bluuebunny/crossref_metadata_2025 huggingface dataset:
Tractoring – A New Era in Horizontal Logging for Ghawar Field, Saudi Arabia
Authors: Al-Amer A. A. , Al-Dossary B. A. , Al-Furaidan Y. A. , Hashem M. K.
Published: December 2007

The number of horizontal wells is increasing dramatically in Ghawar Field, the largest onshore oil field in the world. Refer to Figure-1. The complexity of completions is also increasing. Horizontal wells and complex completions such as extended reach and multilaterals introduce challenges for conventional intervention techniques such as coiled tubing (CT) to convey diagnostic and surveillance tools to the bottom of these wells. One answer to this challenge is the intelligent deployment system known as wireline tractoring.

The wireline tractor provides a breakthrough in logging capability by being able to log successfully where conventional wireline and CT logging tools cannot go. This paper will highlight challenges and Saudi Aramco's experience in production logging extended reach (1.5 - 3 km) open hole horizontal wells using two different types of tractoring devices. The characteristics of the two tractors will be described and compared, and the benefits of applying this technology will be explained in detail. The paper will discuss the successful application of this technology and its comparative advantages, including reduced cost and enhanced operational safety. Discussion of the collaborative work among various Saudi Aramco organizations and service companies in deploying this technology will also be presented. This success story of using the wireline tractor to deploy production logging tools in Ghawar Field will illustrate Saudi Aramco determination to overcome challenges by applying the best available technology.
Inflatable Enables Successful Water Shut-Off in High Angle Wellbores in Ghawar Field
Authors: Al-Umran M. I. , Saudi M. M. , Al-Tameimi Y. M.
Published: December 2007

A major challenge in today's oil field industry is to minimize the amount of water produced. Fortunately, many strategies and solutions are currently available; some involve mechanical tools while others use chemicals to manage unwanted water production.

This paper describes the successful application of rigless water shut-off in highly deviated well bores using inflatable plugs set by coiled tubing and with cement placed on top to reduce excessive water production. This technique was successfully employed to reduce water production and revive dead wells in Hawiyah area of the Ghawar field.The primary focus of this paper is to highlight the challenges and share Saudi Aramco experience in performing cost-effective mechanical water isolation in highly deviated wells.It is critical that the nature of the water production problem be fully understood to achieve successful water isolation.

Horizontal or deviated wells might die or produce excessive water after initial completion or after a short period of production due to high water flow intervals. A rigless solution was successfully performed on three dead wells utilizing inflatable plugs.The plug was run in hole using coiled tubing and then was capped with cement.The jobs yielded excellent results in reducing water production and re-activating these wells.The payout period for each job was less than one day. Based on these results, many additional candidates are now being evaluated for possible application.The challenges and risks encountered in previous unsuccessful water isolation attempts included premature setting of the plug in tubing nipples, failure to disconnect from the CTU after setting, or the well remaining dead after the job.This paper describes how a fit-for-purpose solution was planned to overcome these challenges through careful collaboration with the service company to develop the optimum procedure for the job.Also described are the benefits that resulted from this process, including well intervention without pulling the completion, elimination of kill fluids to minimize formation damage, and workover rig cost savings.
Field Example of Capillary Pressure Effects on Wireline Formation Tester Measurements and OWC Estimation in a Mixed-Wettability Oil Reservoir
Authors: Pham T. R. , Al-Afaleg N. I. , Kelder O. , Al-Otaibi U. F. , Zeybek M.
Published: December 2007

This paper discusses a field example of capillary pressure effects on down hole formation tester pressure measurements and oil-water contact estimation. Capillary pressure effects are investigated as functions of mud invasion, mobile formationwater, and rock wettability. Specifically, the effects of mudfiltrate invasion on formation tester probe pressures are quantified in terms of the error margin on the oil-water contact estimate.

In the field example, a fluidpressure gradientof about .45psi/ft was established from the bottom to the top of the reservoir, which is indicative of a water bearing formation. On the other hand, bottom hole fluid samples with the Modular Formation Dynamics Tester (MDT™) showed a 100%oil recovery in shallow intervals, moderate oil-cut recovery in the intermediate intervals, and lowoil-cut recovery in the deep intervals.

The purpose of this paper is to use formation tester information from the field example well, offset delineation wells, and reservoir behavior information, to support and explain that the apparent gradient in this case is not a true representative of the fluid gradient in the reservoir, rather, it represents the water phase gradient created by filtrate invasion and mobile water. A simulation model was developed, based on reservoir properties and laboratory measured capillary pressures, to simulate the formation saturation as a function of mud filtrate invasion and mobile water. Log-derived water saturations were used as a guidance, and ultimately, the model was used to predict the apparent pressure readings by the formation tester.

Together with the understanding of reservoir behavior derived from the simulation model, field data from all delineation wells were used to define the effects of mud filtrate invasion on formation tester pressure measurements. Consequently, the error margin on the oil-water contact estimate is benchmarked. Based on the field evidence,the paper also discusses which methodology is most accurate to use in the oil-water contact delineation in the field area of interest.
Simultaneous Analysis of Total Alkalinity and Organic Acid in Oilfield Brine
Authors: Tomson M. B. , Kan A. T. , Fu G. , Wu X. , Al-Thubaiti M. , Kirk J. , Martin R. , Prukop G. , Inan E. Esra , Davis S. T.
Published: December 2007

Measurement of bicarbonate in produced waters is necessary to calculate thepH for corrosion estimation and for several types of scale predictions, carbonates, sulfides and oxides. Generally, bicarbonate is the predominantbuffer in produced salt water, yet it is difficult to measure accuratelybecause of gas/solution and solution/solid exchange. When sulfides and weakcarboxylic acid buffers, such as formic, acetic, and propionic acids are alsopresent, the problem is complicated both experimentally and theoretically. Wehave recently developed a rigorous theoretical solution of this problem andproposed a corresponding experimental method to accurately measure bothbicarbonate and weak acids simultaneously with minimal experimental difficultyand costly instrumentation. In addition, the sample becomes its own standard.Practically, the method requires a new software package, written in Excel, todo the calculations. After extensive testing using synthetic brines of our ownand field brines supplied by several companies, a series of blind round-robintests have been conducted using only field brines. Several production andservice companies in our Brine Chemistry Consortium have participated in theround-robin testing. In order to estimate accuracy we analyzed the brines usingseveral methods. The precision and accuracy of these blind tests have exceededour expectations, generally approaching ± 3 %. The methodology is presentedalong with the statistical analysis and recommendations for use.
Modeling of Tubing Pickling in Conjunction with Acidizing Treatments
Authors: Al-Mutairi S. H. , Hill A. D. , Nasr-El-Din H. A.
Published: December 2007

Pickling well tubulars to prevent pumping unwanted materials into the formation is an issue that should be decided on an individual job basis. Acid pickling of tubing is a process of flow in a tube or annulus with heterogeneous reactions occurring at the wall of the tube. The reacting solid species at the wall are primarily mill scale, pipe dope, and other scales of various types. The fluids injected for pickling are usually strong acid solutions (HCl), but may also include surfactants, organic solvents, and gelled solutions to aid in lifting solids loosened from the tubing wall. Thus, the process is a complex one involving several reactions with perhaps multiple stages of fluids.

Tubing pickle is an essential part of well stimulation treatments if the main acid job is to be bullheaded. Standard design parameters for a pickle treatment depend on experience and personal judgment. It appears that the standard pickle treatment design is overestimating the required volume of pickling acid. Field data indicate that excessive acid volumes are used for tubing pickle because large returns of unreacted (live) acid are usually recovered on the surface. Careful analysis of flowback samples showed that only a fraction of the acid is being consumed by mill scale and other tubing contaminants.

In this paper, proposed mechanisms to explain the behavior of acid contact with the tubing are presented and a mathematical model for predicting acid consumption and dissolution of tubular contaminants is developed. The model is developed for the bull-heading case where the pickling acid is pumped down the tubing, then flowed back to the surface. The model considers the reaction of acid with mill scale (Fe3O4). The equations formulated are solved numerically to predict the concentrations of major chemical species as a function of position along the tubing and in the effluent from the well during flowback.

Such a model can be extremely valuable in optimizing the application of future pickling treatments. Using this model, the acid volume needed for pickling operations can be reduced significantly and other improvements can be made without extensive, costly field testing. Finally, some recommendations are made to design optimum pickling treatments.
A Front-Tracking Method for Efficient Simulation of Miscible Gas Injection Processes
Authors: Juanes R. , Lie K. -A.
Published: December 2007

This paper presents a front-tracking method for the numerical simulation of first-contact miscible gas injection processes. The method is developed for constructing very accurate (or even exact) solutions to one-dimensional initial-boundary-value problems in the form of a set of evolving discontinuities. The evolution of the discontinuities is given by analytical solutions to Riemann problems. A complete analytical Riemann solver is presented along with methods for simplifying the wave structure for Riemann problems of small amplitude. Several representative examples are used to illustrate the excellent behavior of the front-tracking method.

The front-tracking method can be extended to simulate higher-dimensional processes through the use of streamlines. The paper presents an application of this computational framework for the simulation of miscible flooding in a three-dimensional, highly heterogeneous formation, and demonstrate that a miscible water-alternating-gas injection scheme is more efficient than waterflooding or gas injection alone.
Fractured Reservoir Characterization Using Dynamic Data in a Carbonate Field, Oman
Authors: Ozkaya S. I. , Richard P.
Published: December 2007

The main objective of this study was to extract fracture data from multiple sources and present it in a form suitable for reservoir simulation in a fractured carbonate field in Oman. Production is by water injection. A combination of borehole image logs and openhole logs from horizontal wells revealed that water encroachment is mostly through fracture corridors and appears as sharp saturation spikes across fracture clusters. Dispersed background joints have little flow potential, either because of cementation or lack of connectivity or small size. Image logs indicate fracture corridors are oriented dominantly in WNW direction. Most of the several injector-producer shortcuts are also oriented in WNW direction supporting the view that fracture corridors are responsible for the shortcuts.

Flow meter logs from vertical injector or producer wells intersecting a fracture corridor show a step profile. A comparison of injection or production history of wells with or without a step profile provided a means to calculate permeability enhancement by fracture corridors. The field has over 300 vertical and nearly 20 horizontal wells, which allowed us to generate detailed fracture permeability enhancement and fracture corridor density maps based on injector and producer data, shortcuts, mud losses, openhole logs and borehole image logs. We were able also to build stochastic 3D fracture corridor models using corridor density from dynamic data and orientation from borehole image logs and seismic data. Fracture corridor length and width were tied to fracture permeability enhancement using wells with both image logs and production data. The fracture permeability enhancement maps were independently verified by water flood front maps. Notwithstanding the uncertainties, the fracture data was sufficiently accurate and detailed to generate both single and dual porosity simulation results with good field scale history match.
Orientation and Career Development for New Engineers
Authors: Talabani S.
Published: December 2007

Training new engineers for any industry is not an easy task. It is also the most important task for the company to invest effort and money in, because the new engineers today will be the managers of the future.

Incapable engineers with insufficient backgrounds in training will therefore lead the company to make disastrous mistakes in planning and management. Consequently, it is important to put serious efforts into training new engineers by appointing either the right training staff within the company, or the right company responsible for managing the training plans in detail. Training plans should be reviewed by both sides. The company "that the engineer belongs to" should identify the right position for the engineer in the company. This is not a one-sided decision and should rather be made by involving the engineer. The engineer should have a taste of the position and enjoy doing the work. The company, on the other hand, should ensure that the position suits the engineer.

Knowledge of the company's heritage by the employees is as important as their tasks. Knowing the company's structure helps an employee recognize their position within the company.

A new employee should be advised that their education should start from day one in the company by keeping up to date with the latest research and studies conducted all over the world. In this paper, a detailed plan for training new engineers, phases a company should follow for training, what supervisors should be looking for, and how to periodically improve training programmess are addressed.
The SURE way to Underbalanced Drilling
Authors: Qutob H. , Ferreira H.
Published: December 2007

The benefits of UnderBalanced Drilling-UBD are now widely understood and revealed. However, the impact of UBD on well productivity/injectivity is still elusive. Few papers have documented historical applications of UBD and a recent focus has been to quantify UBD benefit through productivity increase comparisons, or productivity improvement factors-PIFs against field averages. Yet, comparative analyses are questionable.

A process named Suitable Underbalanced Reservoir Evaluation (SURE) has been developed to identify UBD prospects and to quantify the potential well productivity/injetivity benefits of a UBD operation. SURE is a simple, fast and reliable way to accurately evaluate the suitability of an UBD operation for reservoir performance.
A Comparison Study on Experimental Design and Response Surface Methodologies
Authors: Yeten B. , Castellini A. , Guyaguler B. , Chen W. H.
Published: December 2007

Experimental design method is an alternative to traditional sensitivity analysis. The basic idea behind this methodology is to vary multiple parameters at the same time so that maximum inference can be attained with minimum cost. Once the appropriate design is established and the corresponding experiments (simulations) are performed, the results can be investigated by fitting them to a response surface. This surface is usually an analytical or a simple numerical function which is cheap to sample. Therefore it can be used as a proxy to reservoir simulation to quantify the uncertainties.

Designing an efficient sensitivity study poses two main issues: Designing a parameter space sampling strategy and carrying out experiments.Analyzing the results of the experiments. (Response surface generation)

In this paper we investigate these steps by testing various experimental designs and response surface methodologies on synthetic and real reservoir models.

We compared conventional designs such as Plackett-Burman, central composite and D-optimal designs and a space filling design technique that aim at optimizing the coverage of the parameter space. We analyzed these experiments using linear, second order polynomials and more complex response surfaces such as kriging, splines and neural networks. We compared these response surfaces in terms of their capability to estimate the statistics of the uncertainty (i.e., P10, P50 and P90 values), their estimation accuracy and their capability to estimate the influential parameters (heavy-hitters). Comparison with our exhaustive simulations showed that experiments generated by the space filling design and analyzed with kriging, splines and quadratic polynomials gave the greatest accuracy while traditional designs and the associated response surfaces performed poorly for some of the cases we studied. We also found good agreement between polynomials and complex response surfaces in terms of estimating the effect of each parameter on the response surface.
The Development of an Optimal Grid-Coarsening Scheme: Interplay of Fluid Forces and Higher Moments of Fine-Scale Flow Data
Authors: Darman N. H. , Sorbie K. S. , Pickup G. E.
Published: December 2007

The accuracy of upscaling procedures can be improved by using non-uniform grid cells at the coarse scale level. Several researchers have investigated objective methods of selecting the optimal coarse grid configuration for a particular fine grid model1–2. However, all of these works neglect the effect of fluid force balances and always assumed the model to be in viscous dominated flow. This paper describes a new optimal grid-coarsening scheme for two-phase flow in porous media based on the quantitative use of fine-scale simulation data. The main idea of this approach is to use fine-grid fluctuating moments to guide the choice of the coarse grid structure. These quantities are derived from the volume average saturation equation for different fluid force balances i.e. viscous, gravity and capillary. It is shown that this approach results in a more accurate prediction of quantities such as total oil recovery and fluid production ratio in coarse grid models.

Here, we explore the relationship between the sub-grid properties described above, and coarse scale numerical simulations for several synthetic model problems. To do this, we first introduce capillary terms into the volume averaging equations3 to allow us to assess the coarse scale simulations when capillary pressure is important in the fine grid models. Then we proceed to the two-stage testing of the proposed technique to study the relationship of sub-grid variability to the error in the coarse scale simulation results. In the first stage testing, we consider many different aggregations of 2D, 20-layer fine grid systems to equivalent 2-layer coarse grid systems and in the second stage testing, we then apply our findings to more heterogeneous interbedded sand cases where capillary forces are more important and consider coarsening the fine grid model to more than 2 layers.
A New Method for Profile Control with Compound Ion Gel before Polymer Flooding
Authors: Liu H. , Wang J. , Yang Y. , Wang F.
Published: December 2007

It is well known that extensive profile control can enlarge sweep area and enhance displacement efficiency in reservoirs with inner-layer and inter-layer interferences. As for Daqing oilfield, the heterogeneity is very serious in vertical direction. After a long term of water flooding, big channels were formed in many layers. In order to improve the development efficiency, an extensive profile control with compound ion gel was performed before the polymer flooding. This profile control technique was tested in some pilot areas. The treatments have achieved good results in increasing oil production and decreasing water cut. The application results indicate that profile control with compound ion gel is one of the most effective methods that can improve development efficiency of polymer flooding.
An Assessment of Emerging Technologies for Production Optimization in Saudi Aramco—Southern Area Production Engineering
Authors: Vo L. , Styler J. W.
Published: December 2007

In the petroleum industry, advances in technology continue to make a great impact on the business environment. Within the last decade, many emerging technologies have transformed the way oil and gas companies manage and optimize their operations. Today it is widely recognized that significant new oil fields are hard to find and aging oil fields are becoming more challenging and costly to operate. Emerging technologies fill a critical need in the fight against relentless production decline and rising operating costs.

In this regard, Saudi Aramco is no exception, even though it operates some of the largest oil and gas fields in the world. Aside from its routine production related initiatives, the company has invested a significant sum in new technologies with the goal of maximizing production and minimizing capital investment and operating costs over the long term. This paper will provide an assessment of new technologies that Saudi Aramco Southern Area Production Engineering (SAPED) has been working on over the past several years to meet this objective. Each of the applications discussed has either already yielded or is expected to yield significant benefits in terms of productivity improvement/operational enhancement, data management/reservoir optimization, or safety. A brief description of each technology is presented from a Production Engineering perspective.
Upscaling and Discretization Errors in Reservoir Simulation
Authors: Sablok R. , Aziz K.
Published: December 2007

Reservoir simulation models are used as an everyday tool for reservoir management. The number of grid blocks in a simulation model is generally much smaller than the number of the grid blocks in the geological model. The geological model is therefore regularly upscaled for building reasonably sized simulation models. Any upscaling causes a loss in detail and introduces errors. Understanding the nature of the errors that occur due to the upscaling step is important because it can provide a handle on the kind of upscaling to be performed and the optimum level of upscaling. Furthermore, understanding interaction of gridding and upscaling errors is essential for building reliable simulation models. In this paper we analyze errors introduced due to the upscaling step.

Firstly, the generality of the purely local single phase upscaling is considered and the errors introduced due to its use in complex multiphase flows are investigated. Three kinds of errors, namely total upscaling errors, discretization errors, and errors due to the loss of heterogeneity are defined and their behavior as a function of the level of upscaling is studied for different types of permeability distributions. The reasons for apparently low total upscaling errors at high levels of upscaling are investigated. The efficacy of the geostatistical tools (variograms, QQ plots) for understanding the geological structure of the upscaled models as compared to the reference model is tested for different cases.

Secondly, the uncertainty introduced in the flow results due to the upscaling errors is studied in conjunction with the uncertainty incorporated through the introduction of geological variability in the ensemble of geological models. The behavior of upscaling errors and geological variability as a function of level of upscaling is studied, and its possible impact on important reservoir management decisions, is analyzed. It is shown that the uncertainty models of cumulative oil profiles, obtained from flow results of highly upscaled models can contain significant uncertainties. These uncertainties are a result of upscaling errors and therefore cannot be considered to represent only geological uncertainty, which is captured by the introduction of geological variability in the ensemble of the geological models.
Evaluation of Residual Oil Saturation and Recovery Efficiency of Two Distinct Arabian Carbonate Reservoirs
Authors: Okasha T. M. , Funk J. J. , Al-Shiwaish A. A.
Published: December 2007

Saudi Arabia has a variety of carbonate reservoirs of different geologic ages. Such reservoirs are characterized by heterogeneous rock properties. These heterogeneities are caused by wide spectrum of environments in which carbonates are deposited and subsequent alteration of original rock fabric.

Extensive SCAL work was carried out on preserved core plugs recovered from two distinct carbonate reservoirs. The first reservoir is a Late Jurassic Arab-D offshore carbonate reservoir (Abu Safah field). The second one is Shu'aiba reservoir (Lower Cretaceous) located in Rub’ Al-Khali in southeastern Saudi Arabia. The purpose of this study is to provide and evaluate waterflood recovery efficiency and residual oil saturations of the two distinct Arabian reservoirs.

Variation of oil recovery and residual oil saturation between the two distinct reservoirs is due to variations of rock characteristics especially the relationship of textural and diagenetic features which affect the size and distribution of pore throats. Shu'aiba reservoir rock could be classified as wackstone which demonstrates a higher ratio of lime mud to detrital grains (pore sizes ~ 0.27 to 1.5 microns). On the other hand, Arab-D reservoir is classified as grainstone and consists of oolitic limestone and dolomitic limestone with larger pore sizes (0.5 to 5.5 microns).

The results indicated that pore structure, pore size distribution, rock fabric, and environment of deposition are important factors that affect microscopic oil and water flow in porous media and the development efficiency of an oil field developed by water injection. Oil recovery from Arab-D reservoir is slightly higher than that of Shu'aiba reservoir. The residual oil saturations values for Arab-D reservoir were also found to be slightly higher than those of Shu'aiba reservoir. Arab-D reservoir showed less permeability dependence for both (Swir and Sor) end point saturations.
Successful Use of Horizontal Well Technology in Mitigating Water Production and Increasing Oil Recovery in the South Umm Gudair Field, PNZ, Kuwait
Authors: Barge D. , Tran T. , Al-Shaarawy O. , Jha M. , Hagtvedt B. , Al-Haimer M. , Al-Harbi M.
Published: December 2007

The producing history of the South Umm Gudair Field (SUG) is characterized by increasing water cuts and increasing decline rates. Several different conventional techniques were applied to mitigate the effects of water encroachment. Results from applying these techniques were mixed. While some earlier applications looked promising, later applications were often marginal. As a result, horizontal sidetracking was introduced in the SUG field. A total of 15 horizontal sidetracks were performed from 1999 to 2004, resulting in both increases in oil production and reduction in water cut. This paper presents the results of sidetracking 15 wells in the SUG field to mitigate water encroachment and increase oil recovery.
Oil-Water Separation Experience from a Large Oil Field
Authors: Kokal S. , Al-Ghamdi A.
Published: December 2007

This paper discusses challenges related to emulsions that have been encountered in a large Saudi Arabian field. The field produces from several different reservoirs with a range of fluid properties. These properties provide an interesting case of operational challenges in oil-water separation including increased incidents of shorting in the separator, tripping of equipment and increased demulsifier consumption.

This paper presents the results of a comprehensive study that was initiated to understand the main causes of emulsion formation in the field and ways to optimize oil-water separation. The effect of several recommendations that were implemented by operations engineering in the field were evaluated. These include the conversion of a two-phase separator into a three-phase separator, splitting of the demulsifier injection between offshore producing platforms and onshore wet crude handling facilities, and field trials with promising chemicals. The demulsifier costs have been reduced by over 50% by the implementation of retrofitting and proper demulsifier injection strategies. The results presented in the paper provide invaluable operational experience and many lessons learned are applicable to any crude-oil treating facilities.
Sulfur Disposal by Acid Gas Injection: A Road Map and a Feasibility Study
Authors: Kokal S. , Al-Utaibi A.
Published: December 2007

Sour natural gas contains H2S and CO2, which have to be removed to meet specifications for sales gas. The removal process is done at the gas plants. The resulting acid gas streams (primarily H2S and CO2) are processed in sulfur recovery units or sulfur plants, which convert the H2S to elemental sulfur instead of burning it and flaring the produced SO2. The sulfur recovery units (SRU) are not a major revenue generator (due to the low sulfur price) and are primarily installed for environmental reasons.

The total world sulfur production is anticipated to increase in the future, causing a downward pressure on sulfur prices. With low sulfur prices and large stockpiles of sulfur, it is worthwhile to consider alternate processes for handling sulfur. One such alternate is the injection of acid gas into a subsurface reservoir, much like injecting the produced water during crude oil production.

Acid gas injection has several advantages and disadvantages. Advantages include low operating expenses, reduced sulfur emissions into the atmosphere, CO2 sequestration and the ability to handle wide range of acid gas compositions. Disadvantages include finding a geologically isolated disposal or storage reservoir, increased safety risks, subsurface migration and lost revenues from sulfur. Any one of these could be the controlling factor, and a detailed economic and environmental analysis is needed to decide whether an acid gas injection (AGI) scheme should be installed in lieu of sulfur recovery plant. The existing AGI schemes are primarily installed in Canada (a few in the USA) due to low sulfur prices, increased environmental regulations making it mandatory for operators to control sulfur emissions into the atmosphere, and availability of suitable depleted oil and gas reservoirs.

This paper presents a roadmap for acid gas injection schemes including the technical and economic factors that need to be addressed in deciding whether AGI is feasible. An example feasibility study for a Saudi Arabian field is included as a case study.
Measurement and Simulation of Low Vapor Pressure Blends of NGL and Stabilized Crude
Authors: Kokal S. , Meeranpillai N. S. , Al-Otaibi F. M. , Al-Madani E.
Published: December 2007

Due to operational constraints natural gas liquids (NGL) are sometimes blended with stabilized crude. This option is considered when there is a temporary surplus of NGL and for better NGL management. The NGL blend ratios are generally very small and conservative and are not meant to impact the crude quality. The blends have to meet rigorous vapor pressure specifications.

A systematic study was conducted to determine the vapor pressures of different NGL/crude oil blends. The evaluation considered various factors that impact the vapor pressure of the blends, including the NGL/crude oil ratios, degree of crude stabilization, temperature, and the retention time in the pipeline and/or in the crude tanks. An important aspect of the study was to determine the "foaming tendency" and volume changes during blending. Vapor pressure curves were determined for different blends of stabilized crude with NGL as a function of temperature. The data included both the true vapor pressure and Reid vapor pressure of the blends. The experimental data were supplemented with equation of state simulations. Low vapor pressure data of blends are scarce, and the paper discusses the physical properties of NGL/crude oil blends.
Application of Formation Testing While Drilling in the Middle East
Authors: Seifert D. J. , Al-Dossari S. , Burinda B. J. , Kellet S.
Published: December 2007

In recent years, Measurement While Drilling / Logging While Drilling, MWD/LWD, formation evaluation applications have evolved to a point where many applications usually reserved for wireline logging can now be utilized using LWD technology. The latest of such applications come from formation testing while drilling tools which offer an alternative to wireline-based formation testing. Formation pressure data obtained while drilling is useful for traditional applications such as fluid typing, fluid contacts, and reservoir connectivity/isolation determination as well as for improved well control with real-time measurement of pore pressures.

This paper presents a case history from the Middle East where a new Formation Tester While Drilling (FTWD) tool has recently been run. The tool utilizes a probe and packer concept similar to conventional wireline formation testers. A packer and probe are extended to the formation, and a small sample chamber is used to pressure test the formation. To obtain a formation pressure, it is required to stop drilling for a minimal period. Experience has shown this time period to be typically less than the time required to make a connection.

Field data from Saudi Arabia will be presented, where the Formation Tester While Drilling (FTWD) tool was recently run. The tool's operation, response, and applications of the data obtained are discussed.
Immiscible Displacement of Non-Newtonian Fluids in Communicating Stratified Reservoirs
Authors: El-Khatib N.
Published: December 2007

The displacement of non-Newtonian power-law fluids in communicating stratified reservoirs with a log normal permeability distribution is studied. Equations are derived for the fractional oil recovery, water cut, and injectivity ratio at times of breakthrough in the successive layers of the reservoir. Many of the resulting equations are implicit in nature and an iterative solution procedure is used. Expressions are also derived for the pseudo relative permeabilities as function of the average saturation.The performance is compared with that for the Newtonian fluids. The effect of the different parameters on the performance is investigated. These parameters included the apparent mobilityity ratio, the power-law flow behavior indexes, the Dykstra-Parsons variation coefficient, and the flow rate. Constant injection rate and constant total pressure drop cases are studied.
Design and Application of a Novel HT/HP "Stirred Reactor" Test Rig To Study Scale Formation and Control
Authors: Graham G. M. , Williams H. L , Wat R. , Tau L. A. , Wennberg K. E.
Published: December 2007

In several HT/HP production environments severe downhole carbonate scale is often anticipated. Moreover, the high temperature means that reaction kinetics are very rapid and therefore the propensity for scale formation remains high even at moderate levels of oversaturation. However, a number of limitations are recognised when assessing the scale risks associated with such production conditions. This includes; uncertainties regarding the initial FW composition, accuracy of scale prediction tools and the application of conventional laboratory test procedures under these conditions. This paper describes the use of a novel HT/HP stirred reactor test rig (400F & 5,000 psi) designed to conduct in situ scaling experiments and allow equilibrium conditions to be established. The equipment is specially designed for the extraction and stabilisation of samples at or near tested conditions allowing the equilibrium brine composition to be determined under more representative HT/HP conditions. Initial results presented in this paper describe the commissioning and validation of the experimental design including the use of tracers to ensure effective transfer and collection of fluids from the reaction vessel. Results are then presented to determine the equilibrium saturation state of a particular field brine starting from the supplied water composition. In summary equilibrium saturation tests conducted at 340F and pressures between 200 psi and 5,000 psi showed significant quantities of carbonate scale (both barium and calcium carbonate) precipitating from solution, indicating a potential uncertainty in the original brine composition.

In summary, the data generated allows equilibrium saturation levels to be determined under HT/HP conditions allowing uncertainties in the water composition to be assessed. The determined saturation levels are also directly correlated with dynamic tube blocking tests and scale prediction tools. The data can therefore be used to further tune predictive modelling capabilities under these more extreme (HT/HP and high salinity) conditions.
Minimum Platform Designs - Cook Inlet, Alaska
Authors: Visser R. C.
Published: December 2007

The paper describes two minimum-cost, self-erecting, platform designs and one caisson structure design that can be installed in Cook Inlet, Alaska without the need for heavy lifting equipment. The Cook Inlet environment is characterized by thirty-foot tides and during the winter months by fast moving ice floes. The area is remote from other offshore operating areas and there is no heavy lifting equipment. One of the designs has been built and platform Osprey was installed in Cook Inlet in 2000. The paper will describe how it was designed, constructed and installed. A, second, different design concept allows platform installation in deeper water, again without the need for heavy lifting equipment. The third design concept is an outrigger caisson design that can be installed with a jack-up drilling unit. It would have application as a satellite platform structure.

Use of these minimum-cost platform and caisson designs would enable development of marginal fields in Cook Inlet that heretofore could not be developed because the high cost of mobilizing and demobilizing heavy lifting equipment to and from Cook Inlet would make development uneconomic.
Using Real-Time Pressure Data for Well Placement Planning
Authors: Parker M. , Bradford R. N. , Corbett C. , Heim R. N. , Isakson C. L. , Broome S. S. , Proano E.
Published: December 2007

Well placement decisions are routinely made on the basis of simulation models that are created before production operations begin. Real-time downhole pressure data and surface flow rate information can provide a significant set of calibration information early in the life of the reservoir. In this paper we describe a method for comparing a set of assumed reservoir parameters, especially the presence of a connected aquifer and its size, with a set of simulation models to assist with well placement decisions.

In the South Timbalier 316 block, a delineation well penetrated the steeply dipping B4 reservoir near the oil/water contact. Based on a comparison of downhole pressure data, with data from simulation models, the operator concluded that a connected aquifer was present and estimated its size. This information was sufficient for the operator to know that the well would not be needed as a water injector and to justify a sidetrack from the downdip location to an updip location.

When the updip sidetrack well was drilled, reservoir rock quality was below the minimum for a commercial completion. This brought into question the viability of any hydrocarbon storage capacity in the northern portion of the field. As soon as the updip sidetrack well was logged, a "what-if" reservoir model was run to simulate a no-hydrocarbon-reservoir scenario in the northern portion of the field. This reduction represented approximately 25% of the reservoir hydrocarbon pore volume. The model results clearly indicated that this was not a reasonable model and gave the operator confidence to sidetrack the well directly to the west, to a slightly downstructure position, whereby a successful completion was made. Without this "quick-response reservoir model" the well may have been sidetracked to the south, resulting in a less-than-optimal well location.
Reservoir Characterization and Simulations Studies in a Heterogeneous Pinnacle Reef for CO2 Flooding Purposes: A Case Study
Authors: Al-Dliwe A. , Asghari K.
Published: December 2007

Carbon dioxide injection is an effective method for enhanced oil recovery. In this process, CO2 develops miscibility with the oil under reservoir conditions, and leads to additional oil recovery. Proper reservoir characterization has a significant influence on designing and implementing a successful CO2 flood in a reservoir.

This paper presents the results of a reservoir characterization analysis and simulation in a relatively small reef located in Northern Alberta, Canada, which was selected as a candidate for a CO2 injection project. This reef has a thick oil column spanning a small area with steeply sloping sides, and two wells drilled on the same side of the reef. Open-hole logs and production history data were available for only one of the two wells. Data analyses disclosed a number of challenges that could affect the results of any simulation for predicting the performance of CO2 displacement in this field. These challenges included, but were not limited to, the existence of two no-flow barriers with unknown extensions, lack of other data such as relative permeability, and lack of information on lateral distribution of the reservoir properties. Material balance analysis indicated the maximum oil in place was 4.7 MMSTB with a weak water support.

A fully compositional reservoir simulator (CMG-GEM™) was used with the aim of improving the understanding of the reservoir characteristics, and investigating the suitability of CO2 injection. An 8-component Peng-Robinson EOS was utilized to describe the phase behaviour of the reservoir fluids and injected CO2. History matching was done and the current reservoir pressure was found to be about 1000 psi below the minimum miscibility pressure. A simulation study was conducted and the model predicted an incremental oil recovery of around 1.04 MMSTB and about 0.424 Mt of injected gas stored in the reservoir.
Integration of Advanced Production and Image Logging in a High Gor Horizontal Well with Assessment of Remedial Actions
Authors: Al-Fawwaz A. A. , Mubarak H. K. , Zeybek M.
Published: December 2007

Production logging in high GOR horizontal wells still exhibits difficulties due to multi-phase, complicated flow regimes in undulating long well bores. Accurate diagnosis of gas entries is important for the understanding of the well performance, reservoir dynamics, characterization and if possible, for shut-off remedial action.

In this paper, a case study is presented in a horizontal well with high GOR where oil production decreased significantly due to gas entries. The example horizontal well is located in Saudi Arabian Lower Cretaceous carbonate reservoir that has gas cap and relatively weak aquifer. Although the horizontal well is placed away from the gas cap, increase in GOR was observed after two years of production time. Since GOR increased to over 5000 SCF/STB by then, an integrated production logging tool was utilized to detect gas entries and determine flow profile.

Results showed that the gas entries were detected from the high sides of the well and the majority of the gas was entering from the heel section over 500 ft of interval. Gas hold up in the well bore was determined from gas sensor tool in real time and pulsed neutron tool, providing high confidence. All the sensors exhibited coherent measurements, yielding confident and conclusive results for the gas entries. Image logs and permeability determinations identified the presence of different facies with high permeability over the interrelated entry intervals, supporting the calculated flow profile. The results, observed difficulties and recommendations are discussed for improvements. A single well fine grid numerical reservoir simulation model was also developed to assess impact of remedial action plans.
Waterflood Pilot in a Mature Fractured Carbonate Reservoir
Authors: van Schijndel L. A. E. , Swinkels W. J. A. M.
Published: December 2007

This study focuses on a giant fractured carbonate field in the Middle East where large undeveloped oil volumes reside in a reservoir that is currently producing via Gas-Oil-Gravity-Drainage. An inverted five spot pilot is planned to address the viability of waterflooding this reservoir, to increase production rates and ultimate recovery.

Three issues determine the success of waterflooding this reservoir. Firstly, there is a sharp contrast between the relatively homogeneous and unfractured low-permeable bottom part of the reservoir, which is the main target for water flooding, and the heterogeneous, highly fractured upper part. Secondly, the ongoing GOGD development and the associated gas injection have resulted in considerable uncertainty in the current oil and gas saturation distribution in the fractures and the matrix. Finally, the uncertainty on vertical to horizontal permeability has a major impact on the waterflood recovery in the bottom part of the layer.

Reservoir simulation of a pattern element shows scope for an additional 20 % recovery in unfractured reservoir units. This is limited mostly by the reduction in sweep efficiency due to water shortcutting through the high permeable layer. Another key uncertainty is free gas production caused by the ongoing GOGD development.

The results of the element model simulating a field wide pattern were compared with the results of a second unconfined reservoir model representing the pilot five spot.

The unconfined pilot will show lower production rates than the full pattern development due to insufficient pressure support. Not appreciating this phenomenon can cause underestimation of expected pattern water drive performance.

On the other hand pattern drive performance can be overestimated on the basis of the pilot, since gas will migrate out of the unconfined pilot area and oil mobility in the pilot is less affected by the presence of free gas in the pilot.

The pilot five spot is currently being drilled and its results will be used to predict performance of the full field pattern waterflood scheme.