giant Ghawar Field, Saudi Arabia
Authors: Al-Ghamdi Abdullah , BinAkresh Saud A. , Bubshait Saleh A.
Published: December 2007

Pressure Transient Analysis (PTA) was instrumental in identifying and quantifying conductive faults/fractures in the Shedgum leak area. The objective of this study1 is to conduct detailed and integrated pressure buildup analysis for 23 Shedgum producers located inside the leak area in order to accurately estimate important well/reservoir parameters. The ultimate goal was to detect and characterize dominant reservoir heterogeneities such as conductive faults/fractures that may constitute the conduits for vertical fluid flow and inter-reservoir communication.

Additionally, historical water production history inside and around the leak area was also examined in an attempt to provide comprehensive explanation of the water source and flow path. Based on the results of this study, it is believed that water was migrating vertically from lower reservoirs (mainly Hanifa) into Arab-D through conductive faults delineated inside the leak area. Once brought into Arab-D, water then moved laterally towards producing wells, hence, starting the anomalous water production.
Exact Solution and Typical Curve for Commingled Reservoir
Authors: Sun HeDong , Liu Lei , Lu YuanWei , Zhou Fangde
Published: December 2007

The max effective hole-diameter mathematical model describing flow of slightly compressible fluid through a commingled reservoir is solved rigorously with consideration of wellbore storage and different skin factors. The exact solutions for wellbore pressure and the production rate from layer j obtained for a well producing at a constant rate from a radial drainage area infinite and const pressure and no flow outer boundary condition are expressed in terms of ordinary Bessel functions. The numerical computation of these solutions is made by Crump numerical inversion method and the behavior of the systems is studied as a function of various reservoir parameters. The new model is compared with the real wellbore radii model. The new model is numerically stable when the skin is positive and negative. The real wellbore radii model is numerically stable when the skin is positive. Because the curves explicitly include skin factor and other reservoir parameters, the techniques is expected to be more accurate than the real wellbore radii model. The automatic history matching technique has made it possible to accurately determine individual layer properties and wellbore parameters.
Observed Fracturing in a Middle East Oil Well – A Combined Subsurface Study
Authors: Azer Samir , MacKenzie Alasdair , Thiebot Bertrand
Published: December 2007

The paper presents the results of an integrated study comprising different disciplines and scales (core, log and seismic). The study followed the drilling of a well through a Jurassic carbonate reservoir in a NE-SW direction, which was cored near the tip of a NW-SE striking fault. Core and FMI data show a number of open and closed fractures, all striking in a NW-SE direction, contrary to what was expected from the regional structural model.

The structure grew through the Mesozoic with NE-SW extension producing a set of NW-SE striking normal faults and related fractures. A pulse of growth occurred during the Late Cretaceous-Tertiary, followed by continued Tertiary growth. 3D seismic data clearly shows the Lower Cretaceous fault pattern. The faults decrease in throw with depth, and only a limited number cut the Jurassic.

Interference tests show a preferential NE-SW communication pathway between wells. In addition, borehole and core data from other wells show open fractures, which tend to have a NE-SW strike, and a second set of closed fractures orthogonal to these.

The following were concluded from a review of the data: Correlation between core goniometry and FMI image analysis is excellent.The well is located near the tip of a NW-SE striking fault, and is likely to be in the transfer zone between two faults.Two sets of fractures occur in the Jurassic. A fault related NW-SE striking set and a NNE-SSW striking set occurring further away from faults.Fractures occur as near vertical, broken non-mineralized, and completely healed; and tend to occur in swarms.Fractures in the reservoir are likely to provide additional permeability.To intersect the maximum number of open fractures in the Jurassic, wells should be horizontal and oriented WNW-ESE away from faults and NE-SW close to faults.