bluuebunny/crossref_metadata_2025 huggingface dataset:
Smart Completion Design With Internal Gas Lifting Proven Economical for an Oil Development Project
Authors: Jin L. , Sommerauer G. , Abdul-Rahman S. , Yong Y. C.
Published: December 2007

An oil acceleration project in an offshore oil field in Brunei Shell requires two oil wells to produce oil via an existing 80 bara (HHP) gas pipeline to a platform. Acceleration of the 2 wells will result in: Accelerated oil production from the oil rims.Acquisition of additional reservoir data for further field development optimization.

This paper will discuss the technical details on the following work: Evaluate the initial production against HHP (8 MPa) in a commingled mode from 3 oil zones.Internal gas mixing (lifting) using source gas from a gas zone. The optimized gas injection rate, downhole choke size have been selected through modeling.Completion designs for the two wells to realize the commingled production with internal gas lifting and enable the evaluation and production testing of each individual zone for reservoir appraisal and reservoir management purpose.

A smart completion design was proposed. It comprises of: Inflow Control Valves (ICV) for surface controlling of production from each zone,Down-hole temperature and pressure gauges for monitoring each individual zone,A hydraulically controlled down hole choke to control the inflow of lifting gas from the gas zone. Based on the study, the range of choke sizes from 2/64" to 60/64" was chosen,Cased hole expandable sand screens (ESS) with extension pack and/or wire wrapped screens (WWS) in open hole sections for sand control,All the control and monitoring can be conducted real-time remotely to minimize the intervention in an unmanned platform.

The intelligent design is a key enabling technology to economically produce small oil rims and maximize liquid recovery, thereby increasing the value of the overall field development. The project exceeded the group economic criteria and has been approved.
Monitoring of Real-Time Temperature Profiles Across Multizone Reservoirs During Production and Shut-In Periods Using Permanent Fiber-Optic Distributed Temperature Systems
Authors: Fryer V. , Shuxing D. , Otsubo Y. , Brown G. , Guilfoyle P.
Published: December 2007

This paper describes the use of a fiber-optic distributed temperature system (DTS) to monitor and evaluate the production and shut-in thermal profiles in an offshore China well. The objective was to identify and correlate production changes with respect to time over the first phase of a multiphase offshore field development.

The well was drilled from an offshore platform with a deviation of 40 degree across the reservoir section and completed with a 5 inch diameter expandable sand screen (ESS). An electrical submersible pump (ESP) was used to produce the oil. The reservoir consists of multi-layered sand zones and the flow was commingled through the sand screens to the pump intake set in a 9-5/8 inch diameter casing.

The system was commissioned to acquire a better understanding of the flow allocation in the complex stacked reservoir sequence. The importance of this knowledge in the early stages of production is expected to influence future field development.

Continuous distributed temperature monitoring of the well enabled quantitative analysis of the produced fluids to be performed at selected times providing real time, permanent, production monitoring over the reservoir. This technique will allow future wells to be developed with smaller completion sizes by limiting the requirement for production logging "Y" tools.

The data acquired to date has provided improved reservoir characterization and understanding of the dynamics of the reservoir behavior. The data analyzed included initial well unloading and clean-up, zone depletion over time resulting from zone reservoir pressure changes, natural flow on shut-in and differential flow induced from various production rates using a variable speed ESP. These key events would not have been captured with conventional production logging due to normal operating constraints.

As the completions in this field are multi-zone or multi-layer completions, understanding the relative flow contribution of each zone or layer is important for long-term reservoir management. Combined with pressure transient analysis of initial production history, the data collected from the fiber optic DTS has enabled the determination of individual sand lobe flow capacity and a better determination of net pay cut offs. Combined with other open-hole log information, a breakthrough has been achieved for generating accurate models of permeability for each sand sequence within this fluvial deltaic reservoir environment.
The Key to Predicting Emulsion Stability: Solid Content
Authors: Poindexter Michael K. , Chuai Shaokun , Marble Robert A. , Marsh Samuel C.
Published: December 2007

Chemical demulsifiers are routinely added in the oilfield to effectively resolve water-in-crude oil emulsions. As used in the common bottle test, demulsifiers in effect probe or interrogate emulsion stability strength. Emulsion stability in turn is defined by no less than three parameters - water drop, oil dryness and interface quality. All three parameters are direct outputs of the bottle test, and collectively, all three provide a more complete picture of emulsion stability as opposed to the use of any singular parameter.

By selecting a wide variety of demulsifiers and performing a standardized bottle test (as introduced in SPE 84610), emulsion stability from a variety of sites can be quantified and compared. By coupling bottle test results with corresponding crude oil analytical data, fundamental questions concerning factors governing emulsion stability can be quantified. The results show that solid content, not asphaltene content or any other crude oil parameter investigated, is by far the best single predictor for gauging emulsion stability. Furthermore, statistical analysis via partition trees shows that emulsion stability is most aptly described using several input parameters as opposed to a single factor. This statistical technique produces emulsion stability descriptions with Rsquare values on the order of 0.9.
Flow Potential of Fracture Corridors and Mega-Fractures in a Clastic Field in South Oman
Authors: Ozkaya S. I. , Minton K. R.
Published: December 2007

The field is a ‘turtle back' structure bound by a major wrench fault to the north and a salt withdrawl pod to the south. The reservoirs are high net to gross aeolian sands from the Cambrian (Amin) overlain by Permian glacial deposits (Al Khlata) with a high degree of heterogeneity. A combination of high viscosity oil and an extremely strong aquifer makes this field challenging. Early water breakthrough has traditionally been explained by rapid water coning, but recent data from under-balanced drilling operations highlighted that fractures do indeed play a role. This study aimed to explain whether this was a local phenomenon or a field wide characteristic, based on borehole image logs, openhole logs and production data from 16 horizontal and 15 vertical wells.

Faults/fracture corridors and dispersed fractures have no correlation to BSW (bulk water saturation) or gross production rates. However, wells with mud losses always produce at high BSW or have rapid water breakthrough. Recent data from under-balanced drilling operations also highlighted that fractures might play a role because significant water influx was focused within narrow intervals.

This apparent dilemma is resolved by noting that mud losses were reported only from a small fraction of wells, suggesting only a small fraction of faults are fluid conductive. Contrary to faults and fracture corridors, mega- fractures (large conductive fractures) have some correlation to BSW rate of increase. A possible explanation is that most fractures are clusters of shear fractures filled with sand and clay gouge, whereas some mega- fractures are opening mode fractures. It is not possible, however, to distinguish the opening mode fractures from gouge filled fractures from borehole image logs. In general fractures seem to play a minor role in water breakthrough because most fractures are not fluid conductive.

It appears that spud date is probably the main factor related to rapid BSW rise with recent wells being more prone to rapid water breakthrough. Other factors such as pump type, depth to FWL, and distance between wells also have some effect on BSW rise.
Measurement of the Particle Deposition Profile in Deep-bed Filtration during Produced Water Re-injection
Authors: Ali M. A. J. , Currie P. K. , Salman M. J.
Published: December 2007

An on-line linear X-ray apparatus has been used to examine deep bed filtration during water injection in Bentheimer sandstone core samples.Hematite particles suspended in brine were injected at different flow rates and concentrations to investigate the deposition profile.The X-ray attenuation is strongly related to the density; and therefore the amount of deposited material can quantitatively be estimated at any time and distance along the core sample.Deep penetration can be distinguished from external filtercake buildup. Permeability decline as determined by the pressure change and chemical analysis of hematite concentration were used to confirm the X-ray analysis.
Real-Time Downhole pH Measurement Using Optical Spectroscopy
Authors: Raghuraman B. , O'Keefe M. , Eriksen K. O. , Tau L. A. , Vikane O. , Gustavson G. , Indo K.
Published: December 2007

A new downhole pH sensor has been developed to provide an in-situ pH measurement of formation water at reservoir conditions, and results are presented for two wells in the Norwegian Sea. The measurement technique, for use with wireline formation sampling tools, uses pH-sensitive dyes that change color according to the pH of the formation water. To make a real-time pH measurement, the dye is injected into the formation fluid being pumped through the tool flowline, and the relevant visible wavelengths in an optical detector are used to record the dye signal and calculate pH with 0.1 unit accuracy.

The pH of a formation fluid alters as the sample is brought to surface from the high temperature and pressure conditions downhole, owing to acid gases and salts coming out of solution and changes in water chemistry equilibria. To get an accurate pH, the measurement has to be made downhole at reservoir conditions. Unlike potentiometric methods where fouling of electrode surfaces by oil and mud is a potential problem, the dye technique is robust because the dye is isolated from the formation fluid and is injected into the sample only when a measurement is made. The technique has been successfully applied to both oil-based and water-based drilling muds, with successful measurements even in mixed oil/water flows. Multiple measurements of pH at a single sampling station demonstrate that the method is robust and repeatable. These measurements have been compared with numerical simulations using a multiphase chemical equilibrium model that uses laboratory analysis of collected water samples as input.

pH is a key parameter in water chemistry and is critical for corrosion and scale studies. Accurate downhole pH measurement allows more accurate selection of appropriate completion materials and more effective planning for scale treatment and inhibition.
Well and Reservoir Management in a Giant Gas Oil Gravity Drainage Field: A Case History
Authors: Ali E. , Bergren F. E. , Saluja J. S. , Sinani I. S.
Published: December 2007

This paper presents the case history of a focused Well and Reservoir Management (WRM) effort in a giant densely fractured carbonate reservoir in Oman. The field is currently producing under the gas oil gravity drainage reservoir process. The fracture network in the reservoir is largely gas-filled and has a thin oil rim underlain by active aquifer. Horizontal and multilateral producers are positioned in the oil rim while aquifer influx is limited to the optimum rate by water withdrawal from flank water producers. Delicate balance of crestal gas injection, aquifer water withdrawal and oil production is required to keep the oil rim at its optimal position. As the fracture oil rim has been lowered over a period of several years, a large number of wells have gassed out and started to circulate injected gas. Initial analysis of the production trends indicated that additional compression capacity was required in the field.

An integrated WRM effort was undertaken in 2003 to manage this complex field. Active reservoir surveillance planning and execution was carried out to map current fracture fluid contacts across the field. Strategic well optimizations and recompletions were performed in selected wells to capture production from oil rim and avoid short-circuiting of the injected gas. Also, several gassed out intermittent producers and very high GOR continuous producers were shut-in. An eight-well production logging campaign provided better understanding of well and reservoir behaviour. Well integrity tests in over 110 wells further assisted in problem diagnosis and workover planning.

These focused WRM efforts have resulted in sustained 10% production gain over a one-year period. A major capex benefit was also realized when a better understanding of the reservoir and improved GOR performance of the field eliminated the previously perceived need for additional compression.
A New Method for Solving the Implicit Reservoir Simulation Matrix Equation
Authors: Watts J. W. , Shaw J. S.
Published: December 2007

The dominant computational cost associated with implicit reservoir simulation arises in solving the matrix equation at each Newton iteration. This paper describes a new solution method based on a reduced matrix equation constructed using singular value decomposition. The reduced matrix equation is used as the basis of a preconditioner. The resulting preconditioned iteration generally converges in two to four iterations. The new solver can reduce solve times substantially.
Optimizing Stimulation Treatments in Straddled Completions
Authors: Willemse M. I. , Mostafa O. , El-Ashry M. , Abdallah I. , Sattar A. A. , Waheed A. , Conrad B.
Published: December 2007

Completing a producing zone(s) behind straddle packers is a common occurrence; hundreds of wells have been completed in this manner. Should such wells produce trouble-free and meet expectations, there is not much to ponder over; but if not, the options for executing an enhanced stimulation treatment have been limited. Generally, treatment has consisted of pumping and squeezing away the treatment into the perforations via the sliding side door(SSD) and hoping for the best. The preferred technique is to improve the injectivity into the perforations by "spotting" reactive fluids at the perforations or using some type of mechanical action such as "perforation jetting" to break up blockages in the perforation tunnels. This is only possible when perforations are accessible through the wellbore.

These problems become more complicated if the zones of interest are sandstone reservoirs. A study1 in the late-1990s revealed a success ratio in the 30-40% range when treating such formations.

This paper addresses such a scenario in which a dirty sandstone reservoir, not previously matrix-acidized, was producing at sub-par rates (declining to the point of being negligible). The zones were completed between straddle packers and were only accessible through SSD, 100 ft above the perforations.

The prudent decision was to stimulate, but make all efforts to maximize the chances of success. Apart from applying the best practices in sandstone acidizing technology, a true fluidic oscillator (TFO) was included as a stimulation tool. This tool provides a continuous pressure pulse in the fluid system that allows solids buildup within the perforations to fatigue and break up while the acid system works on the rock matrix.

The results from the treatment of this well were exceptional and will be detailed in this paper. The production improvement was 10-fold over its prestimulation performance.
Improving Management and Allocation of Gas Production in Maturing Reservoirs: A Multiphase Spinner Response Model for the 21st Century
Authors: Whittaker A. C. , Lenn C. P.
Published: December 2007

Conventional production log interpretation using a spinner assumes that the spinner responds to the holdup-weighted average velocity of the fluids traveling through the swept area of the spinner blades; however, the spinner tends to respond preferentially to the most dense phase flowing through it and so can be considered as a momentum-averaging sensor. This means that when fluids of markedly different density and velocity are averaged using the current best practice we may not be calculating the most accurate spinner velocity to be used in the production log interpretation. This paper examines alternative spinner averaging approaches and then evaluates the difference on synthetic, laboratory, and real downhole data sets. We conclude from this short study that there is potential to improve the current practice of spinner interpretation, especially in gas/liquid flows, and thus provide better data for gas production allocation and gas reservoir management. Further work is needed to develop this approach.
Reservoir Simulation Challenges for Modeling a Thin Volatile Oil Rim With Large Gas Cap in the Poleng Field, Kujung-I Oil Reservoir, East Java Basin, Indonesia
Authors: Forrest J. , Sukmana A. , Suhana W. , Asjhari I.
Published: December 2007

This paper explores the difficulties in modeling an oil rim with a large gas-cap using black-oil and compositional formulations. The example is from the Poleng field located in the Poleng Block, East Java Basin, Indonesia. This reservoir is a reefal carbonate system with a limited aquifer within the Kujung-I interval.

Production from the field commenced in 1975, was suspended in 1978 and re-activated by Kodeco in 1998. In 2002–03, a full-field study was conducted to re-evaluate the OOIP and OGIP and investigate future development options such as booster compression, gas and/or water injection, workovers, and infill wells. For this study, a new reservoir simulation model was developed based upon new/updated data. Two fluid PVT models (modified black oil and compositional) were also developed. At the start of the study, the operator felt that compositional formulation might be needed for modeling the gas injection processes. However, most of the work was performed using the modified black oil model because of computational speed consideration. The history match process showed that many simulation layers (grid blocks) were required to match the wells near the fluid contacts. Grouping some components in the compositional model was helpful to reduce run time, but the resulting equations of state (EOS) were generally not reliable for both the gas-cap and oil zones.

Simulation results indicated that an OOIP of 98.5 MMSTB was required to obtain a good history match. The original free gas-in-place was estimated to be 210.1 BSCF. The best future development option was a booster compression project. For a 10-year prediction period, additional oil and gas recoveries for the booster compressor were predicted to be about 1.7% OOIP and 19.0% OGIP compared to the base case. Gas injection was less favorable because it would defer some volume of the gas sales, while water injection, workover and infill wells resulted in very small incremental oil and gas recoveries. The main reasons for the low oil recovery are high residual oil saturations estimated from core analyses, reservoir heterogeneity, and gas fingering from the large gas-cap.
Successfully Sterilizing the Sulfate Bacteria With Ultraviolet Radiation in Produced-Water Treatment in Daqing Oilfield
Authors: Wang J. , Yang F. , Yuan X. , Liu B. , Wu H. , Sui X.
Published: December 2007

Now the chemical bactericides are often used to sterilize the SRB (sulfate reducing bacteria) in the treatment process of oilfield produced-water, but this method always accompany with disadvantage, such as lower efficiency, environment pollution, high cost, drug-fast of bacteria, and the side-effect of reaction with the other agent adding in water treatment. We Daqing oilfield should dispose about 500 million tons produced water, a great effort should do to get a bactericide method both of high efficiency and low cost to dispose such a mass of produced-water.
Development and Evaluation of High-Temperature Conformance Polymer Systems
Authors: Vasquez J. , Dalrymple E. D. , Eoff L. , Reddy B. R. , Civan F.
Published: December 2007

Conformance polymer systems have been successfully applied for many years to control undesired water production from hydrocarbon wells. However, currently available polymer systems present a number of limitations for high-temperature conformance applications (> 300°F). Based on laboratory research, this paper documents the results of the development and evaluation of polymer gel systems used as sealants to shut off water production in high-temperature environments. The polymer systems were evaluated by their effectiveness to: (a) provide adequate gel time for placement (up to 400°F), (b) limit permeability to water at temperatures up to 375°F in sandpack flow experiments, and (c) provide long-term thermal stability in sandpack flow experiments at elevated temperature (up to one-year study).

A commercially available polymer system that has been successfully used in field applications (up to 275°F) has been modified to extend its applicability up to 375°F. Recently developed base polymer, crosslinker, and retarder were tested successfully to extend the temperature range of applicability of this polymer system. Discussed are: (1) methodology used for gelation time measurement of polymer systems at elevated temperatures, and (2) laboratory results regarding gelation time of crosslinked polymer systems when varying temperature, base polymer concentration, crosslinker concentration, retarder concentration, salinity of mixing brine, and/or pH of solution.

Additionally, this paper discusses and describes the dynamic flow through porous media experiments performed to simulate high-temperature / high-pressure reservoir conditions to evaluate the performance of polymer systems at elevated temperatures (up to 375°F). Specifically, this paper details: (1) the physical laboratory equipment and test conditions used for dynamic flow studies, (2) experimental procedure regarding short-term and long-term testing, and (3) the effect of temperature versus permeability reduction over time.
A volcanic reservoir: Facies distribution model accounting for pressure communication
Authors: Yamada Tomomi , Okano Yoshiyuki
Published: December 2007

A TCF-class gas field has been producing over decades in Japan. The reservoir body comprises stacked Rhyolite lava domes erupted under submarine environment. Porous network developed in each dome and rapid chilling by seawater caused Hyaloclastite to deposit over it. Although Hyaloclastite is also porous in this field, its permeability has been dramatically reduced by clay minerals. These reservoir facies are interbedded with Basaltic sheets erupted alternately and Mud sedimented while the volcano was dormant.

Based on stratigraphic correlation, multiple reservoirs were originally interpreted. Gas had been produced according to the priority assigned to each. However, it was noticed after 10-20 years of production that pressures of all unexploited units had been declining with variety of rates. We confirmed that by subsequent survey and decided to remodel the whole pressure system. As seismic data had not been informative, we made maximum use of the pressure data to resolve the nature of the communications.

We employed multi-point geostatistics to capture the complicated facies distribution patterns. Realizations are then calibrated against pressure history through a probability perturbation technique. A common difficulty of building proper stationary training image is further pronounced in modeling a volcanic reservoir. We solved this by iteratively adjusting a training image inferred from literatures until acceptable history match was reached with reasonable number of perturbations. Another issue was undetermined field extent. We settled this by stochastically populating a rectangular-parallelepiped modeling space of regular cells with pay and non-pay facies.

Resulted realizations closely simulate pressure history and look realistic in both facies distribution and field extent. They ascribe the uneven pressure decline to narrow channels of Rhyolite and confinements by Hyaloclastite. Finalized training image indicates more intensity in facies spatial variation than had been expected. Based on 20 realizations, roughly 15% of scatter was estimated in OGIP around the mean.
Yakin West Waterflood Project: Looking for Opportunity To Maximising Recovery
Authors: Yamin M. , Yuliraharjo A. , Zahar R. U. , Saifuddin F.
Published: December 2007

The Yakin West Waterflood project, which commenced in 2000, applied on depleted reservoir 19-6 and 21-2 sands which had a forecast primary recovery of 27%. The business case scenario resulted from reservoir simulation, which demonstrated possible recovery enhancement (EUR) of up to 39 %. However, during the implementation, the waterflood system did not maintain the minimum design injection rate of 10,000 BWPD, and injection rate declined to 1,000 BWPD within 2 years. Processing low quality sea water caused the waterflood unit frequent shut-downs, necessitating higher preventive maintenance. Consequently, waterflood response delayed for six months and injectors plugging was common. Due to these adverse circumstances, expected ultimate recovery from the project as implemented is forecast to be 33%.

A 3D reservoir model and simulation was developed to evaluate Yakin West Waterflood performance, incorporating a revised geological interpretation, recent production and injection history, and pressure surveys. Full integration between the geo-model and the reservoir flow model was implemented successfully in this project. Using the reservoir model, the reservoir properties distributions were generated for alternate development scenarios. The reserves ranges primarily reflect in trapped saturation that effecting remaining oil to be drainned, and variation in water rate. An assessment of the robustness of the history match to grid size and facies distribution was also undertaken. This model was used as a tool for evaluating further well work activities and infill drilling opportunities. This methodology for obtaining accurate prediction of these outcomes has furthered our understanding of field performance and forecasting methods.
A Fracture Treatment Design Optimization Process To Increase Production and Control Proppant Flowback for Low-Temperature, Low-Pressure Reservoirs
Authors: Krismartopo B. D. , Notman L. , Kritzler T. , Kristanto T. , Nguyen P.
Published: December 2007

As the pumping pressure is released at the end of a fracturing treatment, the proppant remains in the fractures, holding them open and forming conduits for fluid to flow into the wellbore. If the proppant flows back into the wellbore, the width of the fracture channels will decrease. The loss of proppant from the fractures limits the flow-channel conductivity, choking the production potential of the well and impairing the effectiveness of the fracture treatment.

Resin-coated sands, oriented perforating, tip screen-out designs, and screens are just some of the technologies that have been applied in the past to overcome the aforementioned problem. For low-temperature, low-pressured reservoirs, the challenges increase because even small pressure drops or conductivity reductions can have a large influence on the final production results, and resin-coated sand will not cure effectively at temperatures below 130°F.

This paper highlights how a proppant production problem was successfully overcome through the application of several technologies. Statistical analysis was used to help evaluate these technologies during the trial period, indicating that orientated perforating had a limited influence on the proppant flow-back, but a negative impact on production. However, with the help of a tip screen-out design and a newly developed proppant flow-back control additive, the proppant flow-back problem was overcome and production was improved.
A Proposed Data Acquisition Program for Successful Geomechanics Projects
Authors: Chardac O. , Murray D. , Carnegie A. , Marsden J. R.
Published: December 2007

There has been a growing interest in geomechanics in the oil industry. From simple rock mechanical properties to fully coupled reservoir geomechanics simulation, real-time wellbore stability monitoring, stimulation job design, or sand management, the value of geomechanics has now been demonstrated and is applicable throughout the entire life of a field. Because it has become a key component for a number of departments, geomechanics is now considered a discipline by itself, and most of the major oil companies have established their own teams of rock mechanics experts.

The mechanical earth model is the core of any geomechanical work. It is an integration process characterizing the field in terms of rock mechanics properties. Like any other type of project, it requires a minimum amount of specific information to be successful. Practically speaking, because data acquisition programs rarely focused on rock mechanics aspects in the past, it often appears that part of the key data required to perform a proper evaluation is not available. In such a case, one may have to use correlations to estimate the missing information or apply default parameters with their associated uncertainties. Ultimately, there is no equivalent to real data to ensure the accuracy of any study.

The paper summarizes the data requirements for a reliable mechanical earth model and proposes a standard data acquisition program that would guarantee the availability of critical information. It will demonstrate that most of the data required are needed for other disciplines as well. The key is to make sure it is systematically acquired.
First Installation of Hydraulic Flow Control System (Smart Completion) in Saudi Aramco
Authors: Al-Dossary A. S. , Salamy S. P. , Mubarak H. K. , Al-Aqeel S. A. , Boyle M. S.
Published: December 2007

Saudi Aramco has successfully installed the first Hydraulic Down Hole Flow Control System in Saudi Arabia in March 2004, in Shaybah field. In 2002, Saudi Aramco optimized its drilling strategy by drilling Maximum Reservoir Contact (MRC) wells in Shaybah field to improve well productivity by providing maximum reservoir contact and to reduce the development unit cost of drilling and production. In addition, it was necessary to equip selected wells with the options of laterals isolation and a flow control system in order to maximize the benefits of these wells.

The objectives of using such a system are to improve the reservoir's management, increase the life of the well and to avoid intervention.

This well was drilled as a multilateral (Tri-lateral) well targeting one reservoir with total reservoir contact of 8.7 km (28,670 ft). This paper will discuss the difficulties that were encountered during the planning, drilling, and finally installation and testing of the system. Extraordinary efforts were made to ensure the success of this system as it has a great impact on future installations of such technology in Saudi Arabia.
Evaluation and Implementation of Coating Damage and Repair Techniques: A Case Study on 36-in. Badak-Bontang Pipeline
Authors: Priambudi A. , Tranggono N. W. , Somoprawiro S. , Sanjoto P. D.
Published: December 2007

Base on the intelligent pigging survey result, it is believed that the external corrosion was caused by disbondment of the asphalt enamel coating on the 36″ Badak-Bontang pipeline. An electromagnetic technology method is selected to locate and measure the coating damage level. In conjunction with the coating damage evaluation, coating repair was also being assessed. Following field demonstrations from various vendors, a liquid epoxy coating was finally selected, due to its performance, ease of application and relatively long pot life.

Following the receipt of the final coating survey report, the defective areas along the pipeline were positively identified, and excavated for verification. The pipe which have coating damage were repair by removing the existing coating, cleaned back to bare steel to allow application of the new liquid epoxy coating.

This was an excellent example where research, field-testing and evaluation through good engineering practices have resulted in significant cost savings.
Advanced Hydraulic Fracturing Treatments in the Wushenqi Low-Permeability Gas Field: A Workflow to Minimize the Learning Curve
Authors: Lei Qun , Tao Lu , Liu Hai , Tibbles Raymond , Guo Wei , Hou Hui Jun , Ramsey Lee , Meisenhelder Jeff
Published: December 2007

The Wushenqi gas field is a low permeability gas play under development by the Changqing Oilfield Company of PetroChina (PCOC). The first well in this field was drilled and hydraulically fractured in 1994. Out of the ten wells initially drilled, nine were hydraulically fractured using a design based on historical knowledge and area best practices. The average gas production of the 10 wells was 586000 scf/day (16,600 m3/day), which was less than the production required for economical development of the field.

This paper details how Changqing Oil Company and Schlumberger used an optimization workflow and integrated study to improve the completion procedure and increase well productivity.A new field development plan was created based on the following: Advanced seismic interpretation.Geological and petrophysical analysis.Analysis of postfracturing production data.Production forecasts from a new reservoir model and a model of hydraulic fracturing optimization.Completion optimization.Economic evaluation.

Some of the significant results from the study include: An improved understanding of the location of the sand bodies resulting in better control on placement of new wells.A correlation which adjusted the log- derived permeabilities in order to more closely match permeabilities obtained from transient testing and production analysis.An improved well design reflecting data acquisition, fracturing process, and production requirements.A modified fracturing treatment design tailored for the expected Kh and deliverabilty requirements of the various zones.An on-site test program using pre-fracture treatment injection testing to verify the permeability.
A Type of Advanced Mud-Hammer Applied to Oil Drilling
Authors: Jian Z. , Shang J.
Published: December 2007

A kind of percussion rotary drilling system applied to oil drilling, which includes a mud-actuated hammer as a key element. The overall goal of this system is to rise up the ROP and to provide significant cost reduction and technical advantage over current drilling practice particularly in deep, medium-to-hard rock formations. This paper describes a new type of efflux mud hammer, its structure principle and latest experiment results in some detail.
Reservoir Characterization Through Single-Well Numerical Simulation Study Using DST Matching for a Gas-Condensate Reservoir
Authors: Ariadji T. , Suryanto H. , Mariani S.
Published: December 2007

This paper applies a single well numerical model using a reservoir simulator and accommodating geological data such as depth structure, gross and net thickness, and distribution of petrophysical properties to interpret a DST data. History matching pressures and rates of the DST data is conducted after incorporating the geological, reservoir engineering, and production data.

In this single well simulation study, three DST data from well North Belut 3 are as the matching target used in the history matching using commercial numerical simulator with black oil formulation and three dimensional models. The PVT data is generated from an EOS model in which pseudoization is applied to reduce the components into 9. A one and a half foot model, or total of 1309 Z-grid dimension, is used to accommodate facies inconsistency and fluid gradient changes. Capillary pressures are obtained from mercury injection laboratory experiment of samples from four wells and are distributed according to permeability range values. On the other hand, the permeability curves are generated using the Corey function.

The interpretation through the history matching process is described in steps to show advantages of using this method. Correct PVT fluid type, absolute permeability, and skin factor are the most affected on the pressure and rate matching process. The steps could explain and improve the understanding of reservoir characterization. The results are also compared with the analytical interpretations, which study is already done before by other person, to see the reliability. A good agreement on the permeability value is gained, with a possiblility of different net to gross ration interpretation. The skin factors of the numerical method are reasonably positive values, and tend to much less than the analytical results. This SPE-93218 suggests that the near well bore damage may not as bad as the analytical interpretation implied.
A Novel Approach for the Evaluation of Oil and Gas Well Performances in Multiwell Reservoir Systems
Authors: Marhaendrajana T.
Published: December 2007

The current methods for estimating Oil- or Gas-In-Place and Reservoir Flow Capacity using dynamic data (pressure and/or rate) assume a single well in a closed system (or single well with constant pressure or prescribed influx at the outer boundary). In many cases a well produces in association with other wells in the same reservoir – and unless all wells are produced at the same constant rate or the same constant bottomhole flowing pressure, non-uniform drainage systems will form during boundary-dominated flow conditions.

The approach presented in this paper accounts for the entire production history of the well and the reservoir and eliminates the influence of well interference effects. This approach provides much better estimates of the in-place fluids in a multiwell system, and the methodology also provides a consistent and straightforward analysis of production data where well interference effects are observed.

This paper also presents the computation of flow capacity and skin factor using the multiwell approach.
Pressure Transient Results Demonstrate Utility of Cased-Hole Formation Tester
Authors: Joshi S. , Siwindono T. , Bunyamin M. , Basya D. , Harun H. , Krisna R.
Published: December 2007

Gunung Kemala is a mature oilfield located in South Sumatra province of Indonesia, which was discovered in 1937 by the Royal Dutch company and is currently owned by the Indonesian national oil company, Pertamina. Declining field production led Pertamina to target some previously unexplored deeper reservoirs in this field, termed as the "Upside Potential" zones. Drilling the wells was a challenging task because of the combined presence of depleted reservoirs and virgin zones. Hence acquiring correct pressure information was a primary objective in the re-evaluation plan.

Openhole wireline formation testing was ruled out due to the experience of high sticking risks in this environment. Pertamina had earlier tested these reservoirs using drillstem tests (DST's). However, the DST's had been extremely expensive and time consuming, due to the many layers that needed testing, and were sometimes inconclusive.

Consequently Pertamina decided to try out a new wireline conveyed cased-hole formation tester capable of drilling a hole through casing, measuring formation pressure, identifying formation fluids, capturing PVT samples and finally plugging the hole with a metal to metal seal. This could significantly reduce testing time as well as the chances of tool sticking. Another objective was to obtain formation radial permeability for the tested zones. Therefore, the testing program was designed to incorporate an extended pressure buildup (PBU) test for each zone.

This methodology was applied in 2 wells, GNK-X3 and GNK-X4, of the field. A total of 6 points were successfully drilled, formation pressures measured, reservoir fluids identified in real time and 6 PVT samples captured. Extended PBU's were also carried out at each point till radial flow was reached and radial permeabilities calculated. All but one of the zones tested as hydrocarbon bearing. In one well, 2 hydrocarbon-bearing zones with a large difference in pressure and permeability were identified. This led Pertamina to run a dual completion for optimum exploitation of the zones.

This cased hole formation testing program reduced the risk for Pertamina's operations and successfully achieved testing objectives in an efficient and economical manner as compared to conventional methods.
Effect of Quasi-Piston-Like Flow on Miscible Gasflood Recovery
Authors: LaForce T. , Johns R. T.
Published: December 2007

Multi-contact miscible (MCM) displacements of single-phase reservoir fluids are designed to achieve piston-like flow and optimal recovery of in-situ hydrocarbons. Piston-like displacements occur when the reservoir pressure is greater than the minimum miscibility pressure (MMP) or the gas is enriched beyond the minimum miscibility enrichment (MME). The effect of two hydrocarbon phase reservoir fluids on piston-like flow and recovery in MCM displacements have not been considered in detail in theoretical or experimental research. The consequences of two in situ phases may be significant for displacements in capillary transition zones, vertically-graded compositional reservoirs, surfactant floods, or gas condensate reservoirs.

The primary goal of this paper is to explore the ramifications of leading condensate or gas banks on recovery in MCM floods with two-phase initial conditions. We develop detailed method of characteristics (MOC) solutions for 1-D displacement of two-phase initial compositions by gases that are enriched below and above the MME. We consider ternary and quaternary systems to examine the effect of combined condensing/vaporizing (C/V) behavior on recovery.

The results show that in MCM displacements, recoveries can be seriously affected by the presence of two-phase initial reservoir fluids for injection times less than 1.0 PVL The delay in heavy component recovery is substantial for intermediate and large initial gas saturations and could significantly impact the economics of gas injection projects. The results also show that recoveries during dispersion-free MCM flow are affected by relative permeability for injection times less than 1.0 PVL Because flow is MCM, however, recovery increases rapidly to 100% at 1.0 PVL
Gas flood-Flow Pattern Evaluation: Mesozoic Chiapas-Tabasco Basin Field Revisited
Authors: Mercado M. , Martinez B. , Asadi M. , Casas D. R.
Published: December 2007

A gas interwell tracer program was designed and implemented to characterize the flow stream within the current injection/production pattern of the central part of the Mesozoic Chiapas-Tabasco Basin.The field includes one injector and four producers.Due to production, the average reservoir pressure fell and approached the dew point at reservoir conditions.Natural gas was injected to maintain reservoir pressure and optimize condensate production.A chemical interwell tracer was also injected to detect and evaluate the magnitude of any communication between the injection and production wells and to track the areal flow pattern within the field.The study was designed for 18 months and commenced in December 2000 and terminated in mid 2002.The results from the sample analyses provided information on the magnitude of highly permeable channels between the injector and producers as well as flow patterns within the field.Furthermore, the results provided valuable information on breakthrough time and fluid travel time.Sampling discontinued for over a year.In late 2003, it was decided to collect more samples from the same four production wells as well as one of the offset wells.The new sample analysis results indicated tracer concentrations at high levels from all of the wells except one.Based on these new results, a new sweep efficiency and total volume swept between the injection and production wells were calculated and are presented.Finally, an overview of formation heterogeneity, based on the three years interwell tracer study, is presented.
New Step Rate Test Analysis Technique Aids Determination of Fracture Pressure for Waterflood Design in Kuwait Reservoirs
Authors: Mandal D. , Qazi A. , Abdullah S. , Bu-Qurais A. , Hughes S.
Published: December 2007

Zubair and Upper Burgan are important clastic reservoirs in North Kuwait. Phase 1 of the North Kuwait Waterflood Project includes peripheral water injection for pressure maintenance of these reservoirs. Injection at matrix conditions commenced in mid 2001 and though initial injection rates were promising, injectivity declined rapidly in many wells. Various remedial actions were unsuccessful in achieving sustained injection at desired rates. Subsequently, a series of Step Rate Tests were conducted which indicated that desired injectivity could be achieved if injection was above fracture conditions. Consequently, measurement of fracture pressures for the reservoirs assumed key importance for forward planning and design of injection facilities for Phase 2 of the Waterflood Project.

However, it was found that interpretation of fracture pressures from the step rate tests was difficult in certain cases, using the classic approach of rate vs pressure plots, because the change in slope above fracture pressure was very subtle, leading to uncertainty in fracture pressure determination. To facilitate interpretation and reduce this uncertainty, a new diagnostic technique was developed.The technique involves plotting and analyzing the cumulative change of rate per unit pressure against bottom hole injection pressure. This provides more accurate interpretation of the data in those cases where slope change is difficult to interpret using the classic approach. As a result, the technique has ensured full use of the available data, which otherwise would have been inadequate for confident determination of the fracture pressure of the reservoirs. The results obtained are critical for determination of well head injection pressures for the design of surface injection facilities for Phase 2 of the waterflood project.

This paper summarizes the application of this new technique and demonstrates its distinct advantage over classic industry methodology in cases where fracture pressure analysis would otherwise be problematic.
Peciko Geological Modeling: Optimizing Fluid Distribution and Model Resolution of a Giant Gas Field in a Shale-Dominated Deltaic Environment
Authors: Samson P. , Dewi-Rochette T. , Lescoeur M.
Published: December 2007

A Geological model is the image of the understanding of a field according to available data. Through time new data allow generating more detailed models. Peciko Gas field is interpreted as complex shale dominated deltaic environment deposit. Modeling strategy is pragmatic, based on a 2D approach. Its resolution is optimized through time. Methodology focuses on multi-disciplinary data integration for interpreting and modeling fluid distribution. Final goal is to provide reservoir model with major flow barriers.