bluuebunny/crossref_metadata_2025 huggingface dataset:
Effectiveness of Intelligent Completions in a Multiwell Development Context
Authors: Yeten B. , Jalali Y.
Published: December 2007

We examine the behavior of a pair of matching horizontal wells, producing an oil column bound by a gas cap and an aquifer, to determine the impact of certain drilling and completion decisions on reservoir and production performance. We consider a well configuration that can be characterized as multiply parallel. The two wells are aligned in parallel fashion, are parallel to any two opposing no-flow boundaries (and equidistant from the other two) in a nearly square drainage area, and are in the same plane parallel to the initial gas-oil contact (GOC) and water-oil contact (WOC) planes. We examine the problems of well spacing, vertical placement, and directivity/orientation, in relation to instrumentation. Instrumentation, comprising downhole flow monitoring and control – when control is effectuated in an anticipatory mode – has an influence on the optimum placement between the initial fluid contacts, when optimum is defined in terms of cumulative recovery within a prescribed operational envelope. Operational envelope is defined by constraints on withdrawal rate, bottomhole pressure (BHP), gas/oil ratio (GOR), and forecast duration. Instrumentation of one well enhances also the performance of the adjacent well, and this effect is reinforced when both wells are instrumented. In the latter case, it is immaterial to recovery whether the wells are aligned in the same or opposing directions – introducing a degree of freedom for drilling/infrastructure planning -- and opposing directivity only partially compensates for lack of instrumentation in one or both wells. Stated results hold when each well is centrally located in its respective half-region, which is the spacing yielding the highest recovery; as spacing decreases the influence of instrumentation on vertical positioning weakens and its interchangeability with directivity strengthens. These results can be explained in terms of the limiting hypothesis of zero spacing, which is equivalent to a doubling of withdrawal rate for a single well. The latter increases the frictional losses in the wellbore, accentuates the coning problem, limits vertical maneuvering, and approaches the performance of two oppositely directed nearly coinciding wells—each producing at half-rate. The observation that the effectiveness of instrumentation depends on the severity of frictional losses in the horizontal conduit vis-a-vis the maximum drawdown at the sandface1 is thereby extended by the aforementioned friction-spacing interrelationship. Instrumentation is effective in the region bound by no coning and extreme coning; the latter being exemplified in this case by a virtual/ultimate doubling of withdrawal rate. The friction-drawdown interplay therefore provides a basis for screening candidates for instrumentation under the scenario of noncommingled production.
Cased Hole Formation Resistivity Tool Trial
Authors: Gyllensten Asbjorn , Boyd Austin
Published: December 2007

In the past hydrocarbon saturation have been monitored behind casing by pulsed neutron capture (PNC) logs. These tools have been quite successful in our environment onshore Abu Dhabi characterized by good porosity carbonate reservoirs with high salinity waters.

The ability to measure formation resistivity directly through casing in monitoring wells adds a new dimension, by allowing the measurement of water saturation further away from the borehole, less affected by the "damaged zone" invaded by mud filtrate and drilling fines. Until recently, resistivity logging in cased hole has been restricted to Induction logs in fiberglass lined wells. New advances in digital electronics has made it possible to produce the sufficiently accurate and stable downhole sensors required to measure formation resistivity through steel casing. The first Middle East trials of a new Cased Hole Formation Resistivity Tool (CHFR) took place in 1999/2000 in several ADCO wells.

Monitoring fluid saturation changes and movement in fluid contacts with time, including the identification of swept zones, barriers to flow and bypassed oil are the main applications for the CHFR. With a greater dynamic range than PNC-logs, the CHFR will complement data from sponge cores and open hole logs in swept zones, leading to more robust ROS determination.

The CHFR may also be used for primary evaluation, where no logs could be acquired in open hole, and allows re-examination of wells with old resistivity logs.

In low resistivity where the CHFR is near it’s specified limit of 1 Ohmm, the effects of resistive cement behind casing become important and require careful correction. PNC-logs are favored in this low resistivity range.

Field logs obtained in this trial will be presented and discussed in the paper.
Evaluating Uncertainty in Archie's Water Saturation Equation Parameters Determination Methods
Authors: Hamada G. M. , AL-Awad M. N.
Published: December 2007

Early in the life of reservoirs, it is required to estimate accurately hydrocarbon volumes in place. Modified Archie formula (Sw = (a Rw / φm Rt)1/n) is the basic equation to calculate water saturation. The exactness of water saturation value for given reservoir conditions depends on the accuracy of Archie parameters a, m and n. The terms of Archie relationship have been subjected to many laboratory investigations and even more speculation. There are many factors affect porosity exponent, m, saturation exponent, n and tortousity factor, a. Therefore, it is very difficult to fix Archie parameters regardless of reservoir characteristics; rock wettability, formation water salinity, permeability, porosity and fluids distribution.

This paper presents a new technique to determine Archie parameters a, m and n. The developed technique is based on the concept of three dimensional-regression (3D) plot of water saturation, formation resistivity and porosity. 3D method provides simultaneous values of Archie parameters. Also, 3D method overcomes the uncertainty problems due to the separate use of formation resistivity factor-porosity and water saturation equations to get a, m and n parameters.

Two field examples are given to show the applicability of 3D method and three other methods: 1) common values of Archie parameters, 2) conventional method and 3) core Archie parameter estimation (CAPE) method. The comparison between the four methods has shown that 3D method provides an accurate and physically meaningful way to get Archie parameters a, m and n for given core samples. Water saturation profiles, using Archie parameters deduced from the four methods, have been produced for the studied section in the wells. These profiles have shown a significant difference in water saturation values. This difference could be mainly attributed to the uncertainty level for Archie parameters from each method.
New Drilling System Brings Significant Improvements to Drilling Performance and Hole Quality in Middle-East Fields
Authors: Dahche Ali M. , Swick Stewart , Russell Richard
Published: December 2007

A unique combination of a matched, steerable, positive-displacement motor and a long gauge PDC bit has recently been introduced. The system was initially designed to address problems of high vibration which were known to be causing downhole tool failures. As the design elements of the system were developed it was realised that many of the problems being attributed to downhole vibration were related to hole quality issues such as borehole spiraling. A new system was designed to alleviate this problem. The new system, known as SlickBore TM, used a specially-designed steerable motor and a long gauge PDC bit that, together, retain the steerability of a conventional motor/bit system. SlickBore improved overall drilling efficiencies such as hole cleaning, excessive torque and drag, and poor ROP when sliding. Extensive field tests and subsequent commercial applications have clearly demonstrated the increased efficiencies of this system.

The majority of the initial runs with SlickBore were completed in clastic sequences in the North Sea, Gulf of Mexico, and Far East. When introduced to the Middle-East, the system’s performance in the predominantly carbonate sequences of the Arabian Gulf was unknown. Subsequent runs, however, have proved the system’s benefits also apply to these formations.

This paper will discuss the theories behind the design of the system and provide examples of the improved performance seen in the carbonate formations of Abu Dhabi.
New Application of Impregnated Diamond Bit on High Speed Motor: A Team Approach to Performance Improvement
Authors: Hendriks Peter , Tinkhof Rob , Hanouf Mohammed , Klink Zeinoun , Herran Guillermo
Published: December 2007

Recently, the design for deep wells in AFPC, Syria has been slimmed down in order to reduce well costs. This resulted in a general performance improvement. However, in the 6" reservoir section, which consists of hard and abrasive sandstones and shales in the Rutbah and Mulussa formations, performance deterioration was observed. These formations have traditionally been drilled with a combination of roller cone and PDC bits. In some fields, like the Shahel field, the ROP and bit life became unacceptably low.

To determine if this hard rock section could be drilled faster with alternative technology, the petrophysical logs were analyzed with a rock mechanics program to determine the formation's Unconfined Compressive Strength (UCS). The analysis also helped predict the formation's tendency to ball in addition to its abrasiveness and shale content. The rock mechanics program helped estimate how to drill the 6" section in the most efficient manner.

After comparing this analysis with the results obtained in a similar situations in the Saih Rawl and Barik fields in Oman, it was concluded that the use of high performance motors (1100 RPM) in combination with impregnated diamond bits had the potential to significantly reduce cost per meter. The analogy to Oman helped minimize the perceived risk of bit balling associated with drilling the Rutbah and Mulussa shale section in the Shahel field with impregnated technology. The combination of analytical study and comparison with offset data made it possible to justify a trial despite the high costs of running the high performance motor compared to the normal operating costs.

The new BHA and bit were used to drill the 6" hole section on well Shahel 111 between 3962 meters (m) and TD of the well at 4079m. The application was extremely successful saving in excess of US$150,000 and reducing the time to drill this section from 17 days to 3 days. ROP increased from 1.38 m/hr to 2.7 m/hr, while the number of bits used was reduced from nine to only one. All comparisons were made using a benchmark well in the same block of the field drilled less than a year before. Due to this breakthrough performance more complex wells, such as a level three multilateral, are now being planned for the near future.
Imaging Fluid Movements Through Sandstones, Sands and Model Glass-Bead Packs Using Fast NMR Imaging Techniques
Authors: Al-Mugheiry Mohammed Adil , Issa Bashar , Mansfield P.
Published: December 2007

Nuclear Magnetic Resonance (NMR) techniques are extremely powerful for characterising and quantifying the properties of the fluid-rock systems. Magnetic Resonance Imaging (MRI) has an additional attraction in that it can be used to generate image contrast through fluid transport properties.

The imaging experiments on such systems can be performed as static1 or dynamic2,3 fluid measurements. In some cases results of static-fluid measurements (eg. pore size distribution) are used to calculate a property that is more appropriately related to dynamic-fluid measurements (eg. permeability)

In this work, an efficient flow mapping technique called Pi-Echo-Planar-Imaging (π-EPI or Pi-EPI or PEPI) was used to quantify flow through different porous materials, ranging from model glass bead packs to unconsolidated sand specimens to consolidated sandstone samples.

The results presented demonstrate the potential of the highspeed snap-shot PEPI technique for quantitative spatial flow measurements in porous media.

The fluid flow studies on different porous samples seem to indicate a linear relation between the mean flow velocity and the velocity variance within a selected slice. A detailed simulation model for the interpretation of these results is described elsewhere4.

These results are still at the beginning of EPI applications in dynamic studies of porous media. Research protocols in this area are still at a relatively early stage and a far wider range of remaining challenges still exist5.
A Switch from Verticals to Dual Lateral Producers Accelerate Oil Production and Reduces UTC for Natih Field
Authors: Al Salhi M. , Al Maimani A. , Mäkel G. H.
Published: December 2007

The Natih field in Oman is a densely fractured carbonate reservoir with a STOIIP of 460 million m3. The displacement processes active in the Natih reservoir during the production period are very complex. Production started in 1967 with depletion of the reservoir resulting in production of oil from the fracture system and oil displacement by fluid expansion and solution gas drive. After these processes had ceased, gas oil gravity drainage in the secondary gas cap, water oil imbibition and water oil gravity drainage by aquifer below the secondary oil water contact continued to displace the oil from the matrix.

Based on field data available around the early seventies, it was decided in 1972 to arrest further pressure decline by water injection. In the 1980s, field performance reviews improved understanding of the displacement processes in the field and core analysis data pointed towards a relatively oil wet rock and a relatively large volume of production was ascribed to the GOGD process. Following this, further development of the field was wholly based on the drilling of GOGD producers in the oil rim and conversion to GOGD producer of suitably located wells.

Reservoir simulation work showed that substantial additional reserves could be developed by fracture oil rim lowering to a level close to the original OWC of the field. Through crestal gas injection and peripheral water production, coming from ESP wells placed around the field, this strategy was implemented. A further feature of this strategy is the drilling of multilateral wells with one leg close to the current oil rim and one leg in the anticipated final rim position. The upper leg produces oil, usually after a short "oiling-in" period. The lower leg initially produces water and helps lowering the rim.

This paper illustrates the reasons behind each stage of field development and reviews recent efforts to evaluate the effectiveness of the Natih oil rim lowering strategy and its future production potential through the use of 3D integrated modelling of Natih fracture system.
Looking to the Future - BP Amoco’s Gas-to-Market Outlook
Authors: McNeillie Graham
Published: December 2007

BP Amoco has a strategically important and new position in natural gas. Gas is abundant, inexpensive and clean but it is difficult to transport. The options for bringing gas to the market include pipeline, generating and transmitting electricity (gas by wire), LNG and Gas-to-Liquids (GTL). Transport by pipeline is the primary option for bringing gas to the market. Technology programs are underway to achieve significant pipeline cost reductions. If the end user of the energy requires electricity, then for a range of distances and energy levels it may be more economic to convert the gas into power and then transmit by wire using DC power systems. LNG is an option for delivering very large volumes of gas to markets far from the gas resources. Our latest gas marketing success story is the Atlantic LNG Plant in Trinidad and Tobago, which started up in 1999. Although the GTL option has had limited success, GTL projects are starting to look viable due to technology advances along with a low cost gas feed and a supportive fiscal regime.
Abatement of Water Production from Upper Permian Gas Wells in Saudi Arabia Using a New Polymer Treatment
Authors: Okasha T. M. , Nasr-El-Din H. A. , Al-Khudair W. S.
Published: December 2007

Excessive water production adversely affects the economics of gas wells and often leads to their premature shut-in. Production of high salinity water represents a major corrosion concern for casing, tubing, flow lines, and production facilities. Water production from gas wells can be significantly reduced by using water-soluble polymers or by blocking the flow of water using a suitable gel system.

A non-associate gas is being produced from the Upper Permian gas wells (Khuff carbonate gas reservoirs). Some of these wells produce large amount of very saline water (217 g/l). A chemical treatment is needed to reduce the amount of water produced.

An experimental study was conducted to screen various polymer solutions and gelling systems to treat gas-producing wells in the Khuff gas reservoirs. Experimental work included compatibility of two-water soluble polymers with Khuff reservoir brine, adsorption of these polymers on reservoir rocks, rheology of polymer solutions, injectivity and flow of these polymers into core plugs obtained from Khuff formation, at reservoir conditions.

The two polymers examined were compatible with Khuff reservoir brine under reservoir conditions. The amount of polymer adsorbed on reservoir rocks increased at higher polymer concentrations. Core flood tests showed that an organically cross-linked polyacrylamide-based polymer demonstrated the best performance for treating high permeability streaks where the gel treatment reduced the effective permeability to brine without affecting that to gas. Rheological measurements indicated that this gelling system could be placed into the target zone by bull heading or by using coiled tubing.
Modelling Water Breakthrough in a Fractured Carbonate Gas Reservoir
Authors: Weber Alexander , Brauckmann Franz , Rijkels Lex , Bourne Stephen J.
Published: December 2007

This paper describes a Permian evaporite carbonate gas field that has been plagued by severe water problems since it was put on production in the mid-80s. The field is a carbonate complex consisting of three communicating reservoirs that are heterogeneously fractured. Matrix permeability is typically less than 2 mD, except in one highly permeable streak, where it can be as high as 5 D. The permeability of the natural fracture network is extremely heterogeneous, and varies by up to a factor 100 over the field. Complex interaction between fractures, matrix and the highly permeable streak caused a surprising pattern of water breakthrough, which can be explained by a geomechanical model for the heterogeneous natural fracture network. This predictive, field-wide fracture model was validated and constrained by both geological and flow data.

First, the stress distribution around seismically visible faults was calculated assuming homogeneous, isotropic, linear elastic rock mechanical properties, and frictionless faults. Second, the calculated stress field was used to simulate the growth of discrete fracture networks, which were constrained by statistically comparing fracture orientation and connectivity with that derived from core, BHI, PLT, mud loss, and well test data. Finally, the fracture networks were upscaled dynamically to the grid of a dual-permeability simulator, enabling field-scale multi-phase reservoir simulation. The flow model obtained this way matched historical production data from all wells. It also explained the source of water breakthrough and the inflow profile seen on PLTs. Integrating seismic, borehole, well test and production data to constrain and validate such a field-wide model considerably reduced the uncertainty in the final predictions.

This integrated, predictive fracture model is presently used to investigate future field development scenarios. To this end, the model is coupled to a surface network simulator, which comprises the whole infrastructure. The fully coupled surface and subsurface models offer the flexibility to optimally plan the position and timing of new wells, the size of compressor units, additional in-field trunk lines and the gas offtake.
How to Reduce Proppant Flowback in High-Rate Wells
Authors: Terracina John , Parker Mark , Pongratz Reinhard , Poole Rob
Published: December 2007

This paper describes the laboratory development and field evaluation of a proppant surface-modification agent (SMA) that increases fracture-conductivity and reduces proppant flowback after fracture stimulation treatments, even in wells with high production rates. This SMA allows proppant packs to withstand three- to five-fold the critical flow velocity required to erode a proppant pack. Laboratory tests indicate that SMA will improve the vertical distribution of proppant by hindering settling. Typically, SMA provides a 15% to 30% increase in proppant-pack porosity. During tests with SMA, fines resulting from proppant crushing and formation fracturing adhered to the treated pack and did not migrate or block pore throats. Fracturing-fluid cleanup was significantly improved when proppant was treated with SMA.

Several field tests were performed successfully with SMA, including fracture-stimulation treatments in the Middle East, where proppant packs were subjected to extremely high flow rates. In all of these tests, proppant flowback was reduced, and well productivity was enhanced. The paper includes designs and results for some of these field tests.
Two New Chemical Components for Sand Consolidation Techniques
Authors: El-Sayed Abdel-Alim H. , Al-Awad Musaed N. , Al-Homadhi Emad
Published: December 2007

Sand production problems are encountered throughout the world and recently detected in Saudi Arabian oil fields. Therefore an increased emphasis is being placed on proper initial well completion as the value of non-renewable oil reserves increases and cost of remedial work skyrockets. Sand control by consolidation involves the process of injecting chemicals into the naturally unconsolidated formation to provide in situ grain-to-grain cementation. Techniques for accomplishing this successfully are perhaps the most sophisticated ones undertaken in completion work.

Many methods have been suggested to consolidate the wall of the wellbore for few inches or feet around the hole. These methods are either expensive or temporarily. This paper introduces two new cheep chemical components to be used to consolidate friable sand formation at temperature up to 300°C. The paper introduces these two components, discusses the physical and petrochemical properties of the consolidated sand and the factors affecting this consolidation and highlight the laboratory process and field application of these two components.
Maintaining Fracture Performance Through Active Scale Control
Authors: Norris M. , Perez D. , Bourne H. M. , Heath S. M.
Published: December 2007

Hydraulic fracturing using proppants is a well established technique for increasing well productivity. However, uncontrolled mineral scale deposition within the proppant pack can result in reduced conductivity and fracture performance, thereby devaluing the initial investment in the fracture. To protect this investment an active scale control strategy is required especially when executed in the presence of a water flood. A number of different techniques have been proposed and used historically, however they have all suffered with one or more drawbacks. These drawbacks have included excessive volumes, poor placement control, short treatment life and / or the potential for fines and sand generation and pack instability. The ability to place scale inhibitor within the voids of a porous proppant offers a robust technique for placing a large amount of scale inhibitor throughout the proppant pack while its controlled released protects the productivity of the fracture.

Previous papers have described the development of porous, scale inhibitor impregnated proppants and highlighted the initial returns from field trials performed on land wells on the North Slope of Alaska. The impregnated proppant technology has now been further developed and two treatments have recently been deployed in the North Sea. The treatments were both designed to stimulate production and to protect the fracture against future scaling scenarios.

This paper will describe the design criteria used to select this method of protecting the future performance of the fracture. In addition this paper will describe the design and execution of the treatments while highlighting the fracture performance and scale inhibitor return profiles generated by recent treatments performed in the British and Norwegian sectors of the North Sea.
Kinetics of CaCO3 Scale Formation. The Influence of Temperature, Supersaturation and Ionic Composition
Authors: Østvold Terje , Randhol Preben
Published: December 2007

A laboratory study of CaCO3 scaling kinetics has been undertaken to obtain information useful for prediction of CaCO3 scale formation. Thermodynamic carbonate scale prediction models have only a limited use since the rate of CaCO3 precipitation can be very slow at lower temperatures (< 60°C). The induction time for precipitation has been determined in a series of experiments where SR, T and the ionic composition of the water from which precipitation occurs, have been varied. The effect of sand from North Sea Oil Field reservoirs on the rate of CaCO3 precipitation has also been investigated by adding such sands to the water under investigation. Our data clearly show that oil field sands enhance the rate, and reduce the induction time for Calcite precipitation. The formation of solid CaCO3 has a window of metastability, which can vary from SR=aCa2+aCa32−Ksp(CaCO3)= 7.0, 2.9 and 2.7 at 80, 100 and 120°C, respectively, with no sand in the water, and 4.8-4.9, 2.7 and 2.6 with sand present. An even more drastic effect was observed when Calcite scale was added to the water. At 100-120°C the precipitation at SR = 1.6 was observed after a few seconds. This is reasonable since the Calcite crystals suspended in the solution act as crystallisation sites for the dissolved carbonate. It was also observed that Mg2+ and SO42- ions in the solution increased the induction time and retarded the CaCO3 crystallisation. The precipitating phase seemed to be Vaterite when Mg2+ and SO42- ions were not present in the solution. Vaterite even started to form on Calcite seeds when these were added to the homogeneous supersaturated solution. This implies that compounds, which block active sites for Vaterite crystallisation, may inhibit CaCO3 precipitation. With Mg2+ and SO42- ions in the solution Aragonite was formed.
High Temperature (374°F, 190°C) Core flooding Experiments for the Selection of Appropriate Scale Inhibitor Products for Potential Application as Downhole Squeeze Treatments in High Temperature Reservoir Environments
Authors: Graham G. M. , Dyer S. J. , Shone P. , Mackay E. J. , Juhász A.
Published: December 2007

In recent years, a number of new HT/HP reservoirs have been developed in the North Sea. The Shearwater reservoir is a gas condensate producer located in Block 22/30 in the North Sea. This reservoir has very harsh downhole conditions as follows: T ~ 370°F, P > 13,000 psi, brine TDS > 250,000 mg/l and is therefore classed as a HP/HT/HS reservoir. Significant downhole carbonate scale ([Ca2+] ~ 20,000 ppm; [Bicarb] ~ 560 ppm) is expected in the wellbore and near wellbore formation area initially at low GWR (GWR < 0.05) with the main mechanism being evaporation from the low volume brine phase into the high volume gas phase. As a result, downhole squeeze scale inhibitor treatments will be required at a very early stage of production. In a previous paper (SPE 60217), presented at the 2000 Scale Symposium, we presented results from a detailed screening study, based largely on bulk experiments (thermal stability, compatibility and performance), to select appropriate chemicals for potential application in this reservoir. Five products were selected which covered a range of generic chemical types including thermally stable phosphonates (HMDP), sulphonated polymers (PVS, S-Co) and phosphorous containing co-polymers (P-SCo).

Further work involving a series of high temperature core flooding experiments conducted at 374°F (190°C) have now been completed on the various pre-selected products. In addition to monitoring inhibitor return profiles, the performance of the released inhibitor species was also examined, with some surprising results. The results from these tests have significant implications on the selection of products for downhole application under such harsh conditions. Results are presented in the following areas: ▪Comparative inhibitor retention and return characteristics▪Comparative field application modelling using SQUEEZE V software▪Implications of adsorption on the thermal stability of the pre-selected products.

Results in this study demonstrate that the rock surface interaction of certain pre-selected chemical species in core flood experiments can alter their performance (as a result of thermal degradation), which was not recorded in the initial static thermal stability tests. This is not in accordance with previously held opinions that adsorption onto rock substrates increases the thermal stability of scale inhibitor products.
The Use of Expandable Sand-Control Technology as a Step Change for Multiple-Zone SMART Well Completion - A Case Study
Authors: Saeby Jan , de Lange Frank , Aitken Scott H. , Aldaz Walter
Published: December 2007

The Champion West (CW) field Offshore Brunei, North Borneo consists of alarge number of vertically stacked hydrocarbon bearing reservoirs where thinlayers of laterally continuous shales are sealing the different hydrocarboncolumns.

Wells in CW are typically completed selectively on multiple reservoirs (3-5zones) due to contrasting reservoir pressures and fluid properties and forreservoir management purposes. Although the reservoir rock is relativelyconsolidated, sand exclusion has been installed on shallower reservoirsfollowing sand failure in offset wells. Internal Gravel Packing (IGP) has inthe past been the preferred sand exclusion technique.

Due to a high deviation in the four CW Early Oil Development (EOD) wells(54-66 deg.), it was desired to incorporate remote operated smart wellequipment to minimise future well intervention requirements.

As the large distance between zones would require up to four IGP operationsper well (resulting in high costs) and would not provide sufficientthrough-bore to install the smart well equipment, it was decided to useExpandable Sand Screens (ESS) for sand control purposes in the new wells. Theuse of ESS facilitates multiple zones to be completed in single installationswhilst providing a larger through-bore for the installation of smart wellequipment.

The paper discusses the sand-face completion design and installationaspects. As one of the EOD wells was completed with IGP, a benchmarking (rigtime, cost, performance) of the ESS technique is also presented. Finally, recommendations are made which should enable further cost reductions in the future.
An Improved Reservoir Characterization of Sandstone Reservoirs in the Khafji Field, Arabian Gulf, by 3D Seismic-Aided Well Test Interpretation
Authors: Watanabe Kazuaki , Nishikiori Nobuo
Published: December 2007

This paper aims to improve reservoir characterization of sandstone reservoirs in the Khafji oil field, Arabian Gulf, by integration of well test analysis and fault location information from three-dimensional (3D) seismic survey.

There are several hundreds of normal faults in the Khafji field which were recently recognized by 3D seismic survey. Although the reservoir has strong edge water drive, water production is observed in some central upstructure area earlier than in peripheral area nearby. Existence of conductive faults, which causes fluid communication between the upper and lower reservoirs, was suspected from engineering analyses conducted. Conductive faults have great impact on reservoir water production and pressure behavior.

The main issues of this paper are: Well test analysis for wells near 3D seismic interpreted faults.Design of interference test to investigate vertical fluid communication through conductive faults between two reservoirs.

Well test data for 5 selected wells located near faults were analyzed and boundary effects such as sealing fault or constant pressure were interpreted. Faults located within 1000 feet distance from wells were characterized by integration of well test and 3D seismic results.

Field test was designed in an area where interference between the Upper Sand and the Lower Sand was suspected. 1 active well and 4 passive wells were designed and pressure behavior of each well was predicted. A fault was defined in the model by placing two adjacent rows of cells with 30 feet difference in depth. Fault conductivity was changed as a parameter in simulation. Two kind of tests were discussed: (1) Short term interference test with 3 pulses of 12 hours each (2) Long term interference test with 3 pulses of 1 week each. Long term interference test was recommended from the simulation results because pressure drop was detectable even when fault conductivity was small.
Innovative Seismic Data Processing Approach to Improve Signal to Noise Ratio
Authors: Gupta P. P. , Prakash Kuldeep , Singh Paramjeet , Lakra M. N.
Published: December 2007

It is a common experience that undesired noise is invariably recorded during seismic data acquisition. The real signal is masked by the noise that may be coherent or random in nature. Coherent noise is generally identifiable by their apparent velocities. The aim of seismic data processing is to identify the noise, attenuate it and improve signal to noise ratio. In this paper, our aim is to remove coherent noise in shot domain before any subsequent data processing is taken up. Although f-k fan filters are commonly used to remove coherent noise by defining fan-like region in f-k spectrum but these are not applied on NMO corrected shot gathers. In our method, NMO correction is applied on shot gathers using reasonable velocities in such a way that primaries are either perfectly corrected or over-corrected and coherent noise remains under-corrected. Since events having different dips in t-x domain occupy separate zones in f-k spectrum, NMO corrected shot gathers are f-k filtered to remove under-corrected events that represent the coherent noise. Data thus f-k filtered is passed through inverse NMO process to remove any changes made to the input shot records during application of NMO correction. Subsequent processing of data is carried out as usual. Significant improvements are seen in data processed with this technique.

The salient features of this technique are two folds. The first is that the NMO correction before f-k filtering widens the separation between real signal and the noise and the second is that the foldage in shot domain remains double of that in CDP domain thus no spatial aliasing takes place.
Towards Environmentally-Friendly Additives for Well Completion and Stimulation Operations
Authors: Rae Phil , Di Lullo Gino , bte Ahmad Atikah
Published: December 2007

The oil and petrochemical industries have unquestionably been key drivers in the development of the complex, modern world we live in. They have helped power our cities, transport our goods and provided the raw materials for the development of countless pharmaceuticals, dyes, plastics and consumer products. In fact, many of the advances made in general health, and in improved living standards around the world, can be traced to the wealth generated by the oil industry. However, while few recognise this contribution, many people do worry about the risks posed by the search for, and exploitation of, hydrocarbon deposits. Indeed, despite its importance, the oil industry has, to some extent, been "demon-ized" by certain groups and subjected to disproportionate criticism. However, while the industry has a generally good pollution record, when compared to other major businesses, there is no room for complacency. Oil itself is usually perceived to be the biggest acute environmental threat, due largely to the volumes involved in occasional, highly-publicised spills and their distressing effects on wildlife. On the upstream side of the supply chain, the escape of oil is still a risk but, in addition, there are many wellsite operations that involve the use of chemical additives. In common with many industrial chemicals, some of these materials are toxic and some may not biodegrade at acceptable rates. With an increasing awareness of the potential environmental impact of chemical additives, particularly in the marine environment, there is a continuing need to develop more efficient, less toxic alternatives.

We have been actively pursuing this goal since the early 1990's, replacing many additives with environmentally-friendly alternatives. This has been achieved by combining our knowledge of structure-activity relationships with our knowledge of polymer, surfactant and solvent chemistry and ecotoxicology. As a result of these efforts, many potentially harmful chemicals have been removed from active service and replaced with new, field-proven and eco-friendly systems that have been tested in accordance with OSPARCOM guidelines, or their equivalents. Use of such materials offers benefits in terms of health and safety and, ultimately, potential cost reductions when disposal and waste handling charges are factored in. Use of appropriate materials can even improve job results, as witnessed by several operators, and helps to demonstrate what can be achieved when a commitment to "green" principles is made. However, it should be recognised that there are inevitable development costs in the design, testing and manufacture of new additives. Operating companies need to give due consideration to encouraging and rewarding those suppliers and service companies who, ultimately, help them comply with current and future pollution-control regulations.
Opportunities to Improve Success Rate of Coiled Tubing Operations
Authors: Engel S. P. , Mackey P.
Published: December 2007

Coiled tubing has been an invaluable tool to the oil and gas industry for some forty years. Each time that coiled tubing is rigged up and run into a well it carries with it a risk that the objective of that run will not be met. This paper analyses that risk based on some two years continuous records in the Asia Pacific Region and finds that the average rate of a successful run is 82% over a 23-month period. A database of about 1200 runs demonstrates the type, cause and frequency distribution of failures. Risk management options are reviewed and potential solutions offered.

The cause of failures is most frequently attributed to unknown well conditions. However, inadequate job planning, operator errors and equipment failures also have a significant contribution. The levels of technical complexity demands are escalating. In balance, there are increasing operational skill levels, equipment reliability improvements and a better focus on pre-job planning. This, then, tends to hold the status quo at a constant frequency over time. In order to increase the rate of success, lowering the difficulty of the jobs attempted and/or increasing the operating and equipment reliability will be required. Simplicity and reliability tend to go hand in hand. However, there is a general industry temptation to over-engineer and overcomplicate both the work scope and the equipment. The result may be viewed as unreliable and perhaps, not cost effective coiled tubing solutions.

The opportunity exists to significantly reduce the run failure count. This could be achieved by lowering ambitions and allowing equipment and skill levels to ‘catch up’ with established industry coiled tubing solutions. It then raises the question "Is it better to do something simple well or to risk failure with technical ambition?" This paper concludes that the current failure rate can be improved upon with various corrective actions. This is essential in order to progress to further technical advancements.
Assessment of Permeability Distribution Through Well Test Analysis
Authors: Babadagli T. , Al-Bemani A. , Al-Shammakhi K.
Published: December 2007

Many tools conventionally used in formation evaluation can provide an estimation of reservoir heterogeneity type and degree. Based on this information representative reservoir model can be built through which reservoir pressure and production behavior can be accurately estimated. The estimation of reservoir heterogeneity through reservoir responses, however, is still a challenging task. Well test analyses provide important information about the interwell permeability distribution of a reservoir.

This study aims to correlate the response of pressure transient test to permeability distribution type. For this purpose, correlated permeability distributions in x-y direction are generated using fractional Brownian motion (fBm) as it has been shown in literature that permeability exhibits an fBm type distribution horizontally. 2-D fBm permeability distributions created using mid point displacement method are employed as data to a black oil simulator. Intermittence exponent, H or fractal dimension of the distribution, D, as defined by D=2-H, characterizes the distribution type. All permeability distributions are normalized to represent the same arithmetic mean (20, 100, and 500 mD) and uniform variance so that only their fractal dimension that underlies the smoothness of the distribution distinguishes them. Many different realizations of permeability distributions are generated based on the random number seeds used and pressure transient (drawdown) tests are simulated using a black oil simulator package (ECLIPSE 100). Pressure transient analysis is performed using PanSystem package. As a base case and for the comparison purpose, the same procedure is repeated for totally homogeneous case and random (normally distributed) permeability distribution with the same mean and uniform variance.

The effects of permeability distribution type on the pressure response are clarified. A strong impact of heterogeneity is observed as an increase in skin effect with increasing fractal dimension of permeability distribution. This additional (or pseudo) skin effect due to heterogeneity is correlated to the fractal dimension of the permeability distribution. As a further step, the procedure is repeated for different flow rates applied during the drawdown test. The correlation between the fractal dimension of permeability distribution and additional skin is improved by incorporating the rate into it. The methodology followed can be used in the assessment of reservoir heterogeneity quantitatively using pressure transient response.
Combined Saturation and Production Monitoring Logs for Water Flood Optimization
Authors: Elshahawi H. , Gad K. , Hassan A.
Published: December 2007

Despite the old and extensive use of water flooding as a secondary oil recovery scheme, the actual performance of a given water flood is still often difficult to predict even in the most homogeneous of reservoirs. This performance is heavily dependent on the injection pattern, fluid mobilities, as well as reservoir heterogeneity. For this reason, it is essential that the actual performance of a water flood be measured in order to be able to optimize that performance. This is best accomplished through the combined use of reservoir saturation and production logging tools.

The Reservoir Saturation Tool (RST) provides cased hole reservoir saturation using the water salinity-dependent Sigma capture cross-section measurement as well as a salinity-independent measurement of oil saturation using carbon-oxygen ratio. The latter is especially useful in fresh water and mixed/unknown salinity environments, such as might be expected in a water-injection environment. Production logging, on the other hand, provides information on zonal fluid contributions, fluid typing, as well as clues to fluid movement inside and outside the well bore. The use of shut-in as well as flowing surveys adds a third (time) dimension to the picture.

This paper presents a case of water flood performance monitoring from the Younis Field, operated by the Gulf of Suez Oil Company of Egypt, and illustrates the data analysis cycle involved. The role of the analyst is to piece all the measurements together and come up with a hypothesis to explain what may be happening. This hypothesis is then tested against production data, injection data, and other reservoir data. It is then refined and fine-tuned until a satisfactory explanation is found for all the observed phenomena. The resulting conclusions are highly valuable for the assessment and subsequent optimization of the injection pattern.
Application of Produced Water Technology Practices in Indonesia Upstream Petroleum Industry
Authors: Priatna R. , Wusono S. B. , Bledoeg R. I.
Published: December 2007

Produced water still makes up the largest waste stream in up stream hydrocarbon (E & P) industry in Indonesia. Processing and disposing of produced water can make the difference between making a profit and losing money.

Understanding produced water and its unique nature in Indonesia is essential in designing and operating treatment systems. The regulatory requirement is still growing here, and continuous inputs on best practicable technologies available to the regulatory bodies should be maintained and enhanced.

Throughout the history of Petroleum production, since more than 100 years ago, gravity settling tank is the only best known in industry, but recent improvements in processing technologies are added into the old installations. More sophisticated separating systems have been installed and prove to meet the less stringent regulatory requirements. In offshore operations, especially in environmentally sensitive waters, practice with hydro-cyclone technology has been applied. While in onshore, injection to disposal wells are the safe and environmentally sound technology can be applied.
Monitoring Well Performance using Multiphase Flow Meter
Authors: Retnanto Albertus , Azim Azriz
Published: December 2007

A multiphase flow meter has been developed for determining oil, water, and gas rates simultaneously. This evolution combines accurate and repeatable flow rate measurements without prior well information, to offer shorter well stabilization periods to enable a significantly reduced flow period. Multiphase meter well testing offers significantly more detailed information on the well(s) performance than the standard test separator.

The multiphase meter provides the need for light operation, reduction in human error and a significant increase in safety and assures increased environmental control. Furthermore, the well test set up does not require extensive numbers of pressurize lines and safety devices as per a conventional well test. The fast acquisition device monitors the wells ‘heart-beat’ throughout the well test. The test period could be reduced to a half of a normal production testing as the trends are being displayed in real time. Thus, giving the user the capability to test more wells per day. On top of this the meter is completely environment friendly, as no burning of gas has to be performed during the tests, all the well effluents are returning to the production line as there is no need for separation.

Periodic testing with accurate rate measurement and repeatability is the key for production optimization of a well. A multiphase meter has been used to monitor and optimize the production performance for artificially lifted wells. Using this multiphase meter, changes in the well performance can be observed immediately in real time. This allowed the operations engineer to manage decisions in real time as to what interventions were desired to optimize the outflow. The engineers now have the ability to do analysis of producing formations based on true accurate real time test data. The multiphase meter has improved visibility into well and reservoir performance.