bluuebunny/crossref_metadata_2025 huggingface dataset:
Artificial Neural Networks Models for Identifying Flow Regimes and Predicting Liquid Holdup in Horizontal Multiphase Flow
Authors: Osman El-Sayed A.
Published: December 2007

Knowledge of liquid holdup and multiphase flow regimes in pipes is very important in pressure drop calculations and design of surface facilities. To predict the holdup, one has to define the flow regime at a given pressure, superficial gas and liquid velocities, temperature, and other flow characteristics. Several flow maps, regression and mechanistic models are available in literature to predict holdup and flow regime. However, some of these models do not predict the liquid holdup correctly.

This paper presents two Artificial Neural Networks (ANN) models to identify the flow regime and calculate the liquid holdup in horizontal multiphase flow. These models are developed using experimental data - 199 data points - and utilizing three-layer back propagation neural networks. Superficial gas and liquid velocities, pressure, temperature and fluid properties are used as inputs to the network. The output of the first network is the flow regime, while the other network predicts the liquid holdup. One-half of the data was used to train the ANN models, one quarter to cross-validate the relationships established during the training process and the remaining quarter to test the models and evaluate their accuracy. The results show that the developed models provide better predictions and higher accuracy than the empirical correlations developed specifically for these data groups. The developed flow regime model predicts the flow regime correctly for more than 97% of the data points. The liquid holdup model outperforms the published models in terms of the lowest absolute average percent error (9.407), the lowest standard deviation (8.544) and the highest correlation coefficient (0.9896).
Pre- Field Trial Testing of a Twin Screw Multiphase Pump
Authors: Yamashita M. , Sharma Y. , Ihara M. , Yamada K.
Published: December 2007

Performance tests were conducted on a twin screw multiphase pump in a large-scale flow loop prior to its first trial in an oil field in the Middle East. The main objectives of these tests were (1) confirmation of the pump’s hydrodynamic performance by examining the flow rate-head (Q–H) curves and the efficiency-head (η–H) plots, (2) checking the integrity of the design and construction, and (3) obtaining operational experience with the complete system. The pump was installed at the exit of a 82 m long, 106.3 mm ID pipeline and upstream of a three phase high pressure separator. The fluids used were nitrogen and water. A total of 76 flow tests were executed under the following experimental conditions; gas volume fraction (GVF) at the suction: 0 – 95 %; pump speed: 1200 – 1800 revolutions/minute; and differential pressure: 142 – 350 psig. These ranges covered most of the operating conditions to be expected during the field trial.

The pump operated successfully in the flow loop for a total of 150 hours. The Q-H curves showed an increase in volumetric efficiency with an increase in GVF. At high GVF, above 80%, an almost critical flow situation was attained, where the total flow rate was independent of the differential pressure. The η–H plots showed that the pump efficiency decreases with an increase in GVF. These characteristics are consistent with the results of tests conducted by other manufacturers on similar pumps. During the tests, no leaks were obtained through the mechanical seals and there were no problems with the quenching unit and cooling at the bearings. A maximum rise in temperature of 13 °C occurred when the GVF was 95%. Scratches seen on the external face of the screw and the internal face of the sleeve were attributed to scales in the pipeline. As a result of these data, the pre-field trial tests on the twin screw pump were considered successful and ready for testing in an oil field.
Quality Assurance Tool for PVT Simulator Predictions
Authors: Varotsis N. , Gaganis V. , Nighswander J.
Published: December 2007

The currently available PVT simulators predict the physical properties of reservoir fluids with varying degrees of accuracy depending on the type of the model utilised, the nature of the fluid and the prevailing conditions. Nevertheless, they all exhibit the significant drawback of lacking the ability to estimate the quality of their answers.

Artificial Neural Networks (ANNs), trained by large PVT databases, are increasingly utilized to provide accurate predictions of physical properties mainly due to their ability to learn from experience. The utilization of such models offers the unique capability of estimating the quality of their predictions as their degree of competence can be evaluated for each unknown test case1-2. The accuracy of the ANN based PVT simulators depends heavily on the density of the database compositional mapping around the coordinates of the unknown reservoir fluid. Unknown test cases found outside the available training space may lead to poor predictions.

In this work, a quality assurance tool is presented that is integrated to the ANN based PVT Expert™ model. This tool, for an unknown fluid, qualifies the predictions of the PVT simulator based on the evaluation of the affinity of the test case with the training data sets contained in the utilised database. Subsequently, the competence with which the ANN model has learned the general trend in the area around any new test case is assessed numerically.

This innovative approach was successfully tested against a large set of studies "unseen" by the PVT Expert. The ability of providing confidence for the accuracy of the PVT predictions and of assessing their quality, significantly upgrades the applicability of the PVT simulator as a valuable reservoir management tool.
Using an Artificial Neural Network to Develop a Wall-Loss Model for Coiled Tubing Fracturing Operations
Authors: Rispler Keith , McNichol Joanne , Matiasz Kevin , Rheinlander Mark
Published: December 2007

Coiled tubing (CT) erosion can occur during CT fracturing operations. Resulting wall loss and fatigue can limit CT life and prevent safe wellsite operations. An artificial neural network (ANN) has been successfully developed for accurately predicting wall loss resulting from erosion.

This paper presents a case history in which ANN technology was used to successfully manage tubing strings during CT fracturing operations. During these operations, wall loss affects CT pressure ratings, tensile strength, and fatigue, all of which are critical performance parameters used for determining CT life and identifying a safe operating envelope. An ANN can predict erosional wall loss and quantify critical performance parameters for specific applications.
Flow Equilibration Towards Horizontal Wells Using Downhole Valves
Authors: Sinha S. , Kumar R. , Vega L. , Jalali Y.
Published: December 2007

This paper analyzes the problem of heel coning under a variety of drive mechanisms and studies how deployment of downhole flow control devices along the length of the horizontal well affects this phenomenon. To reproduce the heel coning effect for homogeneous permeability fields, wellbore hydraulics must be taken into account. The control approach adopted in this work aims to achieve equal inflow from the heel and toe halves of the completion by adjusting the choke position in accordance with the in-situ flow rate. This strategy likens the behavior of the instrumented well to an infinite conductivity well, as far as inflow is concerned. The control strategy, however, has an outflow/lift cost, as it requires running stinger tubing inside the liner. For water-drive, this scheme results in delay of water breakthrough and extension of the pure oil production plateau. Alternatively, plateau production could be increased. For gas cap-drive, analogous conclusions hold except that the gas/oil ratio constraint necessitates a cycled production scheme with rate cutbacks for successive cycles. For the combined aquifer- and gas cap-drive, control mitigates gas coning more than water coning, because the well is positioned nearer the water-oil contact to satisfy the maximum recovery criterion within the operational constraints adopted in this study. Active control by downhole valves, therefore, is an effective means of overcoming the problem of heel coning where the displacing phase is water, gas, or both. Drainage becomes isotropically more uniform. In practice, realization of this scheme requires a fully coupled flow monitoring and control system.
Can Oil and Gas Companies Extend Best Operating Practices to Community Development Assistance Programs?
Authors: Wells John Bruce , Perish Meredith , Guimaraes Luiz
Published: December 2007

Faced with massive consolidations and unpredictable price swings, oil and gas companies increasingly turn to operational efficiency as the cornerstone of profitability, and many are adopting innovative cost reduction strategies. For example, in November 1999, BP Amoco engaged Pricewaterhouse Coopers for a $1.1 billion 10-year business process outsourcing agreement to manage the financial reporting, accounts payable and accounting responsibilities of its chemical, oil-exploration and production units.[1]

In one area, however, best practices remain the exception rather than the rule: community development programs.

Extractive industries in developing countries spend millions of dollars per year on community development programs in their areas of operation. For example, BP is soon to announce a global commitment to donate 1 percent of annual net revenues to social programs; while in Indonesia, P.T. Freeport donates 1 percent of annual gross revenues (US$ 16 million to US$19 million per year) to social programs in Irian Jaya. The authors estimate that global spending by oil, gas and mining companies on community development programs totals more than US$ 500 million per year.

While the goal of these development assistance programs is to better the communities in which the firms operate, the programs themselves are often designed and managed by operational staff whose backgrounds are in engineering and business rather than in community development.

As a result, corporate-funded community development programs do not often effectively serve either the firms or the communities.

Recently, some oil, gas and mining companies have begun to explore alternative approaches to community development. This paper assesses the traditional model and two emerging alternatives.
The Utilization of Malaysian Local Bentonite as an Extender and Free Water Controller in Oil-Well Cement Technology
Authors: Samsuri A. , Junin R. , Osman A. M.
Published: December 2007

This paper presents the results of experimental studies for Malaysian bentonite from Sabah (Lahad Datu and Tawau areas) application in oil- well cementing as compared to world wide commercially used Wyoming bentonite of USA. Samples were dried, grounded and sieved into particle size of 75(m. The experiments include XRD & XRF techniques to determine the chemical compositions and mineralogical contents of bentonite. Methylene blue tests were carried out to estimate the value of cation exchange capacity (CEC) in order to determine the approximate montmorillonite content. In the cement performance tests, class-G cement slurry mixed with bentonite in the range of 2%- 16% BWOC. The cement slurries were tested in accordance of API Specification 10. Dry and wet treatment processes were also conducted for the Malaysian bentonite to upgrade its performance.

From laboratory investigations, it showed that Malaysian bentonite has less content of montmorillonite mineral and more impurity materials such as quartz, kaolinite, illite, muscovite and hematite, while Wyoming bentonite considered as high- quality bentonite. Malaysian bentonite has low values of CEC which had been improved after treatment processes. Malaysian bentonite has low degree of swelling. The free water of the cement slurry increased with the increase of bentonite concentrations as compared to Wyoming bentonite. On the other hand, after treatment processes, the free water decreases in the cement slurry with bentonite concentrations increased. The Lahad Datu's bentonite had lowered slurry density after the treatments than the Tawau's bentonite.
Reservoir Management for Ultra-Thin Oil Columns Under Gas-Cap and Water Support: Attaka Field Examples
Authors: Vo D. T. , Witjaksana Renas S. , Sukerim Waryan , Dharmawan Agung , Iwan Harmawan , Okuno Masato
Published: December 2007

Exploitation of ultra-thin oil columns under gas cap and water support is challenging since both gas and water coning can seriously curtail oil recovery. Horizontal wells have shown to alleviate some of this problem as they allow for less drawdown and hence reduce coning for better recovery efficiency. Although the industry has shown horizontal drilling cost continues to be lowered, economics is still a major issue in exploiting ultra-thin oil bands using horizontal completion.

This paper presents a case study showing lessons learned from managing reservoirs with ultra-thin oil bands with less than 20 ft and sandwiched between gas cap and bottom/edge aquifer. Actual data from a field characterized by stacked pays of fluvial and deltaic channel sands in the Mahakam Delta complex are demonstrated. Subject to long-term production, the originally thick oil columns in these reservoirs have now become thinner, yet carry significant reserves to be prudently further developed. Issues involved in reservoir management such as well surveillance, well planning and prognosis, operating while drilling and producing, and long-term development plans are discussed. Reservoir modeling is shown to be the guide not only for well planning but also for well operations as it is used to select well type and completion strategy, optimize well production and prepare for continuous annual operating plan.

The vast well performance database provided from the paper shows horizontal drilling continues to be the main vehicle to develop these ultra-thin oil bands. Care however needs to be taken to scrutinize the economics inherent in selecting this type of completion, as other alternative methods also deserve to be considered.
Computer Simulation of Thermohydrodynamic and Technological Processes in Active Subsea Oil Pipelines
Authors: Thuc Phung Dinh , Karimov Marat F. , Karimov Zoufar Ph.
Published: December 2007

Here generalized analysis is given for transport of highly paraffin and highly congealing oil taking into account layout, technology of transport and construction features of subsea oil pipeline.

In accordance with results of physical experiments for active oil pipelines the generalized mathematical model was made to explain thermohydrodynamic regime of telescopic construction oil pipe operation for paraffin and highly congealing oil transport.

Thermohydrodynamic and mass exchange process in subsea pipelines are explained by differential equation system: flow (1), continuity (2), energy (3), heavy hydrocarbon fraction concentration forming wall depositions (4), adsorbtion kinetic and hydrodynamic desorbtion of wall oil depositions (5).

Based on mathematical model of existing subsea oil pipeline, new computer method was created for analysis of thermohydrodynamic and technological process while transporting highly paraffin and highly congealing oils. There was developed respective software package allowing to study both steadied and unsteady transport process in wide range of thermobaryc and technological parameters change characterizing oil pipeline operation.

Proposed method of analysis is intended for designing of new pipelines and modification of old subsea oil pipelines and change of transport technology in active pipelined, i.e. optimization of transport parameters and determination of oil pipeline safe operation limit eliminating critical transport regime-telescopic pipeline "freezing".

Digital experiments have shown that in certain technological transport condition the critical operation regime starts proceeding from intensive heavy hydrocarbon depositions (in solid phase) at inside pipeline surface. It is accompanied by spontaneous (uncontrollable) decrease (due to hydraulic resistance) of pipeline throughput. This process (if timely special measures are not taken) will result in full transport stoppage and subsequent pipeline "freezing".

Based on analysis of different technological parameters influence on thermohydrodynamic pipeline operation regime, there were considered and proposed method of thermal, hydrodynamic and chemical influence on wall depositions which allow to eliminate critical pipeline operation regime at different flow rates.

Here the results are given for digital simulation of pipeline operation in form of diagrams.
Luanping Fan-Deltaic Outcrop Geostatistical Characterization & Application to NY Oilfield, China
Authors: Liang Chen , Mu Longxin , Jia Ailin , Huang Shiyan
Published: December 2007

Fan-deltaic environment offers a particular challenge for geostatistical modelling. Over the past decades, geostatistical methods are widely accepted and applied to simulate sedimentary microfacies. In this study we have selected Sequential Indicator Simulation (SIS) to generate our model and perform sensitivity analysis. Luanping fan-deltaic outcrop has been selected as a case study. The outcrop is located in Hebei province, China. The main outcrop cut by road is an excellently exposed study area, whose length and height are 1300 meters and 230 meters respectively. The orientation is nearly east-west. It was deposited from upper Jurassic to lower Cretaceous. Based on outcrop studies, 16 types of microfacies have been classified and for simplicity, they have been finally combined into 6 types of microfacies in stochastic simulation.

The 2-D grid of 470 ×290 (ΔX=2.5m, ΔY=0.8m) has been designed to establish a single deterministic (prototype) model of Luanping fan-deltaic outcrop. The model honors all existing data and represents a realistic geological interpretation as closely as possibly. The input data of SIS are extracted from prototype model at different well spaces of 100,200,300,400 and 500 meters. As a result, microfacies simulations are constructed under different well spaces. Comparing these simulations with prototype model, prediction accuracy and uncertainty analysis are presented in this study.

The study shows geostatistical tools can well reproduce prototype model of Luanping fan-deltaic outcrop. The prediction accuracy is largely relied on variogram model and proportion of each microfacies. Moreover, SIS can also reflect the microfacies distribution law of fan-delta, especially fan-deltaic plain can be reproduced under less information. Finally the results are applied to NY oilfield, China successfully.
A New Approach to 3D Reservoir Simulation: Effect of Interfacial Tension on Improving Oil Recovery
Authors: Mulyadi H. , Amin R.
Published: December 2007

The importance of this simulation work was the incorporation of the experimental interfacial tension (IFT) and oil spreading coefficient parameters measured in our laboratories. The effect of IFT was incorporated into the simulator through relative permeability curves measured under positive and negative spreading coefficient for the three-phase reservoir system: oil, water and gas.

The oil spreading phenomena was tested on a black-oil reservoir located in Australia. The reservoir descriptions used in the model were validated by comparing the simulated results with the actual reservoir performance and its production parameters. A more severe test is to have the simulator compute the past performance of each individual wells, as well as historical pressures and fluid saturation distribution. The models incorporating permeability distributions has shown a far superior history match of primary and waterflood performance at a pressure below the original reservoir pressure (positive spreading coefficient) matching and confirming the core flooding results. Good history match was also obtained on individual well basis.

The work has shown that a substantial increased in the oil recovery can be achieved by operating the black-oil reservoir below its bubble point to ensure a positive spreading coefficient system. This allowed a balance between viscous force and gravity force for the oil to form a thin continuous oil film. Thus, ensuring continuity of the oil flow as it is being produced. The scheme has demonstrated that the oil recovery could be improved by as much as 15%.
Clean up and Well Testing Operations in High-Rate Gas-Condensate Field Result in Improved Sand Management System
Authors: Kaura Jiten Devender , Macrae Alex , Mennie David
Published: December 2007

During development of high pressure/high temperature (HP/HT) gas wells in Oman, clean-up operations that remove up to 10 tons of proppant fracture material from individual gas wells have become routine. The continuing development of fracturing, clean up and testing processes in the HP/HT well-testing environment has provided a unique opportunity to fulfill the need for enhancement of proppant clean-up equipment and methods.

Efforts have been concentrated on improving clean-up times, equipment efficiency and refining the design of the desander/filter sand management system (SMS). As a result of the improvements, the clean-up and testing processes have undergone significant modification.

During the initial phase of the project, numerous challenges had to be overcome, and improvements were made in the solids clean-up process. This paper will describe how proppant and other solids materials were managed during the wellbore and formation clean-out process.
A Study of Removal of Organic Formation Damage by Experiments and Modeling Approaches
Authors: Ju Binshan , Luan Zhian , Wu Zenggui , Lu Guangzhong
Published: December 2007

The precipitation or block of asphalts, asphaltene and other or-ganics in the porous media near the wellbole will reduce per-meability due to change in temperature, pressure and compo-sitions of reservoir oil. Injection of organic aromatic solvents and soaking is one feasible method to remove the precipitates. The objects of this paper are to confect economical and efficient solvents and optimize injected rate, volume and soak time of solvent. To obtain the objects, core flooding experiments by solvents are conducted to select optimum solvents and a simulator to remove the formation damages caused by organic deposition by soaking of aromatic solvents is developed. The influences of different injected rates, volume and soak time of solvent are simulated to improve the permeability of the damaged region. And the permeability is also predicted after soak. A project to remove organic formation damage near the wellbole by injection aromatic solvents started Nov, 1998 at an offshore oil field in China. And the production of the first well increased from 90t/d to 270t/d after injection solvent U-01 selected by core flooding experiments. The simulated results coincide well with the data from the oilfield.
Well Testing in the New Millennium — Real Time
Authors: Finley Douglas B. , Pahmiyer Robert C.
Published: December 2007

As oil industry technology has advanced, increasing emphasis has been placed upon accomplishing operational objectives more safely and efficiently. In pursuing these goals, operators and service companies have investigated the advances made in other technological fields, and many innovative applications have found their way into oilfield operations to accomplish these objectives.

One of the most notable technologies for improving and disseminating information is "Real Time Operations." Real Time Operations or RTO in the oil industry is already a reality in certain geographical areas. Specifically, data from drilling operations such as Formation-Evaluation-While-Drilling are already being "beamed" real-time back to the operators, assisting them in making optimal operating decisions. The advantages are clear when one considers that in the past, the subject matter expert had to be present at the well site in order to carry out any type of real time analysis or control during an operation. This advantage becomes particularly beneficial in remote areas.

Cost savings from RTO vary according to the particular service and wellsite location, but with increasing emphasis on deeper waters, high pressure/high temperature (HP/HT) environments, and remote areas, the value of RTO becomes more evident.

This paper will present a synopsis of oilfield RTO and how it is applied to drill tem testing and well testing. A classification system is proposed for delineating the different types of RTO that are available. Several RTO case histories are presented to support the applications. A discussion concerning the added-value generated as well as the relative cost-savings will be shown by the case histories.

The capability to carry out real-time analysis remotely can positively effect cost efficiency and allow state-of-the-art testing to be performed in areas that would not previously have been feasible. In addition to the present usage of RTO in the oilfield, this paper will discuss what RTO capabilities can provide, in both the near-term and in the distant future.
The Integrated Production Database in Unocal Indonesia
Authors: Chatterjee Debasis , Palar Steve , Rothenberg Louis
Published: December 2007

Unocal has been a leading developer of Indonesia's energy resources for more than 30 years. In the late 1960s, Unocal Indonesia signed one of the world's first production-sharing contracts with Pertamina, Indonesia's national oil company. Currently, Unocal Indonesia operates 11 producing oil and gas fields offshore East Kalimantan, including Indonesia's largest offshore oil and gas field, Attaka, which the company discovered in 1970. The cumulative production of Unocal Indonesia to date is 890 MMB of oil and 1.87 TCF of gas.

Each day, a wealth of data related directly or indirectly to the volume of hydrocarbon production is collected at various points of oilfield operations. These data are transmitted to Unocal Indonesia's office via e-mail and are further processed for plant balance, gas allocation and monthly allocation. The raw and processed data can be accessed via Unocal Indonesia's Intranet for further data analysis and usage in simulation, mapping and general surveillance.

Until recently, a suite of four separate computer systems managed the production data. In 2000, Unocal Indonesia's Petroleum Engineering department decided to streamline the heterogeneous and proprietary solution by adopting a commercial master database and data management solution similar to the parallel data management effort in the Geological & Geophysical (G&G) domain. This effort is in line with the vision of knowledge management that can be created by integrating business processes and sharing information to manage the life cycle of Exploration & Production (E&P) assets.

This paper describes an integrated G&G and production data management system based on the Finder data management system and details how such a system improves employee productivity.

A phased approach has been adopted for implementation of the solution. The first phase involves consolidation of the legacy databases into a commercial master database that is built on an industry standard data model. In the second phase, the field data capture process will be improved and the current proprietary allocation and balance system will be replaced with a commercial solution.

The final result will be a single data repository providing Unocal Indonesia staff with validated, approved and easy-to-use data that is accessible via built-in data browsing facilities and inter-application data exchange utilities. In addition, the commercial system will require a smaller support staff, thereby freeing up more Unocal Indonesia team members to focus on maximizing the production and the recovery of reserves.
Estimation of Formation Hydraulic Properties from Analysis of Regular Operations Data
Authors: Silin D. B. , Tsang C.-F.
Published: December 2007

We propose to use regular pumping rate - pumping pressure data for estimating the formation hydraulic properties in the vicinity of wellbore without interrupting the operations. A distinctive feature of our analysis is that we account for the effects of pumping preceding the test interval. We derive our model from the same assumptions as in a standard pressure draw-down or pressure build-up test analysis. We introduce an additional parameter characterizing an effective pumping rate prior to the test. This parameter is of crucial importance for our procedure because there is no shut-in period preceding the test during regular operations. Moreover, we demonstrate that accounting for this parameter does affect analysis of a traditional pressure draw-down or build-up test as well. Our method produces good data matching, and the results are stable with respect to the selection of the portion of data for fitting. We derive our conclusions after analyzing almost entire data set, rather than only a portion of the pressure fall-off or build-up curve. This makes the results more reliable and stable with respect to measurement errors.

The new method we have developed is implemented in a code named ODA (Operational Data Analysis). This program incorporates a special curve-fitting procedure which we designed for our method to significantly simplify the problem and reduce the amount of computations. Therefore, the analysis can be preformed on a laptop computer.
Surface-Geometry and Trend Modeling for Integration of Stratigraphic Data in Reservoir Models
Authors: Xie YuLong , Cullick A. Stan , Deutsch Clayton V.
Published: December 2007

Accurate prediction of reservoir performance depends on an accurate estimate of the subsurface structure, lithofacies, associated petrophysical properties, and fluid distribution. Often the reservoir heterogeneities that are controlled by stratigraphic architecture and sedimentological trends are difficult to predict, particularly at subseismic resolution and far from well control. An ongoing challenge in subsurface modeling has been the utilization of analogs of complex geology along with seismic and sparse well data to predict the natural geologic complexity in models of the subsurface.

Time surfaces provide very important constraints on the geometric connectivity and continuity of facies and petrophysical properties in reservoirs. Such time surfaces are a suitable framework for facies and petrophysical properties modeling. Instead of modeling each reservoir later as a whole, the elementary sediment units are more easily modeled separately; the final composite model will show realistic heterogeneity patterns consistent with the underlying physics.

This work presents a hybrid deterministic, rule-based, and stochastic technique to generate surface models. These surface models are utilized as a framework to preserve sediment trends and honor analog and well data. Petrophysical properties are modeled for each sediment unit to reproduce trends. Finally, the individual sediment units are assembled into a reservoir model.

The surface model is created stochastically with parameterized surface templates. The shape, extent, height, orientation and regularity of the surfaces are controlled by user-specified distributions. The location of each surface in the reservoir is chosen on the basis of previous events. The addition of each surface is based on sedimentological rules. Conditional Gaussian simulation is used to ensure that the surfaces reflect realistic uncertainty through undulations and that well data intersections are honored.

The surface model divides the reservoir layer into sediment units. From geology and well data, trends are parameterized with mathematical functions as trend templates. Residuals are characterized after removing the trend. For each sediment unit, a trend and a residual model are generated stochastically. The observed well logs serve as conditioning data to guide the deployment of trends and to condition the generation of residuals. The model of each sediment unit combines its trend plus residual. The final reservoir model is obtained by assembling the separate sediment units.
A New Material-Balance Equation for Naturally Fractured Reservoirs Using a Dual-System Approach
Authors: Penuela Gherson , Idrobo Eduardo A. , Ordonez Anibal , Medina Carlos E. , Meza Nestor S.
Published: December 2007

The complexity associated to naturally fractured formations constrains reservoir engineers to use simplified versions of the Material Balance Equation for determining the initial hydrocarbon in place and predicting reservoir performance. Although in particular cases a limited variant of the MBE may end up in small volumetric errors, the risk of using it is extremely high.

In this paper, a new material balance equation for naturally fractured reservoirs is presented by using an original mathematical model that considers an initially-undersaturated black-oil fluid in a porous medium composed of interdependent matrix and fracture systems.

The proposed equation leads to an improved method of modeling naturally fractured reservoirs by considering the compressibility difference between fractured and matrix systems. Particularly, the analysis displays its capability in reservoirs that have similar storage capacity in matrix and fractures. Modeling separate estimates of oil accumulation have significant economic implications. Poor fracture-matrix communication will give initially high oil rates that drop quickly because oil is basically produced from the fracture network. Pore pressure reduction due to production will tend to close fractures leaving behind considerable oil reserves in the matrix system. Estimates of original oil in-place both in the matrix as well as in the fracture system will help reservoir and production engineers to decide on exploitation strategies for these complex reservoirs.

Our proposed equation has been applied to synthetic as well as field examples. Synthetic examples are used to validate the approach and examine the sensitivity to the average fracture compressibility. The field example is from El Segundo field, a low porosity carbonate reservoir in Colombia. Our example includes 8 producers located along the main fracture trend of the field and illustrates the feasibility of the approach for large-scale field applications.
A New Diagnostic Method for Prediction of Producibility and Reserves of Wells Producing from the Monterey Formation Using Well-Log Data
Authors: Wylie Ursula M. , Ershaghi Iraj , Christensen Karen
Published: December 2007

Formation evaluation using well log data is primarily a prediction tool for the purpose of identifying porous and permeable zones containing movable hydrocarbons. When the lithology is complex or the productivity is controlled by fracture density and the well log data are limited in scope, underestimation of productive intervals can occur. This paper is a unique study on relating more than 28 years of actual production history to the initial well log responses. This retrospective approach is the basis for presenting a diagnostic approach to predict producibility and reserves for other wells in the field under study or in other neighboring fields with similar geology.

The focus of the study is well log responses in the Monterey Formation of California Offshore. The geology of this formation is regarded as a prime example of a heterogeneous matrix system and a lithology-dependent fracture network. Lithology of the Monterey Formation is heavily influenced by the diagenetic stage of biogenic silica comprising the bulk of the geologic column, the detrital content and calcareous component. The particular field selected represents typical lithological and diagenetic stages observed in surrounding fields. As such, the proposed approach has merits for application to other fields. Geographically the Monterey type sediments extend from Baja California and all the way along the Pacific Rim to Japan8. Extension of the lithological patterns observed and the productivity correlations in surrounding fields can lead to eventual development of a more general correlation for widespread exploratory or development wells in this type of formation.
Transient Dual-Porosity Behavior for Horizontal Wells Draining Heterogeneous Reservoirs
Authors: Verga F. M. , Beretta E. , Albani D.
Published: December 2007

In the literature it has been shown that a bilinear flow regime, characterized by a quarter slope line on the logarithmic derivative diagnostic plot, can arise for horizontal wells draining fractured or layered reservoirs with transient dual-porosity behavior during the intermediate linear flow period. In the case of layered reservoirs the bilinear flow is a result of the linear flow in the more permeable layer toward the well and of the linear flow from the less permeable layer by which the more permeable layer is fed. In the case of fractured reservoirs the bilinear flow occurs as a result of the linear flow in the fracture planes and of the linear flow from the matrix toward the fractures. Therefore, bilinear flow is expected to end in relatively short times.

However, bilinear flow was also observed for a long period in the case of two horizontal wells draining a layered, heterogeneous limestone reservoir. The reservoir is characterized by matrix porosity only but highly permeable subvertical zones have been detected due to consistent mud losses occurred during well drilling, and by well logging. The two wells are drilled in the more permeable layer of the depositional sequence encountered at each well location.

A 3D numerical model of the reservoir was set up accounting for reservoir heterogeneity in an attempt to reproduce the pressure trend observed during well tests, which consistently showed a quarter slope pressure derivative. Results showed that the vertical heterogeneity would not lead to a bilinear flow regime although the permeability contrast between layers could locally exceed two orders of magnitude, probably because such contrast would not keep constant throughout the reservoir. The quarter slope pressure derivative could only be reproduced when the horizontal heterogeneity was accounted for, assuming that the more permeable subvertical zones would intersect the whole oil-bearing formation.
Sand Consolidation Using High-Temperature Alkaline Solution – Analysis of Reaction Parameters
Authors: Moreno F. E. , Mamora D. D.
Published: December 2007

As reported in SPE 62943, Wilmington Tar sand samples were successfully consolidated in the laboratory using high-temperature (250-260°C) solution of sodium carbonate (pH 11-12). The sample was placed in a vertical 18 in. long aluminum cylindrical cell with an ID of 1.5 in. The top half of the cell was thermally insulated while the bottom half was cooled. Hot alkaline solution was injected at 20 ml/min for 3-4 hours at the top of the cell and liquid produced at the bottom of the cell. After each experiment, the cell contents were removed and analyzed to determine if sand consolidation occurred. Thin sections of the sample were analyzed using an electron microprobe to determine any change in shape, size, and composition of the sand pack.

To better understand the process, experiments were subsequently conducted using samples of (a) pure quartz, (b) pure feldspar, and (c) a 50:50 (by weight) mixture of quartz and feldspar. In each case, the grain size was 20-40 mesh. For these cases, zeolites and amorphous silica were deposited on grain surfaces but were insufficient to cause overall sand consolidation. However, when a finer, poorly sorted (50-250 mesh) 50:50 mixture of feldspar and quartz was used, sand consolidation was obtained in 2.5 hours. At the top, hotter part of the cell, equant and acicular zeolite crystals (sodium aluminum silicates) weakly bound the sand grains. At the bottom and cooler part of the cell, the sand grains were strongly bound by amorphous silica. Results to-date indicate that both zeolite and silica may be cementing agents, the grain-bonding strength depending on the grain surface area. Further, the temperature, injection rate, and pH of the alkaline solution, and "curing time" are important process parameters that will be further investigated.
Demulsification Treatment and Removal of In-Situ Emulsion in Heavy-Oil Reservoirs
Authors: Castro Leo U.
Published: December 2007

Cyclic steam injection has been proven to be an effective method for producing heavy oil from low gravity, shallow reservoirs in the San Joaquin Basin of California. The practice of cyclic steaming, however; can cause formation damage in the reservoir that can severely affect the performance of post cyclic steam production.

Cyclic steam operations introduce a high level of energy into a reservoir, a primary element needed for the formation of stable emulsions in highly porous sands. Other necessary elements such as immiscible fluids, formation fines, and oil-wet surfaces are naturally present in most steamdrive reservoirs. Significant fluid velocities and shear forces during steam cycles combine these elements in the wellbore much like the action of a Waring blender in the laboratory. This leads to the creation of stable in-situ emulsions which can partially, or wholly block the production paths into the wellbore.

The use of a surface active, water-soluble blend of oxyalkylated alkanolamines and sulfonates, has shown dramatic improvement over non-chemically enhanced steam cycles. These treatments, applied during different stages of a steam cycle, have resulted in significant and prolonged increases in incremental production. This paper details the successes associated with these types of treatments, and discusses placement technique, candidate profiling, and chemical selection.
Modern Total Well Management - Sucker Rod Lift Case Study
Authors: McCoy J. N. , Podio A. L. , Drake Bill , Rowlan Lynn
Published: December 2007

Oilfield operators continually need to verify that their wells are being produced at the optimum capacity and in a cost effective manner. An integrated analysis of the pumping system is required to reduce operating costs, increase oil production and increase net income. The integrated analysis of the pumping system must include the performance and interaction of all the elements: the prime mover, surface equipment, well bore equipment, down hole pump, down hole gas separator and the reservoir. This integrated analysis methodology is called Total Well Management, TWM. The TWM analysis is made based on data obtained at the surface without entering the well bore and yields an accurate representation of the conditions existing on the surface, within the well bore and within the reservoir. A field case study of a sucker rod lifted well illustrates the procedure and benefits of the Total Well Management methodology.
Fullfield Numerical Simulation Using Geostatistical Reservoir Model of Upper Main Body "B" Reservoir, Monterey Formation, Elk Hills Field, California
Authors: Hampton Thomas J. , Danielli Corinne , McChesney Don , Singh S. P.
Published: December 2007

This reservoir is located in the southern San Joaquin Valley of central California, about 20 miles west of Bakersfield. The Upper Main Body "B" (UMBB) is part of the Upper Miocene Monterey Formation. This turbidite reservoir was initially under crestal gas injection from 1976 to 1988. The reservoir has been under peripheral waterflood since 1983. An integrated study including reservoir characterization and full field simulation was started in late 1998 to evaluate near term enhancements to production.

Geological mapping and correlation generated nine zones based on logs from 725 wells, 413 with modern log suites, of which 28 were cored. Geostatistical models (~25 million cells) were built with 413 wells for net pay, porosity, and permeability. These models were evaluated with sequential Gaussian simulation (sGs) and cloud transform algorithms on selected "sector" areas. The geostatistical models were upscaled for numerical simulation to allow for realistic process time. The final numerical simulation grid consisted of 240×140×20 cells with ~82,000 active.

The simulation model was built by integrating: 1) PVT data from nine wells, 2) 40+ samples of special core analysis data (relative permeability tables and capillary pressure tables), 3) completion data for 332 wells completed in UMBB, 4) 25+ years of allocated production and injection history, 5) more than 7,000 bottom hole pressure surveys, and 6) repeat formation tests from 43 wells.

Parallel processing with four to eight processors on an SGI ONYX machine significantly cut the run time. Integration and communication between simulation engineer, geostatistician, petrophysicist, and reservoir management team has led to considerable improvements in the simulation model. The combination of this process and intensive cross-disciplinary reservoir characterization resulted in significant time-savings in building the model and simulation history match time. The prediction cases are being utilized for future development planning for the UMBB.
Stimulation of a Producing Horizontal Well Using Enzymes that Generate Acid In-Situ - Case History
Authors: Harris Ralph E. , McKay Ian D. , Mbala Justin M. , Schaaf Robert P.
Published: December 2007

The Libwa 4 well offshore the Democratic Republic of Congo was stimulated in November 1999 using an enzyme-based process that generated acid in-situ. The results to date have been excellent. Well tests as high as 759 BOPD have been recorded after the treatment compared to less than 100 BOPD before the treatment.
Optimising Gravel Pack Performance in a High Rate Gas Development
Authors: Watson R. B. , Patey I. T. M. , Paveley C. , Rushworth P.
Published: December 2007

This paper discusses a reservoir conditions laboratory investigation into the fast track Easington Catchment Area (ECA) Neptune Development which was identified as requiring sand face completion design. During the front-end engineering design phase the initial case accepted for the platform and sub-sea processing facility was zero sand tolerance. Rock mechanical test results suggested that an open hole gravel pack was the best sand face completion option, however many formation damage mechanisms are known to be encountered during well operations.

The emphasis of the paper is to explain an investigation of the design phases of a sand face well completion under laboratory conditions. Therefore, each phase of laboratory testing looked at identifying and reducing formation damage mechanisms prior to well operations. To aid in interpreting permeability results and identifying damage mechanisms, dry and cryogenic Scanning Electron Microscopy (SEM) analyses were performed on samples before and after testing. This interpretation was used to determine whether formation damage occurs within the gravel pack assembly and interfaces or within the core. The advantages of well-designed drilling mud can be ruined by a poor completion procedure. Therefore, throughout the development phase it was strongly emphasized that synergy between the drilling phase and completion was paramount. An operational strategy was then generated from the results, which led to the installation of the sand face completions with minimal formation damage.

After implementing the preferred drilling mud, displacement of the drilling mud, then the associated enzyme and acid treatments post gravel pack operations from the core study, the Neptune Well showed extremely low skins. This production data confirms the importance of laboratory analysis undertaken on representative core intervals as a well performance predictive tool.