bluuebunny/crossref_metadata_2025 huggingface dataset:
Applying a New Systematic and Dynamic UBD Procedure Prevented Formation Damage, Wellbore Collapse and Improved Oil Production in Hassi Massoud Field
Authors: Berkat Ali , Kartobi Khelil , Mazouzi Amine , Dhina Okba , Qutob Hani , Barakat Naiem , Grayson Fudge , Marei Ayman
Published: March 2009

The Hassi Massoud oil field is the largest of its kind in Algeria. The reservoir was discovered in 1956 and produces from a Cambrian-age at approximately 3400 meters depth. It produces 45°API oil from a thick Cambro-Ordovician sandstone formation.

This sandstone is extremely hard, abrasive and slow to drill. The reservoir is naturally fractured in some parts. Fractures are either open or plugged with materials such as shale, silica, anhydrite, pyrite and bitumen. Porosity is ranging from 6 to 12%. Generally, the permeability is low with a range of less than 1 to more than 100 md in open-fractures layers

Sonatrach introduced Underbalanced Drilling (UBD) primarily in an effort to improve penetration rates. However, all additional benefits obtained from UBD, such as production improvement and reservoir characterization while drilling, will be of an added value.

Well OMPZ553 is the 37th well drilled underbalanced in the Hassi Massoud field. In this well, the focus was on production improvement with minimum formation damage while the increased rate of penetration (ROP) was a secondary benefit. Another objective was the evaluation of production while the well is being drilled. This eliminates the need for expensive post drilling production testing, and also to minimize borehole instability specially when drilling in the R2 section of the drain.

In order to increase the success rate of drilling and completing this well underbalanced, Sonatrach introduced a new systematic and dynamic procedure. The new procedure consists of: Proper UBD candidate screeningCalculating the actual reservoir pressure before UB mode startsCompleting the well in UB mode

This well proved to be the best UB drilled well in Hassi Massoud field in terms of reservoir benefits and characterization. The pre-job UBD candidate screening, feasibility studies and applying the new procedures proved effective in the success of this well.

This paper describes in detail the above procedure and presents the successful application of such procedure to optimize production and enhance the ultimate recovery in the Hassi Massoud field. Lessons learnt and challenges encountered will also be discussed in this paper
Chemistry Applied to Fracture Stimulation of Petroleum Wells
Authors: Harris Phillip C. , Sabhapondit Anupom
Published: March 2009

Hydraulic fracturing is a stimulation procedure that is applied to petroleum wells that will not otherwise produce at commercial rates. Hydraulic fracturing employs fluids that are pumped with very low tubular frictional pressure, yet have sufficient viscous properties to generate fracture geometry in subterranean rock and transport solid propping agents to hold the fracture open.

Fluids for commercial fracturing applications contain polymers, crosslinking agents, surfactants, clay-protective agents, and viscosity breakers. All of these must be balanced to result in the physical properties required at elevated temperatures and pressures without damaging the proppant pack or rock formation. Complex chemistry is carefully controlled on a large scale and in a hostile environment for the fracturing process to be successful.

Most fracturing fluids are mixed in aqueous media. One of the polymers used in fracturing is water-soluble polysaccharides derived from natural guar. Crosslinking agents include borate, titanium, and zirconium complex ions. Formation compatibility is enhanced by clay-protective materials, such as potassium chloride and organic salts, with surfactants to lower interfacial tension. Fluids heat up as they travel down the wellbore and into a subterranean fracture. Timing of the crosslink initiation is vital to balance fluid friction in the wellbore and yet obtain proper penetration into the fracture and transport of propping agents. Finally, the viscosity developed by the crosslinked gel is broken with chemical agents to allow the injected liquid to be produced back to the surface.

This paper discusses the development of fracturing fluids and shows how the kinetic reaction of polymers, crosslinking agents, and other chemical components work together to produce the favorable result of stimulating petroleum wells to produce at higher rates.

With the focus of today's oil production moving from the western hemisphere to the eastern hemisphere, new research facilities have been established to apply technology-specific adaptations to the demands of eastern hemisphere reservoirs. These adaptations will improve the efficiency of oil and gas production for the future.
On the Relationship between Electrokinetics and Reservoir Rock Physical Properties
Authors: Alkafeef Saad F. , Zaid Alforgi M. , Alajmi Abdullah F.
Published: March 2009

Numerous investigations have been made of the relationship between formation resistivity factor and porosity of reservoir rocks. One of the most widely used expressions is the familiar Archie equation. This paper presents an investigation of the relationship between electrokinetics and reservoir rock formation conductivity factor and porosity. Electrokinetics is the general term associated with the relative motion between charged solid/liquid interfaces, and has proven to provide direct information on oil reservoir characterizations. The movement of liquid through the capillaries carries a net charge (mobile part of the Electrical Double Layer) and it gives rise to streaming current, consequently, a potential difference (streaming potential). This investigation leads to the determination of formation conductivity factor from the total electric conductivity of reservoir rocks. This was achieved from the estimation of the ratio of the pores' area cross section 'A′ to its length 'L′ by coupling streaming current and streaming potential measurements. The validity of calculated formation conductivity factor from this analysis is established by the use of sandstone data with various porosities. The results are in good agreement with the Humble expression for porosity-formation resistivity factor relationship. These results could prove to be valuable in determining formation conductivity factor from simple and quick measurements of streaming current and streaming potential. The factor can then be used to estimate water saturation in the normal manner.
Controlled Pressure Drilling (CPD) Candidate Screening Methodology
Authors: Villatoro Jaime , Boutalbi Said , Schmigel Kevin , Qutob Hani , van Galen Martijn , Lakshminarayanan Sunil
Published: March 2009

Controlled pressure drilling (CPD) has become the most effective drilling method to improve technical limit drilling time and reduce previously recorded lost time on offset conventionally drilled wells—when it is applied to correctly selected candidates. In addition, specific drilling techniques offered within CPD technology not only improve the time it takes to reach total depth (TD), but also have been proven to optimize reservoir section productivity and maximize economically recoverable reserves. CPD comprises three main techniques: air drilling, underbalanced drilling, and managed pressure drilling. This paper discusses the latest CPD techniques and the non-productive time that it can address.

A methodology to properly screen all CPD techniques to reduce failure/misapplication and align objectives with expectations had been absent. This paper addresses the latest enhancements in an expert system developed to better understand and screen options for CPD operations. The Internet-based selection tool provides guidance by using key indicator questions, beginning with the primary objective(s) for the given wellbore section. If the specific CPD technique is known, the user can activate the online screening tool. The online screening tool considers a range of economic and technical parameters, as applied to algorithms and logic rules, to provide a relative ranking for each candidate of the CPD technique. Sensitivity analysis can also be performed to determine the impact of key uncertain parameters. Additional expert screening and selection methods are available upon the completion of the online CPD candidate selection process. The paper provides an overview of the Internet-based tool and methodology, in addition to supporting case histories.
Review and Outlook of Subsurface Acid Gas Disposal
Authors: Carroll John J. , Griffin Peter J. , Alkafeef Saad F.
Published: March 2009

Acid gas primarily is a mixture of carbon dioxide and hydrogen sulfide and is a byproduct of the sweetening of natural gas. Acid gas injection (AGI), an environmentally friendly method of dealing with the acid gas, is basically the compression of a low-pressure stream to sufficient pressure to achieve injection. The fluid is transported via pipeline to an injection well where it travels downward into a selected injection reservoir. AGI is a mature technology on a small scale (less than 283×103 SmVd [10 MMSCFD] of injected fluid). In addition there are a few injection schemes on a medium scale (less than 2125×103 SmVd [75 MMSCFD]). Some producers are now considering injection on a larger scale (greater than 2125×103 Sm3/d [75 MMSCFD]). Many of the principles used to design the small and medium sized injection schemes can be transferred to the larger schemes. However the larger injection schemes pose new challenges. In this paper the state of the art for AGI is reviewed. The main difference between the current injection schemes and some of those proposed is the volume of fluid to be injected. Some of the newer projects are suggesting the injection of significantly larger volumes than are currently being injected. Some of the differences between the small and large-scale injection schemes are discussed. The main focus of this paper is on the surface facilities, but wells and the injection reservoir are also discussed.
The Oil Compressibility Below Bubble Point Pressure Revisited–Formulations and Estimations
Authors: Al-Marhoun Muhammad Ali
Published: March 2009

Oil compressibility plays an important role in reservoir simulation, material balance calculations, design of high-pressure surface-equipment and the interpretation of well test analysis, specifically for systems below the bubble point pressure. Accurate information on the oil fluid compressibility above and below bubble point pressure is very important for reservoir evaluation.

The conventional definition of the isothermal oil compressibility below bubble point pressure is being questioned on its scientific merit and challenged against the basic compressibility definition and the general trend of physical behavior of compressibility. This paper presents a new derivation based on the basic compressibility definition to calculate the oil compressibility below bubble point pressure. The experimental data obtained from flash and differential liberation tests is utilized to determine the isothermal oil compressibility values.

It is found that the oil and gas compressibilities below original oil bubble point pressure computed in the conventional method may lead to errors in reserve estimation for saturated reservoirs and skin factor in well test analysis.
Geomechanical Characterization of a Sandstone Reservoir in Middle East—Analysis of Sanding Prediction and Completion Strategy
Authors: Mohiuddin M. A. , Najem M. M. , Al-Dhaferi Y. R. , Bajunaid H. A. , Tan C. P.
Published: March 2009

Sanding problems are often observed in fields after a period of relatively smooth operation. These occurrences usually coincide with an increase in depletion, water cut, or changes in the artificial lift mechanism used to produce the hydrocarbon. Sanding is detrimental to optimum field development and therefore, information about the possible advent and extent of sanding will be helpful in planning for completions and facilities.

The study presented in this paper characterizes the geomechanic behavior of a field in which sanding problems are expected after depletion, increase in water cut, and installation of ESPs to optimize production. To accomplish this task, a 3D full field model was created. First, several 1D Mechanical Earth Models (MEMs) were developed. These 1D MEMs were calibrated using drilling data, laboratory measurements, well tests and other field measurements. The calibrated rock mechanical properties from the 1D MEMs were distributed in the 3D model using Gaussian sequential simulation technique. The populated 3D model was then used to perform a coupled geomechanical simulation to evaluate the changes in stress with time and production.

The rock mechanical properties and stresses needed to perform sanding analysis were sampled along the well trajectories from the 3D model. Sand production prediction analysis was subsequently undertaken using a field proven sanding prediction model that accounts for scale effects associated with different perforation size and sand grain diameter, and plasticity effects that modify the strength behavior of sands surrounding open holes and perforations during drawdown and production. The sanding tendency predicted from sanding analysis was corroborated with field observations. This was also used to calibrate the 3D model and formulate a completion strategy to minimize sand production for the life of the field. The completion strategy optimizes the production using ESPs while minimizing sand production.
Development of a Full-Field Parallel Model to Design Pressure Maintenance Project in the Wara Reservoir, Greater Burgan Field, Kuwait
Authors: Ma Eddie , Williams Lee , Ambastha Anil , Al-Naqi Meqdad
Published: March 2009

The Wara reservoir is one of the four main reservoirs in the Greater Burgan field, the world's largest sandstone oil field. It has experienced significant pressure decline after 60 years of primary production. In 2005, design for a pressure maintenance project (PMP) via a peripheral waterflood was initiated to arrest pressure decline and improve oil recovery.

A key building block of the Wara PMP is a stand-alone, full-field Wara simulation model. The 23-million cells geological model was scaled-up to 4 million cells for flow simulation. Four pseudo layers were added to the simulation model to allow fluid migration via faults from the lower reservoirs. The new model has 100 m x 100 m areal cells and individual layers with an average thickness of 6 ft. Overall, this new model has 18 times refinement compared to the previous model for the Wara reservoir. Thus, this model is suitable for evaluating PMP, infill drilling and pattern waterflood. This paper, however, focuses on PMP evaluation only carried out over the last four years.

The final history-match has been carried out at three levels: Field, Gathering Centers (GC) and Key Wells. Detailed study of interactions among field permeability distribution, edge aquifer representation, and fault transmissibility specifications on simulation results was key in developing a meaningful history-match. PNC data for many wells around the periphery of the field provided useful insights for edge aquifer representation. Water cut match was less than satisfactory for wells located in the center due to modeling deficiency of pseudo layers as discussed in the body of the paper.

Prediction runs have been set up to investigate various PMP designs. These runs include sensitivity with respect to number of injectors, number of producers, target injection rate per well, maximum bottom-hole injection pressure, voidage replacement ratio, injector-producer distances, and injector-producer rows along with various scenarios for dealing with production from existing Wara producers throughout the field. This flow simulation model will be used as an operating model to optimize process design and well location.
Opportunistic Fluid Sampling and Analysis to Track Reservoir Souring in Water Flooded Operations in North Kuwait Reservoirs – Implications for the Future
Authors: Al-Marri Salem , Alkafeef Saad , Chetri Hom , Al-ghabdan Asma'a
Published: March 2009

Reservoir souring while water flooding North Kuwait reservoirs has been predicted by modeling studies in the past. One of Sabiriyah Mauddud wells showed up H2S as first indication of reservoir souring, which was an alarm bell for production facilities designed for only sweet crude. Surface/ Bottomhole fluid samples were required to confirm whether it is localized or reservoir-wide. In order to track reservoir souring and monitor on continuous basis, a process for tracking of reservoir souring annually was developed and initiated for the first time in 2006. Subsequently, this has been made part & parcel of fluid study requirements each year.

As sea water is being injected into traditionally sweet reservoir like Sabiriyah Mauddud, some degree of reservoir souring is expected due to Sulfate reducing bacterial (SRB) activity, as was projected happen sometime in 2005 in wells, needing monitoring/ mitigation actions. Expected H2S levels being very low (50–200 ppm), risk of loosing and not capturing these concentrations using conventional samplers/ bottles due to absorption/ reaction with the metallurgy of the samplers was felt, thus posing a challenge for obtaining a representative bottomhole sample for the analysis of H2S.

A comprehensive sampling program was made jointly by KOC & KISR, using the non-reactive internally coated samplers for capturing bottom hole samples; performing the onsite analysis, followed by immediate shipment to the local fluid analysis laboratory and conduct all necessary analysis with expert supervision & care.

Value was added to North Kuwait Water flood management by timely knowing the onset of reservoir souring. The analysis also led the way forward for the review of chemicals dosages; interventions needed in case of H2S occurrence; inputs to the future facilities and the requirements of further modeling studies.
Increased Certainty in the Determination of Zonal Isolation through the Integration of Annulus Geometry Imaging and Improved Solid-Fluid Discrimination
Authors: Al-Suwaidi A. S. , Al-Marri Faisal M , Sultan Emad , Ibrahim Moh'd El-Sayed , Jammeli Kamal , Al-Kindi Zaid , Elkadi Antoine
Published: March 2009

The zonal isolation behind casing was critical during a major field development project in the Middle East. However, the assessment whether the cement bond will hold against hydraulic communication or not has not always been an easy task; slurry contamination during pumping, slurry invasion by formation hydrocarbons especially gas, channeling through the cement sheath, patchy cement, annulus shape and casing excentralization inside the outer wellbore are all factors that have traditionally made it difficult and sometimes even impossible to judge the zonal isolation behind casing between various zones of the reservoir.

A new approach was adopted for the assessment of the cement bond behind casing in this project. The technique combines the conventional "pulse – echo" ultrasonic measurement with that of a newly introduced flexural waveform. The analysis from this combination allows a better discrimination between solid, liquid and gas behind casing and it also provides, for the first time, a comprehensive assessment of the annulus shape and casing centralization inside open hole or inside the second casing string. This latter casing stand-off measurement has proven to be instrumental when deciding whether the cement sheath will hold against hydraulic communication or not.

In this paper we will discuss the data that was acquired in four wells from this project. We aim at proving the clear benefit of this new approach for the assessment of zonal isolation behind casing.
Gas Condensate Relative Permeability of Low Permeability Rocks: Coupling Versus Inertia
Authors: Jamiolahmady M. , Sohrabi M. , Ireland Shaun
Published: March 2009

Flow around the wellbore of gas-condensate systems, when pressure drops below dew point, is controlled by complex interaction of capillary, viscous and inertial forces. Hence, accurate determination of gas-condensate relative permeability (kr) that is affected by relative impact of these forces is challenging.

There are a number of reports demonstrating kr of high permeability rocks affected by both coupling (the increase of kr as velocity increases and/or IFT decreases) and inertia (i.e., the reduction of kr as velocity increases) for these low IFT systems. However, there is little information on this subject for low permeability rocks.

In this work, we report and analyze a series of steady state kr for a 3.9 mD reservoir rock with low porosity of 6% measured using our unique experimental facilities. These data have been measured at three IFT below one mNm−1 and five velocity levels below 200 md−1.

The results indicate that at the highest IFT, inertia is dominant at low condensate to gas flow rate ratio (CGR) whereby kr reduces with increasing velocities. At higher CGR, an increase in kr is observed due to the dominant effect of coupling. At lower IFT, the negative impact of inertia on kr as velocity increases is observed at all CGR. We have recently reported kr of highly conductive propped fractures showing a more pronounced effect of inertia at lower IFT but this is the first report of such behavior for low permeability rocks. We also compare the results with the corresponding predicted kr by the generalized kr correlation, which we reported recently and expresses the combined effect of coupling and inertia with universal parameters. The unique contribution of inertia, as observed in the experiments and predicted by the correlation, is mainly attributed to impact of the single-phase inertial factor and fluid properties.
Experimental Evaluation of Heavy Oil Recovery by Hot Water Injection in a Middle Eastern Reservoir
Authors: Alajmi Abdullah F. , Algharaib Meshal , Gharbi Ridha
Published: March 2009

With the increase of oil demand worldwide and current oil price, the recovery of heavy oil deposits became a major issue in the oil industry. Overcoming the challenges and complexity associated with the production of these deposits has been the target and focus in recent years. Large quantity of hydrocarbon deposits remains unrecovered due to the high viscosity of oil. Thermal recovery processes are techniques used to reduce the oil viscosity and enhance the oil recovery by introducing heat to the underlying reservoirs. Hot water injection is a thermal recovery technique in which water is injected into hydrocarbon strata. The hot water injection reduces the viscosity of the heavy oil and provides a driving mechanism to sweep the heavy oil toward production wells. In this work, the application of hot water injection in a Middle Eastern reservoir with large heavy oil deposits was investigated. The reservoir's heavy oil had a viscosity of 500 cp and an initial oil saturation of 75%. Two-phase fluid flow displacement experiments were conducted. The objective was to find the optimum design parameters in terms of injection temperature and hot water slug size that would yield to the best performance. The results obtained from several design configurations are presented. These configurations include hot water floods with different slug sizes and sequences. These results can be used as a tool for the successful design of hot water injection to recover heavy oil in these types of reservoirs. In addition, they provide the condition under which a given design may yield better recovery performance.
Pressure Behavior of Horizontal Wells in Dual-Porosity, Dual-Permeability Naturally Fractured Reservoirs
Authors: Lu Jing , Zhu Tao , Tiab Djebbar
Published: March 2009

This paper presents pressure bahavior of horizontal wells in dual-porosity, dual-permeability naturally fractured reservoirs. The proposed equation is obtained by double Fourier transformation and Laplace transformation. The results calculated for combinations of various dimensionless characterizing parameters, including the permeability ratio between matrix and fracture systems, have revealed the unique behavior of naturally fractured reservoirs when the flow state within the matrix blocks is taken into account. It is concluded that, for the flow within matrix blocks will weaken the essential nature of fluid flow through a dual-porosity, single permeability medium revealed by Warren-Root model. This paper also presents the application of "Tiab's Direct Synthesis" to horizontal wells in an infinite acting dual-porosity, dual-permeability naturally fractured reservoirs with pseudo-steady state interporosity flow.
Steady-State Productivity Equations for a Multiple-Wells System in Sector Fault Reservoirs and Channel Reservoirs
Authors: Lu Jing , Zhu Tao , Tiab Djebbar
Published: March 2009

Currently in the oil industry, pseudo-steady state productivity equations for a multiple wells system are used in all reservoir systems, regardless of the outer boundary conditions. However, if the reservoir is under edge water drive or with infinite lateral extension, pseudo-steady state is no longer applicable. When producing time is sufficiently long, productivity equations based on the steady state are required.

This paper presents steady-state productivity equations for a multiple-wells system in homogeneous, anisotropic sector fault reservoirs and channel reservoirs. Taking fully penetrating vertical wells as uniform line sinks, and solving a square matrix of dimension n, where n is the number of wells, simple, reasonably accurate multiple-wells system productivity equations are obtained. The proposed equations which relate the production rate vector to the pressure drawdown vector provide a fast analytical tool to evaluate the performance of multiple wells, which are located arbitrarily in a sector fault reservoir or a channel reservoir. This paper also gives an equation for calculating skin factors of each well.

It is concluded that, for a given number of wells, well pattern, anisotropic permeabilities, skin factor, pressure difference between reservoir outer boundary and flowing bottomhole pressure, have significant effects on single well productivity and total productivity of the multiple-wells system. In a sector fault reservoir, the production rates are increasing functions of the sector angle; in a channel reservoir, the production rates are increasing functions of the reservoir width.
Use of Exclusion Zones in Mapping and Modeling Fracture Corridors
Authors: Ozkaya Sait I.
Published: March 2009

Fracture corridors are sub-vertical tabular fracture clusters which are associated with faults, or originate as incipient faults. Fluid conductive fracture corridors may have significant permeability and profoundly affect reservoir flow dynamics.

Mapping fracture corridors requires (i) locating fracture corridors and assigning to them (ii) length, (iii) orientation and (iv) fluid conductivity. Estimation of orientation and especially length is a major challenge in fracture corridor modelling. Exclusion zones may aid both in locating fracture corridors and assigning orientation and length. An exclusion zone is an area which can not have a conductive fault or fracture corridor passing through.

Exclusion zones around vertical wells are defined mainly by well tests and remaining oil column thickness. Borehole image logs, wells tests, lost circulation and openhole logs define exclusion zones in horizontal wells. A vertical well test with homogeneous matrix can not have a fluid conductive fault / fracture corridors within the circle of investigation. Oil column thickness can be estimated from a combination production logs, water cut history or from recent openhole or surveillance logs. Wells with thick remaining oil column and no water sweep can not have a nearby fluid conductive fault or fracture corridor. Horizontal wells with image logs or openhole logs showing no conductive fault/fracture corridor indicate an exclusion zone around the well where no faults or fracture corridors can pass through.
Improvement of Geologic Exploration Efficiency in Mature Oil and Gas Provinces
Authors: Khisamov R. S. , Bazarevskaya V. G.
Published: March 2009

Approaches and methods for oil and gas exploration have improved significantly with maturing of major oilfields.

At the initial stage of geologic exploration in Tatarstan prospects were identified by single coverage reflection profiling and structural drilling. The accuracy of these methods sufficed to identify large anticlinal closures. Efficiency of geologic drilling to evaluate the potential of deep intervals was rather high at that time, 88%.

In 1980-ies Tatarstan witnessed a wide-scale development and application of 2D seismic methods to search for small oil habitats, structural and lithologically-screened structural pools. The discovery ratio of prospects identified with 2D seismics in Tatarstan in 1980-ies reached 72–95%, in the Volga-Ural oil and gas province 12–89%, in Russia–20%.

At the initial and medium stages of exploration of zones with proved oil and gas potential primary objectives are structures with areal extent not less than 5 sq. km and closure at least 15 m. At mature stage of exploration (Republic of Tatarstan) primary targets are features with areal extent 0.5–1.0 sq. km and 5–10 m closure. Complicated geologic and economic environment attributed to exploration of deep carbonate pools, complex trapping mechanism, small-size and small-closure anomalies necessitated improvement of geologic prospecting methods.

Nowadays Tatneft Company successfully uses the technology of forecasting of local hydrocarbon accumulations based on a package of 2D and 3D seismic prospecting and non-conventional exploration methods, the major advantage of which is low costs.

So, lately in its exploration activity both on Tatarstan territory and in its license areas, Tatneft Company has been widely using advanced methods of geologic prospecting including investigation of seismic prospects with the help of neural network (NEUROSEISM system), geophysical and gas geochemical exploration methods, electromagmetic (EM) sounding, low-frequency seismic sounding, geochemical survey (Gore Sorber), and a number of others.
The Key Challenges for Optimization of a Tight Gas Field Developments Using a Multidomain Integrated Process: Application in a Mature and Emerging Environments (North America and Middle East)
Authors: Aly Ahmed , Ramsey Lee
Published: March 2009

As gas demand rises and operators turn to tight gas reservoirs for new supplies, the need to optimize the capacity and recovery potential from this type of reservoir has risen.

In this environment, a multidomain integrated process enables the data and activities of multiple domains to be integrated for single-well completion optimization and field geocellular and simulation modeling. Through this process, various development scenarios for completions and drilling locations can be systematically and rigorously analyzed.

Case studies from North America and the Middle East show applications of this process in two different environments, one mature and one emerging. The case from North America illustrates a use of the proposed process in a high-volume field development and the value of applying new technology to optimize the process until it reaches a "SMART"-factory-like workflow. With our new process, new technology can be integrated with adaptive modification to the factory mode. This approach will identify the development process that will result in the highest recoveries while maximizing the net present value from the asset. Alternatively, the case from the Middle East shows the application in a gas-condensate, tight gas reservoir in an emerging area. The challenge in this case is in collecting adequate necessary data early enough to plan for optimal development. Our case shows the value of collecting the key data early in a complex, tight gas environment and how early collection can impact the development later and avert costly decisions. Also, the special nature and cost of mobilization and limited equipment introduce a need for more stringent early collection of data (e.g., formation evaluation, core, fluid, geomechanics, etc.) that impacts our development before we start the project. This project illustrates the challenges of the developments in a new environment where the services and technology have not matured to the North America levels.

A key conclusion of the paper is that applying the field management process in both environments (North America and the Middle East) has resulted in significant improvements in production optimization, as well as in single-well and field development planning.
Rock Typeand Permeability Prediction of a Heterogeneous Carbonate Reservoir Using Artificial Neural Networks Based on Flow Zone Index Approach
Authors: Kharrat Riyaz , Mahdavi Ramin , Bagherpour Mohammad Hashem , Hejri Shahab
Published: March 2009

The Cretaceous carbonates of Sarvak formation formed large hydrocarbon reservoirs in the South-west region of Iran. The studied field is a tight carbonate reservoir in which several exploration wells have been drilled, and is in the process of development. Since, only few wells have core data, therefore it was decided to integrate the available core and log data using new methods that describe the carbonates heterogeneity more precise.

3D modeling of permeability is an essential part of building robust dynamic model for proper reservoir management and making reliable predictions. A good definition of reservoir rock types (RRT) could relate somehow better geological modes to dynamic models. Rock typing by flow-zone-index (FZI) and rock-quality-index (RQI) values proved to be an effective technique to develop porosity-permeability transforms for RRTs in a reservoir model.

RRTs were defined based on the core derived FZI through some mathematical and statistical approaches. Permeability estimation using artificial neural network approach (ANN) was then made through a two-step process. In the first step, FZI log was estimated from a trained neural network using the standard suite of logs as input (Gamma ray, Sonic, Density, Neutron porosity) and FZI-core as output in a subset of cored wells (Key wells). In the second step, individual trained neural networks implemented porosity-log and FZI-log from the first step to predict permeability-log for each RRT.

Validation of the predictive capability of the method in two cored wells (Blind-test wells) that are located in the field proved the estimation technique to be robust and was found to be valuable to supplement core data in the prediction of log-permeability in the entire reservoir wells.

For the sake of comparison between the result of this work and the work which was based on the integration of sedimentological, petrographical, and diagenetic study, the results were found to be in good agreement for most of the log interval. However, the predictions of the ANN approach in the regions where core data are not available are better and it follows the log property variation logically.
Unstructured Coarse Grid Generation for Reservoir Flow Simulation Using Background Grid Approach
Authors: Yadecuri M. Evazi , Mahani H.
Published: March 2009

Reservoir flow simulation involves subdivision of the physical domain into a number of gridblocks. This is best accomplished with optimized grid point density and minimized number of gridblocks especially for coarse grid generation from a fine grid geological model.

In any coarse grid generation, proper distribution of grid points, which form basis of numerical gridblocks, is a challenging task. We show that this can be effectively achieved by generating a background grid that stores grid point spacing parameter.

Spacing (L) can be described by Poisson's equation (∇2L = G) where the local density of grid points is controlled by a variable source term (G). This source term can be based on different grid point density indicators such as permeability variations, fluid velocity or their combination e.g. vorticity, where they can be extracted from reference fine grid. Once background grid is generated, advancing front triangulation and then Delaunay tessellation are invoked to form the final (coarse) gridblocks. This algorithm is quite flexible, allowing choice of the gridding indicator and thus providing the possibility of comparing the grids generated with different indicators and selecting the best.

In this paper, the capabilities of approach in generation of unstructured coarse grids from fine geological models are illustrated using a highly heterogeneous test case. Flexibility of algorithm to gridding indicator is demonstrated using vorticity, permeability variation and velocity. Quality of the coarse grids is evaluated by comparing their two-phase flow simulation results to those of fine grid and uniform coarse grid. Results demonstrate the robustness and attractiveness of approach, as well as relative quality/performance of grids generated by using different indicators.
Steamflood Piloting the Wafra Field Eocene Reservoir in the Partitioned Neutral Zone, Between Saudi Arabia and Kuwait
Authors: Barge David , Al-Yami Falah , Uphold Don , Zahedi Alireza , Deemer Art , Carreras Patricia E.
Published: March 2009

The concept of steamflooding the Wafra Eocene dolomite reservoir originated in various studies conducted in the 1980's. In 1999, a comprehensive EOR study and Eocene huff-n-puff pilot suggested that steamflooding could be a viable recovery process for the reservoir. As a result of these studies, a staged development approach was incorporated to test the viability of pattern steamflooding the Eocene reservoir. The objective was to assess key technical challenges associated with steamflooding an anhydrite and gypsum rich carbonate reservoir. Additional challenges were the lack of fresh water available for steam generation, high concentrations of hydrogen sulfide gas, and higher reservoir pressures compared to most active steamfloods. The staged approach called for a single pattern steamflood test followed by a larger multi-pattern pilot. As a result of this strategy, a single pattern steamflood test was implemented in 2006.

The design and initial performance of the small scale test (SST) single pattern steamflood pilot in the Wafra 1st Eocene reservoir are described in this paper. The pilot is comprised of one, 1.25 acre inverted five-spot pattern, consisting of four producing wells, a single injector and a single observation well. Continuous steam injection began in February 2006 at a rate of approximately 500 barrels per day cold water equivalent, 600 psig and a temperature of 489 ºF.

The primary goals of the single pattern test were to test application of a mechanical seeded slurry evaporator to process produced water for steam generation and to assess steam injectivity into dolomite reservoirs containing gypsum and/or anhydrite. Injectivity assessment included evaluating reservoir response to steamflooding and investigating the variation over time due to rock/fluid interactions. Secondary objectives included analyzing well productivity and evaluating well testing equipment, facilities, and well construction. The SST has a comprehensive data collection and surveillance plan to support evaluation of these goals and objectives. The surveillance plan includes the collection of pre-flood and post-flood core data, frequent well testing for rates and fluid compositions, daily temperature recordings and periodic logging.

After two years of operation, primary goals have been tested and exceeded expectations. A continuous thermal zone was developed in the 1st Eocene reservoir and steam breakthrough occurred at several of the producers. Generator feed quality water was produced at maximum throughput rate of 1,200 bwpd via mechanical seeded slurry evaporator equipment. Secondary objectives are currently being assessed with focus on current challenges of corrosion and scaling of producing wells.
Challenges of Producing Middle East Oilfields During the Maturation Stage—A Paradigm Shift
Authors: Mahroos Faisal Al , Zubari Hisham
Published: March 2009

The Middle East oil fields provide an important energy source for the world. They hold two-third of the world oil reserves (Figure: 1, Table: 1), provide one-third of the world's oil supplies and have the highest Reserves to Production ratio in the world of 821. Even though most of the Middle East oilfields are still prolific, many are already approaching the end of their primary stages as evident by increasing trends in water and gas productions. This is a natural process caused by maturation whereby a depleting oil reservoir looses its energy which results in oil productivity decline associated with intrusion of aquifer water and gas cap gas, when present. The challenge would be to transform the operation from Primary production to Secondary and Tertiary. This not only requires a change in the operation, but also a paradigm shift in reservoir management style and approach. This requires the identification of the pertinent issues and challenges that need to be resolved early and subsequently setting a roadmap plan to investigate, experiment and devise solutions. It also requires a quick, efficient and effective decision making process supported by modern corporate management style.

In this paper we attempt to document the Primary to Secondary and Tertiary transition experience based on the 77 years old Maturing Bahrain Field which was the first oil discovery in the southern part of the Arabian Gulf. The paper does not discuss in detail the decision making process and the corporate management styles of mature field operation.
Prediction of Wellbore Stability Using 3D Finite Element Model in a Shallow Unconsolidated Heavy-Oil Sand in a Kuwait Field
Authors: Ahmed K. , Khan K. , Mohamad-Hussein M. A.
Published: March 2009

As a part of field development campaign to produce heavy-oil from a shallow sandstone reservoir, among vertical wells, drilling of horizontal wells was considered as an option. However, due to the weak and unconsolidated nature of the reservoir sand, the stability of horizontal wellbore during drilling was considered a major unknown. The stability of rock around the wellbore during drilling is function of several factors including rock strength, in situ stresses, pore pressure and drilling parameters. Integration of a wide variety of data into a geomechanical analysis is required for wellbore stability predictions.

A comprehensive geomechanical study of the unconsolidated sandstone reservoir was conducted by incorporating data from six vertical offset wells in order to constrain the contemporary state of stress and rock strength profiles as a function of depth. The aim of the study was to evaluate the risk of hole stability during drilling, recommend a mud weight for drilling upcoming horizontal wells and to suggest azimuths along which horizontal wellbores will be more stable during drilling and production.

To closely simulate the actual stress state and rock deformation around the wellbore during drilling, a 3D Finite Element-based wellbore model was built. The analysis was performed for a range of mud weights to analyze the sensitivity of wellbore stability to mud weight variations. Based on the study, a mud weight was recommended to drill the planned horizontal wells. In addition, the analysis implied that for the observed stress state in the study field, horizontal wells oriented sub-parallel to the minimum horizontal in situ stress would be more stable during drilling and production compared to those oriented sub-parallel to the maximum horizontal in situ stress.
Potential Applications of CO2-EOR in the Middle East
Authors: Algharaib Meshal
Published: March 2009

Anthropological CO2 emissions to the atmosphere are identified as a major driver for the global warming effect. Major CO2 emissions sources are located within power and industrial sectors where fossil fuels are consumed to generate energy. With the anticipated escalation of global energy demand, CO2 emissions are also expected to grow. Therefore, reducing CO2 emissions to atmosphere is a fatal issue worldwide. Capturing CO2 from emissions sources and injected into safe geological places for storage shows a practical mitigation strategy through CO2 Capture and Storage (CCS) practices. In CCS projects, several options are available for CO2 storage such as subsurface aquifers, coalbed bed methane formations, or depleted oil and gas reservoirs. Alternatively to these storage places, CO2 can be utilized to enhance oil production from mature oil reservoirs. Utilization of CO2 in enhanced oil recovery techniques (EOR) is a well known practice in oil industry. Therefore, synchronizing between the objectives of storing CO2 and enhancing oil production to meet global demand can be achieved through CO2-EOR projects.

The giant oil reservoirs in the Middle East represent potential places for CO2-EOR projects. In this paper, oil reservoirs located in the Middle East are selected to evaluate the potential of CO2-EOR projects in the region. These reservoirs were subjected to CO2-EOR screening where the fluid and rock properties are compared with a well known criteria. Furthermore, an analytical model is used to predict the performance of CO2-EOR in these reservoirs. The results showed that implementing CO2-EOR practices would enhance the oil recovery while storing a considerable amount of CO2 in these reservoirs
Field Experiences Detailing Acrolein (2-propenal) Treatment of a Produced Water Injection System in the Sultanate of Oman
Authors: Horaska D. D. , Penkala J. E. , Reed C. A. , Law M. D. , Gaffney S. H. , Srour M. M. , Al-Harthy Abdulla Salim
Published: March 2009

Acrolein represents a unique chemical approach to resolving water quality and injectivity problems resulting from bacteria and sulfides in secondary recovery systems. The key to this approach is three-fold: Acrolein is a potent microbiocide; it scavenges hydrogen sulfide (H2S); and it dissolves iron sulfide (FexSy). In the subject field trial, a 9-fold improvement in water quality and a 16% increase in injection water rates were achieved.

This paper presents the results of a 9 week field trial of acrolein that was conducted using a batch application protocol in a 9,000 m3/day produced water injection system in a Petroleum Development Oman (PDO) field in the Sultanate of Oman. The results indicated a 90% reduction in planktonic sulfate reducing bacteria and 72% reduction in planktonic general aerobic bacteria over the course of the trial. Concentrations of dissolved H2S were lowered by 50%, with a consequent downward trend in oil-free suspended solids (OFSS). The impact on injection water quality was significant, reflected by a 9-fold improvement in Barkman and Davidson slope test results. The average total water injected per day increased from 9,019m3 to 10,442m3 (16%) over the duration of the trial. These findings are discussed in the context of best practices for injection water system management.