bluuebunny/crossref_metadata_2025 huggingface dataset:
Advanced Chemical Water-Shutoff Treatments in Multilayer Gas Reservoirs: A Case Study from Peciko Field, East Kalimantan, Indonesia
Authors: Samvelova Marina , Haekal Muhammad , Kristanto Tutus , Kusuma Dadik Hendra , Mahardhini Antus
Published: January 2012

The Peciko field is situated offshore of East Kalimantan, Indonesia. The majority of the reservoirs in this field are gas producers with water. The average production is more than 650 MMscf/D with 11,000 BWPD. The reservoirs are characterized as multilayered sandstone water-sensitive formations with varying permeability ranging from 0.1 md to 2 darcy. The measured depths (MD) of the perforated producing zones extend from 9,400 to 11,100 ft, with an average reservoir bottomhole temperature of 240°F (115°C).

Significant water breakthrough was experienced from some reservoirs, which led to dramatically reduced total gas production per well—up to 90% in recent years (water-gas ratio [WGR] ranging from 100 to 1,000 bbl/MMscf). The goal was to reduce WGR to help prevent the water-source reservoirs from killing the other producing layers and to stabilize the flowing conditions. This could be achieved by shutting off the undesired water production. The main challenge of the field is the number of reservoirs opened per well (>25 perforated reservoirs), with short distances between the perforated zones. Mechanical isolation was impossible in these cases because it would create restrictions during future interventions. Previous bullheading methods using water-shutoff chemicals were not always sufficient because theysacrificed producing reservoirs above. Selective treatment with organically crosslinked sealant gel using an inflatable packer as the upper isolation deployed by coiled tubing (CT) and a retrievable bridge plug used for the bottom isolation was successful in shuttingoff the watered-out sands, while keeping the upper reservoirs producing up to date.

This paper discusses the methodology of the job design, with a detailed operation sequence and results obtained from the field.
Effect of Gas Lift Gas Composition on Production Stability / Instability by Dynamic and Steady State Simulation for Continues Gas Lift Injection Mode
Authors: Maijoni A. , Hamouda A. A.
Published: January 2012

Gas lift is one of the artificial lift methods that is used to increase oil recovery by gas injection into production tubing. At the injection point, chocking effect has been identified as one of the factors that affect production instability. Fluctuation of the injected gas pressure, affects the gas/liquid interface behavior.

Influence of the gas composition on the production efficiency, to our knowledge, has not been addressed in literature as an additional factor that plays role in efficiency. The flow instability leads to discrepancies between the forecasted and the actual production.

The main objective of this study is to address the production instability of gas lift wells in transient (dynamic) and steady state simulations for continuous gas injection regime.

Sensitivity investigations for stability analysis are performed for the various gas compositions, gas injection rates, injection pressure, prudctivity index (PI) and gas lift valves (GLV) port size. The results show that higher gas density, higher gas injection rate, higher injection pressure, higher PI and lower gas lift port size can stabilize the gas lifted well. When, relating the gas composition to density for black oil in dynamic and steady state simulation, it is interesting to see opposite effects are obtained from the results that are obtained these simulations, where dynamic simulation shows that the heavier gas gives larger production rates compared to lower gas density, while the opposite is obtained from the used steady state simulator.
Business and Technology Innovation: Essential Imperatives for Future Energy Sustainability
Authors: Kelechukwu Ekeh Modesty
Published: January 2012

Exploration of petroleum resources is considered synonymous with the lifeblood of modern society and how it meets its energy needs. Yet, the entire globe has been unimaginably seized by the soon visible energy crisis and consequently demanding from humanity a systematic blue print of its sustainability. The future looks very different from our routine hydrocarbon exploration and production practices, hence to succeed in such future, players in the petroleum industry will need innovative business strategy to make their portfolios more diverse; develop new technologies that will help to establish the heartlands of sustainability; globalise operations and best practices; and invest in partnerships that create value across the strata of stakeholders. However, energy sustainability is a complex challenge, which involves, among others; petroleum industry players, private sector and Government. While parallel development in creating business friendly-environment and innovative technological advancement will serve as a vehicle to enable success in future energy sustainability. Technology will significantly influence the availability, choice and cost of future energy. Investment in R&D is crucial to provide energy efficient-technologies through private sector partnership. Business plays an important role in energy efficiency and sustainability, within its sphere of responsibility, in partnership with stakeholders and investment diversification. It should be taken into account that business operates well under sound predictable long term enabling frameworks and good governance. This paper focuses on the opportunities of inventing new conceptual dynamics to ensure sustainable energy Future.
Manifold Production Enhancement through Effective Horizontal Well Placement within a thin Heterogeneous Silty-Sands Reservoir: A Successful Case for the First Time in Wasna Field, India
Authors: Sapkal Arvind Vilasrao , Kar Somenath , Kumar Surendar , Majumdar Chandan , Kumar Rajeev Ranjan , Vashisht T S , Keot Chandan Jyoti
Published: January 2012

Prime objective of horizontal wells is to enhance production by maximizing reservoir contact. Hence it is extremely essential for deviated section to land accurately on top of pay horizon followed by optimum placement of horizontal section. Lateral formation heterogeneity in terms of thickness, lithology and stratigraphic pinching out makes proper horizontal well drilling through deltaic silty-sand reservoir in Wasna field, India; a real challenging job. Absence of Seismic data also adds structural dip uncertainty to the complexity of these targets. Real-time decisions making via optimal well placement technology are useful to drill these wells in a cost effective manner.

In the studied field, several attempts were taken previously to drill horizontal well geometrically but the production result was never encouraging. Manifold production enhancement through accurate horizontal drilling has been achieved using conventional well placement method for the first time in this field. Well Placement workflow involves real time well trajectory designing while drilling based on layer earth model updation using LWD Image and Log data.

The high resolution LWD images in real time have been instantaneously utilized to compute the orientation of the geological features across the borehole with high degree of accuracy. These computed orientations along with real time log data is used to update the near wellbore structural and stratigraphic model. Accurate configuration of subsurface layer earth architecture helped in effective forward designing of the well trajectory.This interactive 24X7 real time process finally enabled the successful horizontal well drilling within 1.5 m thick sweetest part of the reservoir. The well was placed with 95% NTG resulting around 5 times increment in initial production compared to the other existing horizontal well.

This paper illustrates an extraordinary successful case study which opens new and exciting possibilities for horizontal well drilling campaign in the Western Onshore India.
The Contribution Of Synthetic Based, Non-Aqueous, Drilling Fluids To The Successful Development Of Mangala Field, India’s Largest Onshore Oilfield
Authors: Sawyer Graham , Lochhead Ian , McKenzie Tim , Peytchev Peter , Uphadyay Abhishek , Marshall David , Vickers Steve , Kosandar Balraj
Published: January 2012

The Mangala field was discovered in 2004 in the sparsely populated, remote, undeveloped Thar Desert of NW India. Mangala is India’s largest onshore producing oilfield and its development was fast-tracked with production start-up in 2009. This paper describes the process of selection, design, testing, and implementation of specific synthetic-based drilling fluids and their advantages (technical and economic) over conventional water-based fluids.

The field development plan includes 109 production (11 horizontal) and 53 water-injection wells, all directionally drilled from wellpads. Newly-designed, mobile drilling rigs predominantly used rotary steerable systems. Synthetic-based fluids were proved appropriate for drilling all main hole sections with a drill-in fluid system custom-designed for horizontal well sections. Strict environmental requirements imposed restrictions on fluid choice, type, handling and disposal in this delicate ecosystem. Over 18 months of continuous drilling, 3 rigs have drilled 130+ wells using and reusing these muds. Rigs are fitted with Hi-G shakers using selected fine screens to ensure tightly controlled Particle Size Distribution (PSD) and drilling fluids are constantly monitored for consistent specifications. Advantages delivered by these muds include very low fluid invasion, excellent return permeability, low filter cake lift-off pressure and high ROPs. This drives drilling performance and has resulted in worldwide top-quartile benchmark ranking in the industry standard database. Planned casing installations, data acquisition and hole sections have been successfully delivered in all wells. Horizontal wells, drilled with 8.5" reservoir sections and completed open-hole with sand screens have delivered record flow rates for onshore India, up to 14,000bopd. The field is currently on production at 125,000bopd.

These custom-designed synthetic-based drilling fluids have been a major contributor to the successful drilling and completion program at Mangala. The top-quartile drilling performance has achieved significant cost savings while still delivering highly productive wells, including the longest, most productive, onshore horizontal wells in India.
Rate Transient Analysis and Investigation of Unit Slopes in Multistage Hydraulically Fractured Tight Carbonate Reservoirs
Authors: Bello Rasheed O.
Published: January 2012

Carbonate reservoirs constitute about 30% of the world’s most active reservoirs and are thus important. The focus of this paper is on the tight carbonate gas reservoirs that are only economic when produced by completing with a multistage hydraulically fractured horizontal well. A unit slope has been observed on a log-log plot of production gas rate against time. This unit slope and flow regime occurs after the one-half slope indicative of linear flow. The objective of this paper is to investigate these flow regimes and provide a method of analysis.

Numerical simulation is the primary method of investigation employed in this paper. Several runs were made with the following variables: reservoir boundary dimensions, hydraulic fracture spacing, phases, hydraulic fracture length and number of stages.

It was concluded that the appropriate reservoir simulation model which results in the observed flow regimes in actual well data is a bounded rectangular reservoir containing a centrally located horizontal well with transverse fractures contacting the reservoir boundary. The main flow regimes observed are linear flow and Unit Slope Flow Regime (USFR). Linear flow occurs with drainage from the reservoir matrix into the transverse fractures. The USFR begins when there is interference between the hydraulic fractures and ends when the fractures drain the reservoir as a unit. The appearance of these two flow regimes, either singly or with the linear flow preceding the USFR, is controlled by a critical fracture spacing. An equation is derived for analysis of these flow regimes to obtain useful reservoir properties for characterization.
Visualization and Analysis of Interaction of Carbonate Reservoirs with Carbon Dioxide During CO2 Enhanced Gas Recovery Process
Authors: Odi Uchenna , Gupta Anuj
Published: January 2012

This paper presents simulation based analysis for CO2 Huff-n-puff and Enhanced Gas Recovery (EGR) process in carbonate rocks that are representative of the Middle East’s aquifers and oil/gas reservoirs. The objective of this study is to study the development of condensate in the near wellbore region of a wet gas carbonate reservoir and to subsequently study the feasibility of using CO2 injection for removing this condensate phase.

Changes in oil saturation, gas saturation, gas permeability, and gas productivity were used to quantify the effect that CO2 has on wet gas carbonate reservoirs. Carbonate reservoir systems have complex structures and to represente these, two reservoir models were constructed that had the characteristics of typical carbonate reservoirs.

Condensates appeared in wet gas systems once the pressure reduces below the dew point pressure. This can be remedied in two ways: (1) repressurizing the reservoir above the dew point and (2) lowering the dewpoint pressure by changing the fluid properties of the reservoir fluid. Both of these remedies can be achieved by using CO2. Results show that CO2 has the ability to repressurize a reservoir and the ability to lower the dew point of a wet gas fluid. Results also show that carefully timing the start of CO2 injection and its duration can significantly improve the economics of enhanced gas recovery process.
Brazeau River Nisku "A" Pool Oil Volume Re-Calculation: A Case History Study
Authors: Chen Andrew
Published: January 2012

The Brazeau River Nisku "A" pool is located approximately 150 km southwest of Edmonton, Alberta, Canada. It has produced 45 °API light oil since 1978 from the pinnacle reefs of Later Devonian Winterburn group. The stock tank oil initially in-place (STOIIP) was estimated from the 2D seismic data to be 33 million bbl. The primary oil production of the under-saturated reservoir pool only lasted two and half years before a dry-gas cycling pressure maintenance scheme was initiated to enhance the pool’s recovery. An infill horizontal well was added in 1992 to the existing two vertical producers, with one-injector to re-inject the produced lean gas back to the reservoir pool from the top of the reef structure, enhancing the pool recovery from a typical gravity drainage mechanism. After 1995, the dry gas injection stopped and the reservoir began pressure blowdown and resumed depletion drive production. By 2010, the pool’s pressure was near a complete depletion. However, the Nisku "A" pool’s performance history data have suggested that 7 bcf more natural gas was produced than expected, raising questions about the long established STOIIP estimate. Numerical simulation studies also failed to reconcile the oil volume estimate conflict between the production performance data and the seismically well-defined volumetric evaluation.

This paper demonstrated, by carefully examining the reservoir appraisal data that the Nisku "A" pool most probable STOIIP is 40 million bbl, instead of 33 million. The 7 million barrels of oil in-place estimate gap could have been easily identified in the first two and half years of production by correctly performing simplistic material balance analysis of the pool’s pressure versus oil and gas rate history and the reservoir compressibility values, which are often taken into granted by engineers in resource and reserve evaluations.
Introduction of a Modified Rotary Steerable System in Papua New Guinea Improves Drilling Performance in Poor Quality Wellbores with Tectonic Breakout
Authors: Dow Michael , Schmickl Christopher , Ross Angus , Baggio Dion
Published: January 2012

Directional drilling in the Highlands of Papua New Guinea is extremely challenging, especially in the intermediate 12!" hole section. 12!" drilling is through medium strength claystones, where severe tectonic breakout occurs. This results in an extremely poor quality, ledged, ovoid, over gauge wellbore. Traditionally positive displacement motor (PDM) bottom hole assemblies (BHAs) were used to directionally drill in these difficult hole conditions. Drilling performance was far from ideal. Steering penetration rates were typically 50–80% less than those obtained when rotating, even at low inclination, with weight stacking, hang up and motor stalls becoming progressively worse with depth. Additionally, the motor pressure drop placed a hydraulic limitation on flow rates. This limitation handicapped hole cleaning optimisation, which was critical if the abundant large 1–3" cavings generated by wellbore breakout were to be removed from the hole.

An initial attempt to introduce a rotary steerable system to improve penetration rates and hole cleaning had been unsuccessful. It was only with the innovative introduction of a rotary steerable system originally designed for soft formations that success was obtained. Modifications to the original system specific for this new environment brought further performance improvements. Performances will be analysed from a series of wells in Papua New Guinea to demonstrate the improvement obtained by the introduction of this new directional drilling technology. ROP improvement, dogleg capability and improved drilling hydraulics will be presented.
Case Study: Cyclic Steam Stimulation in Sihapas Formation
Authors: Putra Eldias A. , Rachman Yusni A. , Firmanto Tri , Arsyadanie Robbie , Hafizh Gama
Published: January 2012

Viscous and heavy oil reservoir is a challenge in oil production due to unfavorable mobility ratio. Thermal injection is a method to increase well productivity and oil recovery which is usually performs in shallow reservoir. One type of thermal injection is cyclic steam stimulation.

Cyclic steam stimulation was conducted in two wells of Melibur field as a pilot project. Since it has 8–12 cP viscosity, 22–26° API oil gravity and relatively shallow reservoir depth, Melibur has an appropriate character to perform steam injection.

The project started with well selection with the main consideration is amount of remaining oil in reservoir. It is also considering completion diagram and operational aspect for each well. The injection process was performed in 10–12 days with certain injection parameter to meet the heat requirement for reservoir and follow with 5 days soaking.

This paper focuses on the result and effect of cyclic steam stimulation to well and offset wells production rate and fluid properties. Many experiences acquired from the project of cyclic steam stimulation perform in Sihapas formation, one of them is the effect to offset well that indicates there is a connection and high heat conductivity between wells. Incremental of initial production rate about 40% occurred in first well. In second well, this operation gives an effect to offset well with the incremental of production rate reach 100% in nearest well. Oil properties changes with different in viscosity, oil gravity and pour point value after cyclic steam stimulation.
Pressure Drop Prediction in Deep Gas Wells
Authors: Moradi B. , Awang M. Bt. , Shoushtari M. A.
Published: January 2012

Deep reservoirs with very high temperature and pressure are turning to be the main development sites today unlike in the past. Normally these reservoirs contain sour gas. To run measurement tools such as wireline logging are very costly, and because of sour gas rapidly corrodes wirelines it may also be disastrous.

In this paper, effect of heat transfer is studied on pressure profile in deep gas production wells.

The mass, momentum and energy balance equations govern the fluid flow in the wellbore. Wellbore governing equations are solved simultaneous and consequently a procedure is developed to calculate pressure and temperature profiles in deep gas wells.

Result indicated pressure drop is sensitive to temperature profile and there is showed how temperature profile can affect on pressure drop in the wellbore.
Sharing Safety and Safe Behavior to Universities thru Lab Safety Workshops
Authors: Adisoemarta P. Suryono , Riyanto Hadi , Mustar Maladi M. , Adrianto Adrianto
Published: January 2012

Safety and safe behavior at various universities, especially in Indonesia, are still neglected and sometimes this failure to observe safety in lab activities end up with accidents that can be minor such as lost sample, up to major with bodily injury or fatality. As graduates from universities are source of new-hires for the industry, having high-quality graduates that are versed in safety would improve the quality of incoming new-hires and possibly reduce the onboarding process within oil companies. To improve the condition at various university laboratories in Indonesia, Chevron IndoAsia Business Unit (Chevron IBU), has developed a 4-day workshop, called as "Good Laboratory Practices" (GLP) Workshop, that shares industry’s best practices in: safety and safe lab behavior, flammable and combustible materials, basic fire prevention, lab waste management, lab business plan, statistical data analysis, sample custody chain, lab accreditation, and Fundamental Safe Work Principles.

This well-received workshop has been conducted sixteen (16) times, since the inception in late 2006, and will be continued with 4 similar workshops this year. These workshops were conducted to 7 universities and a national lab in Indonesia, attended by lab managers, lab operators, graduate students and other personnel. As each attendee would interact with students, either during classroom or lab sessions, this workshop has been estimated to influence close to 5000 students in improving their safety and safe behavior,

This paper would share the challenges in developing the workshop and initial resistance from university professors, quick hitter and best practices as the program comes to maturity.
EOR Simulation by in situ Nitrogen Production via Denitrifying Bacteria and Performance Improvement by Nitrogen Alternating Surfactant Injection
Authors: Nuryadi Arief , Kishita Atsushi , Watanabe Noriaki , Vilcaez Javier , Kawai Nobuo
Published: January 2012

The mechanism of miscible/ immiscible displacement in nitrogen gas injection as a part of EOR procedure has been understood. However, production of nitrogen inside the reservoir may have different process and impact for oil displacement. Simulation of EOR in sand pack column by involving denitrifying bacteria could be a close approachment to understand this mechanism. Production of nitrogen molecules within the pores possibly increases the system pressure, which may lead to repressurization of reservoir after pressure loss during primary recovery. An experiment for obtaining the evidence of system pressure increment post-incubation of bacteria was conducted within a closed piston vessel equipped with pressure gauge. Pressure within the system raised .35 MPa during 48 h incubation from initial pressure (1 MPa). This gradual pressure increment fact demanded further proves of correlation between additional pressure and effect on oil recovery. Therefore, a sand pack EOR simulation in core flooding apparatus had been performed and shown .2 MPa increment of pressure during 48 hours incubation of denitrifying bacteria with 3% oil recovery from saturated oil volume or 1.5% from OOIP. Biogas molecules generation and local pores re-pressurization in the unswept water flooded zones might become the responsible factors for the additional oil recovery. Sweep efficiency of displacing fluids in sand pack column could be improved with increasing their viscosities. This mechanism was applied by alternating nitrogen injection with surfactant, with expectation that foam formation would occur within the pores. Yet, the experiment showed that the ratio of surfactant to gas during injection did not provide any significant help for the oil recovery, whether foaming occurred or not, but only the concentration of surfactant (around 900 ppm) that did. Suggested methods to improve this EOR mechanism result were to increase biological activity of the agent through nutrition stimulation and combination of biogas product with more viscous metabolites such as natural surfactant.
Reservoir Characterisation of Surat Basin Coal Seams using Drill Stem Tests
Authors: Kabir Akim , McCalmont Steve , Street Tom , Johnson Ray
Published: January 2012

Drill Stem Testing (DST) is a primary means of evaluating skin and permeability of exploration and appraisal wells. It is no exception in the case of Coal Seam Gas (CSG) reservoirs. A modified form of DST is routinely used by the CSG industry in this region (Queensland, Australia) as a low cost means of getting skin, permeability and pressure information for these land based wells which have to be mass-drilled given the nature of these coal seam reservoirs and the well productivity.

In this paper we review about 450 individual DSTs with a variable permeability and skin values. Observed high skin and permeability values from many of these wells called for better understanding of these parameters in conjunction with core and log data. About 50 wells in the subject study were cored. Image logs were run in addition to routine openhole wireline log suite. Some of the abnormal (very high) skin and permeability values could be explained from detailed analysis of these logs. Examples of DST, log and core data reconciliation have been reviewed. Various studies have been conducted to understand root causes of the observed high skin values. Well interference tests have been conducted to understand horizontal permeability anisotropy and reservoir continuity. This DST, log and core assisted reservoir characterisation has opened the way for completion optimisation for more than 6000 wells to be drilled in the Surat Basin, Queensland, Australia.
Making Big Gas Producers Even Better: The Tangguh Experience
Authors: Apolianto Eko , Turnbull Bill
Published: January 2012

Tangguh is a large gas producing development located in Bintuni Bay, in the Papua Barat province of Indonesia, some 3000 km east of Jakarta, the capital city of Indonesia. Gas production from the Vorwata Field and LNG export from the Tangguh LNG facility started in 2009. The field and the LNG facility are operated by BP.

The Vorwata development consists of 14 wells drilled from two normally unmanned platforms. The wells were predrilled prior to completion of the LNG plant and are completed as 7" monobores. They are perforated conventionally and are limited to 240 MMscfd each due to erosional considerations. Production from the field is currently 1.3 Bscfd; this rate being limited by the throughput capacity of the Tangguh LNG plant.

During the initial testing phase following completion and prior to start-up, the wells were limited by the infrastructure to a maximum rate of 100 MMscfd. Pressure transient analysis (PTA) of the data obtained during this test phase indicated that most of the wells had high mechanical skins. A reservoir preservation study showed that these high skins were caused by near wellbore damage and could theoretically be reduced by producing the wells at higher rates.

Following start-up and establishment of stable plateau production, a rigorous well clean up and maximum rate testing program was carried out. The wells were flowed at rates up to 240 MMscfd and pressure build up (PBU) tests were subsequently carried out to evaluate any improvement in reservoir deliverability. The analysis of the post maximum rate test PBU data showed that the skins were reduced on average by 40% in each well.
In-situ Combustion Using Sugar Dust, "Sweet Reservoirs"- A Smart and Better Alternative
Authors: Roy Panchamlal , Kasat Sanket , Pandey Rohit , Patel Himanshu , Sahay Pranav
Published: January 2012

Heavy oil recovery has been an area of continuous research and improvisation. In Situ Combustion has been a technology full of promise and potential. The possibility of very high recovery makes this technique highly lucrative. However, the technical uncertainties and high cost poses a major problem. This paper suggests the use of sugar dust suspended in air as an alternative to water co-injected with compressed air/natural gas mixture used in In-situ combustion in order to overcome the above mentioned problems.

Sugar dust is a bi-product in the sugar industry and is treated as a waste material. Hence, its use will reduce the cost significantly. Another problem faced in implementing In-situ combustion is the occurrence of Low Temperature Oxidation (LTO) which creates many problems. However, Sugar dust suspended in air forms a highly combustible mixture and is capable of generating temperatures in the range of 800-1000°F which leads to occurrence of High Temperature Oxidation (HTO) only and thus eradicates any possibilities of LTO. An analytical study was undertaken of a dry combustion tube test data of a Louisiana heavy oil core. H/C ratio, oxygen to fuel ratio and air to fuel ratio was computed for the new suggested technique and compared with the existing values for the same. A similar analytical study was done for another combustion tube test data for a heavy oil core. Fuel requirement and air requirement was computed for the suggested technique and compared with the values observed for the normal ISC process. The comparison yielded positive results for all the parameter considered. Encouraged by those results an analytical and numerical case study was undertaken of a heavy oil field in Gujarat (India).The air requirement was seen to be reduced from 220sm3/m3 to 72.6sm3/m3. An economical analysis showed that the cost of oil production reduced by significant amount for that field.

Further, sugar dust concentration can be easily altered to facilitate auto ignition eradicating the need of artificial ignition. Combustion of sugar dust produces CO2 and steam. CO2 produced will be imbibed on oil surface and the viscosity will be reduced. Steam produced will aid in the displacement of the oil towards the producer well. Also, air requirement for the suggested technique would be very less. Hence, Sugar dust can revolutionize the in-situ combustion operation.
A Novel Enzyme Breaker for Mudcake Removal in High Temperature Horizontal and Multi-lateral Wells
Authors: Al-khaldi M. H. , Ghosh B. , Ghosh D.
Published: January 2012

Effective removal of drilling-mud filter cake during well completion is essential to reduce the formation damage caused by drilling activities in many production and injection wells. This task is very difficult to achieve, especially in horizontal/multilateral wells. Harsh chemical treatments (acids, oxidizers, and chelating agents) have been used extensively to conduct water-based mudcake cleanup treatments. However, these approaches have been limited due to the associated high corrosion rates and un-even mudcake removal. With their controlled reaction with the mudcake, mild chemical nature, better health, safety and environmental (HSE) profile, enzymes provide an excellent alternative to harsh chemical treatments in high temperature formations. However, their use has been limited to relatively low temperature applications due to their instability at elevated temperature values.

In this work, two enzymatic systems were evaluated: old a-amylase system and new structurally reinforced a-Helix system. The old enzyme was found to form a potentially damaging precipitate at reservoir temperature above 100oC. The degree of this damage was assessed using size-matching technique and core-flood experiments. This potential of secondary formation damage was drastically reduced in the new improved enzyme system. Enzyme denaturing was minimized by protecting the catalytic center using preferential hydration of proteins with a Polyol.

The effectiveness of the new system was proven in the lab through comparative tests. Bioassay by reducing sugar estimation showed better biopolymer hydrolyzing capability of the new system at higher temperatures. In contrast to old enzyme system, core-flood experiments, conducted at high temperatures, using new enzyme system, showed the enzyme denaturing did not occur and the core oil permeability increased at stabilized pressure. In addition, this paper will also highlight the advantages and disadvantages of each enzyme system in terms of stability, compatibility, and mudcake damage reversal.
Evaluation of Shear Forces and Stream-Thrust Forces in Torque and Drag Analysis
Authors: Mirhaj S. A.
Published: January 2012

Excessive torque and drag is a major challenge in drilling and completion of extended-reach wells and horizontal wells with high degree of 3D geometry. Torque and drag modeling is regarded as an invaluable process to assist in well planning and to predict and prevent drilling problems. Some wells can be drilled, but may not be completed due to high friction.

Most of today’s torque/drag models are based on the work of Johancsik et. al. (1984) and Sheppard et. al. (1987), while a more comprehensive model is derived by Mitchell and Samuel (2009).

If we assume the drill-string as the elastic-solid material, then a solid material can develop shear stresses. In this study the effect of shear forces on torque and drag modeling has been analyzed. This force is usually ignored in industrial softwares. The effect of disregarding bending stiffness in the equilibrium equation of the drill-string has been stated shortly with some field examples.

Moreover the effect of stream-thrust force on the axial force has been assessed. One part of this force is hydraulic force acting on the closed-end pipe when it is stabbed into the wellbore or by larger diameter pipes when the string is pulling out of the hole. The resulting force together with pressure-area force which is a force resulting from different pressures inside and outside of the pipe has been put together in one equation and it will affect friction in the wellbore that has been addressed here. In other words effective force which is the summation of the axial force and stream-thrust force will be replaced by axial force in the force balance equations. The above-mentioned factors have been implemented in a field case-study. Hence the importance of these forces in the torque-drag modeling in the wellbore has been identified.
Development of Isotherm Polymer/Surfactant Adsorption Models in Chemical Flooding
Authors: Dang Cuong T. , Chen Zhangxin , Nguyen Ngoc T. , Bae Wisup , Phung Thuoc H.
Published: January 2012

The injection of chemical solutions plays an important role in increasing the recovery factor of mature fields. For many reservoirs, polymer or surfactant flooding is an attractive alternative to conventional waterflooding; it can improve the area swept efficiency not only in the macro scale but also in the micro scale.

Adsorption of polymer/surfactant on reservoir rock is an extremely important parameter for chemical flooding. Adsorption represents a loss of a chemical agent from solution, and consequently, a net reduction in the surfactant-polymer slug. Therefore, the efficiency of chemical flooding will be significantly diminished not only in technical aspects but also in terms of economics. However, adsorption is usually measured in laboratory scale with high uncertainties, and numerical simulation of multi-component adsorption is still limited. The adsorption process in a polymer/rock system has not yet been well developed, especially for highly heterogeneous reservoirs. In this paper, the polymer and surfactant adsorption processes are modeled by the Langmuir isotherm theory for various chemical flooding approaches including polymer, surfactant, micellar polymer and alkaline/surfactant/polymer flooding. The simulation results indicate that polymer adsorption strongly depends on the polymer concentration, shear rate, pH, salt concentration, and reservoir heterogeneity. An effective controlling of such parameters can reduce the effect of polymer adsorption so that it helps minimize mass of chemical loss and improve economic efficiency of the chemical flooding process.
The Bulkhead Principle – Delaying Water Cut and Improving Horizontal Well Productivity through Compartmentalization Using Short Swellable Packers
Authors: Smith Peter E. , Young Dustin , Shahreyar Noman , Lauritzen J. Eric , Awang M. Zaki
Published: January 2012

Inflow control devices (ICDs) are used extensively to address the challenges of water management, particularly with the coning effects of water and gas inflow as well as permeability heterogeneity in horizontal wells. Historically, in Saudi Aramco wells, the horizontal open hole has been segmented in up to 6 compartments using mechanical openhole packers However, economic restraints and the risks have limited the running of a larger number of these packers. This paper discusses the development and results of a concept proposed to maximize the production potential from horizontal passive inflow control completions.

In any well, there are uncertainties, both in the reservoir itself and in the operational events that work sequences can cause. A planned completion may not reach total depth (TD), or there may be undetected fractures or high permeability streaks in the reservoir section. A study has been undertaken to further enhance production and to maximize the benefit of inflow-control-device completions with the usage of slip-on swelling packers to increase the number of compartments in the open hole. It is assumed that shorter compartments will lead to an increase in net oil production, because water breakthrough can be managed more efficiently; i.e., the principle similar to that in a ship, where if there are no compartments and the ship leaks, it will fill with water and sink. If the ship uses bulkheads to form small discrete compartments and leaks, only the compartment with the hole is water filled. Likewise, if a well starts to produce water but is compartmentalized, only the section or sections with water will flood; the rest will continue to produce oil.

In addition, we know through wireline logs, logging while drilling (LWD), or through the actual drilling results where we expect water or gas breakthrough to occur, but we are not able to predict with repeatable accuracy the nature of the fracture network in the matrix behind what we can see in the near wellbore environment. Then, it becomes beneficial to attempt to eliminate this uncertainty by increasing the number of compartments where the breakthroughs can occur.

The short slip-on swellable packer, which was developed to provide a cost-effective annular isolation method, will be described in the paper along with the testing processes and field-trial validation that included nearbore simulation and modelling. The system has been proven as successful for sandstone and carbonate reservoirs.
The Successful Development Strategies of Tigh Oil Reservoir: Achievements versus Future Directions
Authors: Dang Cuong T. , Chen Zhangxin , Nguyen Ngoc T. , Bae Wisup , Phung Thuoc H.
Published: January 2012

The Oligocene reservoir of White Tiger field is a tight oil reservoir with high heterogeneity and complex geological characteristics. In such complex reservoirs, a detailed geological understanding of the reservoir along with a reservoir simulation is needed to gain a detailed reservoir description and determine the optimal recovery method for this oil reservoir. These are essential in order to have successful operations as well as reducing uncertainties and improving the efficiency of oil field management. With a large database collected from initial production stages of over 50 wells, the authors developed an integrated static and dynamic workflow to forecast oil production under several production scenarios. The challenges of development strategies in such tight oil reservoirs are analyzed and compared with those one in the typical sedimentary reservoir as well as naturally fractured basement reservoirs. In addition, the authors proposed a successful assisted assisted history matching by global optimization to construct a reliable model for complex reservoirs. Finally, this paper provides a comparative evaluation of enhanced oil recovery feasibility by surfactant polymer flooding in tight oil reservoirs. A series of laboratory test and compositional reservoir simulation were performed and analyzed by both experiments and commercial simulator. The results prove that cumulative oil recovery by surfactant polymer flooding increases more than 1.44 times in comparison with water flooding. This is a solid evidence for a promising successfulness of surfactant polymer flooding in complex reservoirs.
Risk Based Management of Hydrocarbon Sub-Sea Pipeline Free Spans
Authors: White Christopher B. , Ekawati Dhian , Kartika Ria
Published: January 2012

Sub-sea pipeline free spans occurring from inadequate seabed support can lead to static and vortex induced loading which results in pipeline failure. At best, this could effectuate a small crack at overstressed welded field joints, at worse, pipeline rupture. The latter may have significant safety, environmental and business impacts, and as a consequence free span management is necessary for incident avoidance and operational reliability.

This paper describes a risk based approach to the management of multiple free spans that exist on the 30" gas pipeline that traverses the Malacca Straits from the NSO-A offshore platform to the gas processing facility at PT Arun, Aceh, northern Sumatra, Indonesia. It draws from an intensive data collection campaign and technical assessment allowing characterization of exposure and tolerances. Remotely operated vehicle (ROV) and Metocean surveys, together with Finite Element Analysis (FEA) conducted on more than one occasion since pipeline commissioning in 1999, has provided the necessary base data inputs.

Pivotal to the analysis is utilization of industry best practices (in particular the DNV Recommended Practice F-105 Free Spanning Pipelines), together with risk assessment tools. Several dozen critical length spans have an elevated risk of fatigue cracking due to duration exposure.

Span management recommendation identifies grout bag pipeline supports as being the most affective remediation solution, amongst others considered.

The literature for actual case trial publications on sub-sea pipeline free span management is limited. This paper is considered to contribute to the emerging understanding of static loading and vortex induced vibrations impacting on the fatigue life of critical assets.
Enhancement of Vorwata Field Reservoir Model by Integration of Pressure Transient Analysis with Real-Time Downhole Pressure Data
Authors: Setiawan Agus , Hird Kirk B. , Curtis Bennett O.
Published: January 2012

Vorwata is a giant gas field located in Bintuni Bay, Papua Barat Province, Indonesia. The field was discovered in 1997 and currently produces approximately 1.3 bcf/d of dry gas from the Roabiba sandstone reservoir. Initial development consists of 14 wells drilled from two platforms. The wells produce through 7-inch tubing and have been tested up to 240 mmscf/d. A Permanent Downhole Pressure Sensor (PDPS) is installed in each well to continuously monitor downhole pressure and temperature.

Vorwata field is a faulted, high sand quality reservoir. The impact of faults on reservoir performance was very uncertain prior to startup. There was great concern the field could be compartmentalized, or at least strongly influenced by flow baffles and barriers. One of the primary subsurface objectives during pre-startup testing was to assess lateral and vertical reservoir connectivity within the development area.

Pressure build-up tests (PBU) were conducted in each well as part of the initial clean up and testing procedure. The initial tests were very helpful in characterizing offset faults. PBUs obtained once the field was put on production are influenced by interference from offset wells, masking any boundary effects. Interpretation of the PBUs is enhanced by applying deconvolution. A pre-startup interference test successfully identified lateral and vertical pressure communication within the development area. The well/fault geometries and reservoir connectivity characteristics obtained from the PBUs and interference test have been used to condition the static and dynamic models.

This paper describes the well testing program that has been implemented to reduce reservoir uncertainty in the Vorwata reservoir during the early phase of field development. Well test and pressure interference results have been integrated into full-field models to better assess future field performance and development decisions.
Optimization of Equity Redeterminations through Fit-for-Purpose Evaluation Procedures
Authors: Worthington Paul F.
Published: January 2012

Equity redetermination is most commonly encountered where a straddling field is developed as a discrete entity through a process of unitization. It is enacted through evaluation procedures that prescribe the technical methodology for requantifying different license shares, or tract participations, in a field unit as more data become available. The formulation of these procedures usually takes place at unitization, it is based on appraisal data, and therefore it is guided by simplified perceptions of reservoir character. For this reason, many such technical procedures have been found to be lacking when they are applied later at the equity redetermination stage. These shortcomings can take the form of ambiguous wording, misleading definitions, technically-inappropriate specifications, contradictory prescription, or simply a lack of sufficient detail to render the intended process meaningful. They have impeded the determination of revised tract participations by triggering inter-license disagreements that might otherwise have been avoided.

With the objective of reducing this unhelpful impact, experience of redetermination situations is used to illustrate the nature and consequences of poorly constructed procedures for the recomputation of tract participations. The analysis is then flipped to generate a framework of key elements of technical procedures together with indications of how they are best implemented. These matters form the basis for a high-level set of protocols for a more efficient and effective redetermination of equity that would avoid the previously encountered shortcomings. The protocols encompass the proper incorporation of data character, a sound technical basis for redetermination, a balance between under- and over-prescription, an auditable deterministic ethos, and adherence to good international petroleum practice. They constitute recommendations for a better approach to the compilation of fit-for-purpose evaluation procedures within those unitization agreements that make provision for a future redetermination of equity. The recommendations are equally applicable to domestic and international unitizations. The principal benefit lies in an enhanced efficiency of the equity-redetermination process, which feeds through to a greater collective asset value.