NotesNov-09NOTES:The papers listed here have been obtained by search SPE and IPTC papers post 2005 on the SPE's OnePetroThe papers relating to reservoir engineering have been catergorised for inclusion on the reservoirengineering.org.uk websiteThe affiiations searched were;

Total No PapersReservoir Engineering RelatedBP551175Shell575279Chevron482238ConocoPhillips19168Marathon5537Total255129Schlumberger1130563Imperial College, London9553Heriot Watt University, Edinburgh 235175(Anywhere in Article)Total35691717Total number of papers published post 2005 =10,00035% of papers published categorised

Well DeliverabilityOrganisationSourcePaper No.ChapterSectionSubjectTitleAuthorAbstractSHELLSPE101038Well DeliverabilityAcid TreatmentsCase StudyA High-Success-Rate Acid Stimulation CampaignA Case HistoryN. Al-Araimi, SPE, Brunei Shell Petroleum Co. Sdn. Bhd. and L. Jin, SPE, Shell Intl. E&PAbstract A successful acid stimulation campaign was conducted in 2004 in Brunei Shell Petroleum (BSP). This paper discusses what have been done differently best practices and learning. What is different in this campaign from previous ones? Detailed design Detailed well-by-well review for first round candidate selection. Fundamental data collection (well data pressure formation fluids - water and oil mineralogy data and lab tests). Data management system allowing for quick access to well production history data. A design tool (Stim2001) for detailed candidate selection damage diagnosis fluid system selection and job design. QA/QC and compatibility tests aiming to obtain high success rate. In Brunei Shell a self-raising rig (BIMA) with a coil-tubing unit on board is used to overcome the limitations due to weather. A combined pumping procedure (coiled tubing and bull-heading) was implemented to best-fit individual well condition. Close cooperation among different parties (Well services Subsurface technology teams Operation services and Service providers etc.) 6000 bpdoe of initial gain was achieved by this campaign in Brunei with high success rate (no failure on single well was recorded). Confidence level of acid stimulation in Shell Asia Pacific region has been elevated through this stimulation campaign. Lessons learnt and best practices established will be passed to future campaigns. We would like share our belief that acidization is still a good means for stimulating well productivity but it has to be carried our properly. Introduction Stimulating of existing oil and gas producing wells and of new wells is one of the means to maximizing production potentials without requiring extra facilities and drilling new wells. A synergized stimulation process among a geographical region would benefit each individual asset in the organizational structure that was introduced to the region in Late 2003. Acid stimulation in Shell Asia Pacific region has not been very active compared to other regions. The cause of the relatively low stimulation activity varies. Major factors that limit the stimulation activity include: Various success rate Fewer non-stimulated wells from which stimulation candidates could be selected Operational difficulties (as conventional offshore CT operations normally it is time consuming especially rigging time crane usage boat/vessel availabilities and weather down time) Cost structure: coil tubing cost overruns overall stimulation cost Weather conditions make stimulation operation in conflict with other operations in a limited weather window. And added cost due to waiting for weather time. Contractual limitations An initiative of conducting stimulation campaigns in the region was started in early 2004. It was hoped that under the new business structure some syndication among the region during the stimulation campaign would overcome some of the difficulties listed above and benefit each operation unit (OU) and asset. In Asia Pacific region various reservoir types exist. In this paper we will discuss an acid stimulation campaign in high permeability oil bearing sand stone reservoirs in Brunei.TOTALSPE107760Well DeliverabilityAcid TreatmentsERWAcid Stimulation of Extended Reach Wells: Lessons Learnt From N'Kossa FieldJ.M. Mazel and H. Poitrenaud, Total E&P, and P. MBouyou, Total E&P CongoAbstract NKossa is an offshore field located 60 km west of the coasts of Congo in water depths of 170 m. The field is producing light sweet oil from an Albian age reservoir buried between 3100m and 3400m TVD. In order to access reserves located in the southernmost compartments of the reservoir Extended Reach Drilling (ERD) was implemented. Six ERD wells have been drilled to date with lateral extensions close to 6500 m leading to total depths sometimes in excess of 8600m. In addition to the challenges pertaining to the drilling itself the completion also carried its own ones as the formation would require effective acid-stimulation (not only an acid wash) to reach the desired levels of productivity. Stimulation of long intervals and how to ensure full coverage of treatments is a recurrent topic of debate several approaches have been discussed in the literature. In the particular case of NKossa this issue was not only rendered difficult by the length of the perforated intervals (up to 1200m) but also derived from the combination of lithology and permeability contrasts existing in the formation: indeed the reservoir is an alternation of rather tight carbonates (with permeabilities as low as 1 mD) and porous sandstones (which permabilities sometimes reach up to 400mD). The contrast in permeability is unfavorable as the high permeability layers are often encountered at the heel of the drains. Finally the reservoir temperature is 150C (300F) leading to the need for retarded acid systems. Building on the experience acquired from the successive treatments performed on NKossa the methodology and treatment design fluids and diversion have been continuously evolved. The treatments currently involves two phases: An injectivity initiation is performed via Coiled-Tubing creating an artificial thief zone at the toe of the well; then a massive treatment based on emulsified acid and ball-sealer diversion is bullheaded from a stimulation vessel. This paper will discuss design considerations and operational aspects of the acid treatments performed of these ERD wells. We will discuss some of the observations made and present lessons learnt from such treatments. Introduction Located 60 Km offshore from the Congolese coast the NKossa field was discovered in 1984 and put on production in 1996. The current installation includes two wellhead platforms a floating production facility and two hydrocarbons storage floating facilities (one for oil one for LPG). The water depth varies between 150 m to 300 m in the field. Gas and water injection are used for pressure support in the field. The general set-up is showed on fig 1. The reservoir is of Albian age (Senji formation) and is located between 3100 m and 3400 m in TVD; it consists in a succession of carbonated layers and sandstones sometimes silts. The carbonates occur as silto-sandy calcites or and silty dolomites. The calcites are usually of relatively low permeability: 1 to 50 mD and the dolomites have better petrophysical properties with porosities between 15 to 27% and permeabilities between 10 and 100 mD. The natural fracturing is poor the production is from the matrix porosity. The sandstones are fine to very fine with porosities values between 8 and 20% and permeability between 50 and 200 mD sometimes up to 400mD. The sandstone mineralogy can vary from relatively clean to quite carbonated as the carbonate content can often vary between 10 to 30%. Fig 2 gives an illustration of poro-perm data. The bottom hole temperature (BHT) encountered on the wells discussed in the article is 150C. The hydrocarbon quality encountered in the reservoir varies with the depth from a light sweet oil at the base of the reservoir to condensate gas at the top. The need to access the southernmost compartment of the reservoir from the existing facilities lead to the drilling of wells with significant lateral extension (ERD) (see fig 3) and due to the layered nature of the reservoir the drains usually intercept the layers initially at 70 and then levels-off to horizontal or sub-horizontal (88 up to 92); faulting can lead the drain to intercept twice some of the flow-units. Need for stimulation / Rationale As we saw in the previous paragraph the architecture of the NKossa-South wells as ERDs is directly deriving from the important distance between the production platform and the southern compartment of the NKossa field. The drain intercepts the reservoir initially with a high slant and lands horizontally with lengths varying from 600 to 1500m.SCHLUMBERGERIPTC12368Well DeliverabilityAcid TreatmentsProduction OptimisationOptimizing Well Productivity by Controlling Acid Dissolution Pattern During Matrix Acidizing of Carbonate ReservoirsF.F. Chang, SPE, and M. Abbad, SchlumbergerAbstract The chemical nature of carbonate rocks makes acidizing an effective matrix stimulation technique. Acid dissolves carbonates at high reaction rate to create flow channels (wormholes"). The high reaction rate often needs to be reduced to allow wormholes to penetrate deep into the reservoir hence extending the effective wellbore drainage radius. The wormholes created by a retarded acid are deep but thin. During production the flux through the thin wormholes can be so high that high pressure gradient occurs. Therefore the optimized wormhole geometry should be functions of reservoir properties such as permeability and pressure as well as fluid types such as oil or gas. To generate wormholes of various diameters and penetration depths different acid types and volumes have to be used. Acidizing for optimized productivity requires first determining what is desired wormhole pattern. Currently the numerical models focus on computer rendered wormholing pattern by pre-selected acid formulation and volume from past experiences and cost consideration. However it is important to first rationalize the targeted productivity from the specific reservoir have specific properties such as permeability and pressure then to determine the wormhole pattern required to achieve the well deliverability. Finally the acid formulation and volume can be determined to generate the desired wormhole pattern. The discussion in this paper takes a first step toward the goal of designing matrix acidizing jobs in carbonates for delivering targeted productivity. Using a mathematical model a sensitivity analysis is conducted to determine the preferred dissolution patterns for different formation permeability and pressure. It examines the conventional matrix acidizing practices and provides an idea on how the treatment design can be improved. Introduction Acidizing oil and gas wells has frequently been viewed as art than science. Many laboratory researches have been conducted trying to expand and enhance the knowledge of carbonate matrix acidization. Plenty of mathematical modeling efforts are intended to bridge the gap between the laboratory scale studies and the field implementation. However crossing from research to the field applications is still dominated by experience rules of thumb and conservatively copying previous successes in the geographical vicinity.1 2 In sandstone acidizing the acid-rock reaction chemistry is extremely complex.3 4 Nonetheless the dissolution reactions of sandstone constituents are slow and generally considered surface limited they are not affected by the acid injection rate. The materials dissolved by acids are typically the pore lining or filling materials rather than the matrix framework itself. Hence the framework of the sandstone is not significantly altered by the acidizing process. Since the matrix structure is generally intact the entire physical and chemical processes can be modeled by basic fluid flow in porous media coupled with thermodynamic equilibrium among the reactants and products. For practical purposes the models can be used to design field scale acid stimulation treatment and to predict the performance of the stimulated wells. For carbonate acidizing on the other hand the chemistry of acid-carbonate dissolution is straight forward especially for the HCl-carbonate reactions. The acid dissociates into hydrogen and its conjugate base ions. The hydrogen ions attack the carbonate to generate Ca2+ CO2 and H2O. Equation 1 shows acid dissolution of limestone."SCHLUMBERGERSPE126066Well DeliverabilityArtificial LiftESP'sCase Study: First Successful Offshore ESP Project in Saudi ArabiaAhmed R. Al Zahrani, SPE, Redha H. Al-Nasser, SPE, and Timothy W. Collen, SPE, Saudi Aramco; Sudhakar Khade, SPE, SchlumbergerAbstract The Electrical Submersible Pump (ESP) a form of artificial lift technology has proven to be a durable solution for delivering the required rates from Saudi Aramco fields. Therefore this form of artificial lift was selected to increase production rate from one of the offshore fields while optimizing offshore producing facilities. This offshore field has favourable conditions for ESP application producing from carbonate reservoir with no anticipated fines production low GOR low temperature low bubble point pressure and high API gravity. All new installations were carried out without interrupting the ongoing production target. The project has completed a four-years operating cycle while continuously maintaining the field production rate with an acceptable ESP failure and run life. So far 41% of the originally installed ESP systems are operating more than 4 years and 20% are operating in the range of 3-4 years run life. The cumulative average run life of operating ESPs is 2.7 years and that of failed ESPs is 1.74 years. To maintain required production target an effective ESP replacement program is a core element of field production strategy. Therefore several measures such as replacement of underperforming ESP systems and upsizing of the pumps have been implemented. Furthermore Dismantle Inspection and Failure Analysis (DIFA) of pulled ESP systems were conducted to evaluate the root cause of the failures and remedial actions were implemented to prevent such occurrences in future. Increasing Motor Lead Extension cable thickness utilization of tandem seals and new wellhead penetrators are also expected to further enhance the ESP run life. New applications to minimize ESP failures due to human intervention and ensure proper equipment handling during installations are being pursed. In addition tandem ESP completions and different types of wellhead penetrators are being pursued to reduce rig utilization increase producing life and minimize failures. Introduction Saudi Aramco discovered the offshore field in 1963 and placed it in natural production from 1966 until 2004. The primary reservoir is hydraulically supported by natural water influx. The field produces Arabian Medium crude with an average oil gravity of 30 API and 2.7% sulfur by weight.CONOCOSPE114912Well DeliverabilityArtificial LiftFormation Powered Jet PumpFormation Powered Jet Pump Use at Kuparuk Field in AlaskaJ.W. Peirce, SPE, J.A. Burd, G.L. Schwartz, ConocoPhillips Alaska, Inc., and T.S. Pugh, SPE, Weatherford InternationalAbstract Formation powered jet pumps (FPJP) were pioneered for use in Kuparuk Field wells on the North Slope of Alaska. Unlike conventional surface powered jet pumps these pumps are hydraulically powered by a prolific producing upper zone called the C sand to generate greater drawdown on a less productive lower zone called the A sand. Formation powered jet pumps increase oil rate from the A sand while reducing the water rate from the C sand. Gas lift can be used in formation powered jet pump wells to further enhance drawdown on a well while jet pumping. Many formation powered jet pumps are being used in Kuparuk wells with gas lift to increase the drawdown applied to the A sand. An overview of formation powered jet pumps used at Kuparuk Field is presented. Formation powered jet pumps could be beneficial in other multi-zone oil fields around the world to increase oil production rate while reducing water production rate and lifting costs. Introduction Kuparuk Field (Fig.1) is the second largest oil field located on the North Slope of Alaska. Certain conditions make this field an excellent candidate for application of formation powered jet pump (FPJP) technology to improve oil rate from wells. FPJPs are a new artificial lift (AL) innovation developed in the last 10 years. As of 2007 FPJP technology is still only used at the Kuparuk Field. FPJPs have no moving parts excellent durability and are often a preferred AL method used in Kuparuk wells. FPJP installations at Kuparuk are one of the most leveraging forms of well work done in the field based on rate of return on investment. FPJPs are inexpensive to install and have rapid payout periods that are often measured in days. Considering the value of higher oil rate at current high oil prices low FPJP installation costs and lower lifting and water handling costs there is little work done at Kuparuk that pays as high a rate of return as the installation of a FPJP. A typical FPJP assembly costs less than $80 000 to install and net oil benefit (NOB) per installation can be hundreds of barrels of oil per day (BOPD). NOBs up to 700 BOPD have been seen in some Kuparuk wells by installing a FPJP. FPJP installations are very inexpensive compared to installing a surface powered jet pump (SPJP). FPJP installations avoid high costs associated with constructing surface facilities needed to deliver power fluid to hydraulically power a pump in a well. All that is needed to power a FPJP is a prolific high water cut producing zone that can be used to hydraulically power the pump. As of early 2007 there were 25 Kuparuk wells using FPJPs. The number of FPJP wells at Kuparuk has increased yearly since these pumps were first introduced in 1997 as a new AL technology (Fig.2). Most details of jet pump theory design and jet pump failure mechanisms are beyond the scope of this paper. These topics can be reviewed in other references.2 3 4 A FPJP must have sufficient capacity to handle the amount of fluid that a well can produce in order to operate efficiently. Some main considerations in FPJP design are the formation fluid inflow pressures and the flow rate that can be supplied from the prolific formation to the FPJP. Proprietary design programs and worksheets are used to model FPJP performance in wells. Post FPJP production data can be matched back to modeled expected results to verify the model. FPJP design considers three phase flow through the pump and future phase changes expected.CHEVRONSPE128337Well DeliverabilityArtificial LiftGas LiftA Simple Operational Approach To Ascertain the Viability of Your Offshore Gas Lift Project Before Fully Committing: The Meji Jacket X and Y Pilot CaseFrancis Nwaochei, SPE; Adebayo Olufemi, SPE; Vincent Eme, SPE; and John Ibrahim, SPE, Chevron Nigeria Limited; Eseoghene Nakpodia, SPE, and Wole Areo, SPE, Flostar Oil & Gas Nigeria LimitedAbstract Application of improved Oil Recovery in mature fields is almost inevitable. However the method applied in the IOR process is dependent on the economics and value of the method. In the Southern Offshore area of Chevron operations there are huge cost implications in the implementation of gas lift on several offshore jackets. New facilities for gas lift operation entails the installation of a compressor liquid knock out equipment pipelines manifold configuration and associated piping etc. In many cases gas lift sourcing might require completely fresh construction of entire facilities which will involve project development management costs infrastructure cost and space limitation especially in the case of offshore locations. In the Southern Offshore Area of Chevron operations several wells have quit and require some kind of support to flow to surface. Artificial lift (gas lift) has been identified as the best method to optimize production from the wells reviewed in this case. However the infrastructure required to implement the gas lift in the offshore location will come at a huge cost and there is a time factor as well to consider to install the infrastructure. Numerous gas lift opportunities have been identified in the Meji Field (offshore location) which currently has no gas supply. Wells in the shallow strong water drive reservoirs of this field flow naturally to terminal water cuts of between 60 to 70%. Based on the observed trend of terminal water cut the challenge for the team was to quantify the incremental oil gain if this terminal water cut is raised by introducing gas lift. If this proved to be substantial it will make a case for the expenditure on pipelines and associated infrastructure. In a bid to confirm that installing the gas lift infrastructure is a viable project a simple operational approach of installing a temporary piping system was implemented after the necessary engineering analyses which are all discussed in this paper. Other operational methods of confirming the viability of applying artificial lift technology (gas lift) on the jackets were also reviewed with a resolution to utilize the temporary solution. An estimated production gain of about 1105 BOPD from three wells through gas lift was identified in the field. The total production gain from the simple operation yielded 1540 BOPD.BPSPE115950Well DeliverabilityArtificial LiftGas WellArtificial Lift Selection Strategy for the Life of a Gas Well with some Liquid ProductionPeter O. Oyewole, SPE, BP, and James F. Lea, SPE, PL Tech LLCAbstract The Natural Gas industry is often faced with the challenge of selecting an optimal Artificial Lift method for a well in the midst of various artificial lift type choices. These challenges become more complex with increasing dynamic changes in well characteristics over the life of a well. This paper presents a case study on artificial lift selection strategy for unloading liquid from gas well in San Juan basin located in Southwestern Colorado and Northwestern New Mexico. Various modeling techniques were applied to evaluate the lowest bottom hole flowing pressure for various Artificial Lift system types and wellbore geometry. Real life data acquired at the field trials was used to validate model results. The selection strategy resulted in the creation of a robust artificial lift selection matrix and charts for various well configurations as well as production rates for optimum well performance. This approach has a significant impact on gas well production; often loaded up with liquid and prematurely abandoned due to lack of proper artificial lift strategy. The paper may assist the gas well operator and the need to adequately design install and operate an optimum artificial lift system for the life of the gas well. Introduction A gas well with high reservoir pressure and a high gas production rate carries liquid from bottom hole to the surface as a fine mist of droplets with the droplets traveling close to the speed of the gas. The liquid can be oil condensate and/or water. Any combination and percentage composition of these liquid types may be produced in association with gas. As reservoir pressure depletes production production rate falls - the gas flow velocity reduces and drops below a critical velocity required for gas to move liquid droplets up to the surface (References [1] [2] [7]&[8]). Liquid then begins to accumulate at bottom hole and near the well bore region. The gas well loses its capability to lift liquid from bottomhole to the surface. This phenomenon is known as Liquid Loading. The accumulated liquid increases bottom hole flowing pressure due to an increase in liquid holdup in the tubing and a height of liquid build-up in the wellbore. The relative permeability of gas and gas mobility in the near well bore region may also be impaired as a result of increased water saturation. Thus it acts like skin damage to the reservoir known as Liquid Block. If no intervention work is performed to remove liquid from the sandface and the well will eventually cease will flow at a lower rate and many eventually cease to produce due to loading There are many artificial lift techniques available to be used to attempt to continously remove liquids from a liquid loaded gas well. See Table 1 and Table 2 below which is a basic chart of current artificial lift and unloading methods for gas well. This table could also include velocity strings intermitting the well and other novelity pumps but the basic methods of artificial lift for dewatering gas wells are included. Several articles papers and textbooks (See References [1] to [21]) do provide detailed information on various methods of unloading a gas well. In general these methods is categorize into two main groups. These groups are based on source energy used to provide the required lift. The two groups are the Reservoir Supplied Energy Systems and the External Supplied Energy Systems. 1.) The Reservoir Supplied Energy Systems include methods such as: Well Cycling On and Off (Timer/Stop clocking) Venting and Pit Blow-downs (environmentally unacceptable option) Surfactant (Foamer) Velocity String Well Swabing PlungerCONOCOSPE117489Well DeliverabilityArtificial LiftSAGDSAGD Gas Lift Completions and Optimization: A Field Case Study at SurmontT.C. Handfield, T. Nations, S.G. Noonan; ConocoPhillipsAbstract Gas lift completions for SAGD1 producers are unique. Conventional gas lift valves and mandrels with a packer completion cannot be used due to the extreme temperatures of the downhole environment. Most lift gas enters the production stream downhole via open-ended tubing or nozzles which if not properly sized can result in operational issues such as fluid / gas slugging and pressure instabilities which negatively impact the overall lift efficiency. In 2006 ConocoPhillips conducted a study to design a gas lift system for the Surmont SAGD development that would allow better control of lift gas into the production string and in late 2007 the wells completed with gas lift were placed on production. This paper will cover the data collection effort and analysis completed to determine the efficiency of the two types of gas lift nozzles used in the completions the methodology for optimization of SAGD gas lift systems and recommendations for future improvement. Background Surmont an in-situ oil sands project is located approximately 60 kilometers southeast of Fort McMurray in the Athabasca oil sands (Figure 1). This multiphase SAGD project is a 50/50 joint venture between ConocoPhillips Canada Ltd. (CPC) and TOTAL E&P Canada Ltd. with CPC as the operator. The Surmont pilot began injection of steam in 1997. The pilot is comprised of three SAGD well pairs that utilize a variety of artificial lift methods. These wells have been tested to determine the preferred method of artificial lift for the first commercial phase. Steam injection for Phase 1A of the commercial development was initiated in mid-2007 and conversion to full SAGD production followed in late-2007. Phase 1A is comprised of 20 well pairs in which all the producers have been completed to produce via gas lift for the initial life of the well. Phase 1(A B & C) has a capacity of 25 000 barrels per day (bpd) (3 975 m3/d) and is expected to reach peak production in 2012. A second phase is slated for commercial start-up before the middle of the next decade which upon completion and full ramp-up is estimated to bring peak production from both phases to 100 000 bpd (15 899 m3/d). Additional phases at Surmont are also under study.SCHLUMBERGERSPE110103Well DeliverabilityArtificial LiftSAGD ESPPushing the Boundaries of Artificial Lift Applications: SAGD ESP Installations at Suncor Energy, CanadaF. Gaviria, SPE, SUNCOR, and R. Santos, SPE, O. Rivas, SPE, and Y. Luy, SPE, SchlumbergerAbstract The need for high-temperature electric submersible pump (ESP) systems is growing as the oil industry matures. Canada's nonconventional oil reserves are estimated at just over 1 trillion barrels and Suncor's heavy oil reserves in northern Alberta Canada are estimated to have a potential production of 14 billion barrels of crude oil but traditional mining methods of recovery do not make them all economically reachable. It is estimated that less than one-fifth of the oil sands resource is mineable. To deal with this Suncor has turned to in-situ steam-assisted gravity drainage (SAGD) operations as a key part of its plans to increase bitumen supply to its upgraders. The SAGD approach uses a pair of horizontal wells drilled parallel to each other and separated vertically by a distance of approximately 5 m. Steam injected through the uppermost well penetrates the surrounding formation heats the heavy-oil sands and creates a high-temperature region above the injector known as the steam chamber. Heat transferred to the oil sands reduces oil and bitumen viscosity. Gravity forces the oil bitumen and condensed steam downward where these fluids consisting of about 2580% water are produced into the lower well. Suncor uses SAGD technology to recover 8 to 9 degree API bitumen and heavy oil from unconsolidated sands in the Firebag field. Wells in these fields experience bottomhole pressures of 2000 to 3000 kPa and bottomhole producing temperatures of 180C to 209C. Whereas standard ESP strings are rated to 149 C bottomhole operating conditions (BOC) key components of the SAGD system featured in this paper especially its motor power cables pump and advanced protector are built to withstand bottomhole temperatures up to 218 C. Suncor has installed 21 of these ESP systems which have enabled a reduction in downhole pressures to improve the steam/oil ratio (SOR). This is a direct reduction in operating and lifting costs which provides several million dollars in savings by reducing the amount of water that needs to be treated and the amount of fuel burned to generate the steam. Suncor's line of ESP systems has achieved a runlife of more than 500 days. World Oil Reserves and Demand There are several sources of information that continually evaluate and discuss world oil reserves. The numbers may differ slightly from source to source but almost all of them agree on a similar distribution of fossil fuel reserves as shown in Figs. 1 and 2. According to this the world has twice as much heavy oil and bitumen than conventional oil. It is estimated than there are approximately 8 to 9 trillion barrels of heavy oil and bitumen in place worldwide of which potentially 900 billion barrels of oil are commercially exploitable with todays technology. As for oil demand the International Energy Agency (IEA) projects that global primary energy demand will increase by 1.7 to 2% per year from 2000 to 2030 which is equivalent to two-thirds of the current demand. On the other hand the supply from relatively cheap conventional sources is declining and reserves are not being replaced with new discoveries. A conservative 3% of natural decline in production from existing reserves is estimated. While non-conventional oil is emerging as a new major source of oil even an aggressive worldwide development scenario can only capture 10 to 15% of the required new oil supply in the next 20 years. In addition nonconventional oil by itself cannot make up for the decline in the world conventional oil production (Isaacs 2006).OnePetroSCHLUMBERGERSPE106094Well DeliverabilityArtificial LiftStaircase LiftingStaircase Lifting of Oil Using Venturi Principle: A New Artificial-Lift TechniqueSiddhartha Gupta, SchlumbergerAbstract Artificial lift systems are now being considered of extreme importance as the reserves across the globe are depleting and the wells are unable to flow naturally. Over the years a number of artificial lift techniques have evolved as a result of extensive research and ground work. All the systems have proven their worth by increasing the productivity of the field by many folds. But each of these artificial lift systems has economic and operating limitations that eliminate it from consideration under certain operating condition. However all the conventional artificial lift systems have a common feature. The energy added to the lift the fluid from the wellbore is lost in the process and cannot be utilized for some other operation. This paper describes a new technique of artificial lift which uses the concept of venturi to lift the fluid to the surface. A high velocity power fluid is used to create drawdown at the throat of a surface venturi and this pressure drawdown is transmitted downhole by pressure tappings. The drawdown lifts the fluid through the production tubular in a stepwise manner. The power fluid coming out from the other end of the venturi is used to drive a turbine which generates power as a result. This power is used to operate the inlet compressor thus the cycle being completed. After startup effectively no energy is used up to keep operating the system. The system is of immense economic benefit as the operating expenditures are low. Also this system uses zero-cost air as power fluid. It is a space efficient package which can be used on offshore locations as well. The paper describes the individual components of the system and the calculations involved therein. The economic and technical comparison of this system with the conventional methods is also enlisted. Introduction The venturi consist of a converging tube which is an efficient device in converting pressure head to velocity head and a diverging tube converts velocity head to pressure head. The two are combined to form a Venturi tube. As shown in fig 1 it consist of a tube with a constricted throat that produces an increasing velocity accompanied with reduction in pressure followed by a gradual diverging portion in which the velocity is transformed back into the pressure with slight friction loss. If tapping are taken from the inlet and throat of the venturi tube and this pressure differential is applied to an entrapped fluid column then the fluid column will rise in the conduit under the application of the pressure differential. After a certain amount of rise the column is again trapped and the differential is now transferred across it. This causes further rise. The process continues until the fluid column reaches the surface. Meanwhile the high pressure and appreciable velocity air leaving the venturi tube drives an Air generator which produces power. This power is used to operate the inlet air compressor. Thus the cycle is completed. Thus this system achieves which no other existing artificial lift system does. Recirculates power to run itself. Equipment Description The major components of this lifting system are: Inlet Air Compressor Surface Venturi Downhole Tubular and Valves Air Turbine Inlet Air Compressor As shown in the subsequent calculations the primary concern here is the flowrate and not the pressure. Nominal pressures are required but very high flowrate are necessary for the working of the system. As such only Centrifugal Compressors suffice the purpose. Surface Venturi As shown in fig 2 it is a metallic structure of the geometry as shown. It has a converging section throat and a diverging section. The metal thickness should be adequate enough to bear the thermal and mechanical stresses induced because of the flow. Also it should be corrosion and erosion resistant so as to be able to bear the high velocity air passing through it. The converging and diverging angle are to be fixed to optimize the stresses developed. Ideally the converging section has an angle of 20 and diverging section has an angle of 5. Two pressure tappings are taken from the venturi that is relayed downhole.Heriot Watt UniversitySPE122231Well DeliverabilityClean-upIntelligent WellsEfficient Intelligent Well Cleanup using Downhole MonitoringD.K. Olowoleru, K.M. Muradov, F.T. Al-Khelaiwi and D.R. Davies; SPE, Heriot-Watt University, Edinburgh, U.K.Abstract Effective well cleanup during well start-up ensures efficient formation damage removal and maximises the resulting well production potential. Horizontal wells are more susceptible than vertical wells to formation damage due to the longer completion length the longer drilling time the potentially increased overbalance and the reduced cleanup efficiency caused by the heal-toe effect. Extensive modelling and simulation work has been previously performed analysing the impact of formation damage and well cleanup in horizontal wells. This paper extends that work to advanced completions employing Interval Control Valves (ICVs) and Inflow Control Devices (ICDs). It reports a comparative study that illustrates the greater cleanup efficiency of advanced long horizontal well completions over that achieved by the equivalent conventional openhole completion. The highest cleanup efficiency is predicted to be achieved by an intelligent completion employing both sensors and ICVs. The wells full production potential will only be realised if a proper real-time cleanup monitoring and control procedure is implemented to optimise the choking strategy. Only then will the near wellbore cleanup efficiency be maximised. A dynamic well simulator has been used to illustrate the advantages of employing such a proper real-time cleanup monitoring and choke control strategy. This only becomes possible if an intelligent completion is employed. Sensitivity analysis is used to illustrate how an ICV completion gave the highest cleanup efficiency for almost all the parameters studied. The single zone cleanup strategy employed by an intelligent completion requires that extra time be spent on the initial stages of the cleanup process. Guidelines are required to ensure economic as well as technical optimisation of the cleanup process. This can be achieved by use of the presented practical downhole monitoring procedures for efficient well cleanup together with a novel procedure for identifying the time when the near wellbore region is sufficiently clean. 1.0 Introduction Formation damage is one of the major factors controlling actual well productivity1. This is especially true for long horizontal wells that have been drilled and completed overbalance with water-based fluids2 3. Perforating may bypass the contaminated zone but is itself susceptible to damage. It has been long recognised that well cleanup complications increase with increasing well length and number of completion zones. Cleanup management has been recognised as essential for successfully bringing the well on production with the highest possible production potential. Recent publications4 5 provided a qualitative discussion on cleanup as part of a comparative framework for the evaluation of the strengths and weaknesses of advanced and conventional completions. This paper sets out to quantify the advantages of advanced completions to improve cleanup by use of their permanently installed downhole flow control equipment and measurement sensors. Intelligent wells add additional value by providing more effective cleanup than conventional ones. Subdividing the total producing length into a number of zones which are opened successively during the well start-up period is a field proven practice that maximises the drawdown to a particular zone and minimises the chance of flow conduit blockage by deposition of produced sand. The increased drawdown created by unloading the separate well zones sequentially leads to more effective formation cleaning. This temporary zonation of the wellbore can be achieved with specially pre-installed devices (e.g. clean-out or sandface valves). Real-time downhole pressure data can be used to ensure that the flowing bottomhole pressure is kept above the sand production limit6. Intelligent wells break the completion into a number of zones with downhole valves while their multiple gauges can be used to control and monitor the zonal production. They also have the additional capability of optimizing the cleanup operation. This paper will first discuss the processes that cause formation damage in the near wellbore area due to drilling and completion fluids. We will then compare the conventional wells success in cleaning up this damage with that of an advanced well completed with either Interval Control Valves (ICVs) or Inflow Control Devices (ICDs). Finally we will develop recommendations for improved cleaning techniques.Heriot Watt UniversityIPTC12145Well DeliverabilityCompex WellsDownhole control ValvesAdvanced Wells: A Comprehensive Approach to the Selection Between Passive and Active Inflow Control CompletionsF.T. Al-Khelaiwi, SPE, and V.M. Birchenko, SPE, Heriot-Watt University; M.R. Konopczynski, SPE, WellDynamics; and D.R. Davies, SPE, Heriot-Watt UniversityAbstract Advances (from conventional wells to horizontal and then multi-lateral) in well architecture for maximising reservoir contact have been paralleled by advances in completion equipment development of both Passive" Inflow Control Devices (ICDs) and "Active" Interval Control Valves (ICVs). These devices provide a range of fluid-flow control-options that can enhance the reservoir sweep efficiency and increase reserves. ICVs were initially employed for controlled commingled production from multiple reservoirs; while ICDs were developed to counteract the "Heel-Toe" Effect. The variety of their reservoir applications has since proliferated so that their application areas now overlap. It has become both complex and time consuming to select between ICVs or ICDs for a wells completion. This publication along with a companion paper summarises the results of a comprehensive comparison study of the functionality and applicability of the two technologies. It maps out a workflow of the selection process based on the thorough analysis of the ICD and ICV advantages in major reservoir production operation and economic areas. Detailed analysis of the modelling gas and oil field applications equipment costs and installation risks long term reliability and technical performance are covered. The systematic approach and tabulated results of this comparison forms the basis of a screening tool of the potential applicable control technology for a wide range of situations. The selection framework can be applied by both production technologists and reservoir engineers when choosing between Passive or Active flow control in advanced wells. The value of these guidelines is illustrated by their application to synthetic and real field case studies. Introduction Increasing well-reservoir contact has a number of potential advantages in terms of well productivity drainage area sweep efficiency and delayed water or gas breakthrough. However such long possibly multilateral Extreme Reservoir Contact (ERC) wells bring not only advantages by replacing several conventional wells; but also present new challenges in terms of drilling and completion due to the increasing length and complexity of the wells exposure to the reservoir [1]. The situation with respect to reservoir management is less black and white. An ERC well improves the sweep efficiency and delays water or gas breakthrough by reducing the localized drawdown and distributing fluid flux over a greater wellbore length; but it will also present difficulties when reservoir drainage control is required. Production from a conventional well is normally controlled at the surface by the wellhead choke; increasing the total oil production by reducing the production rate of a high water cut conventional well afflicted by water coning. Such simple measures do not work with an ERC well since maximization of well-reservoir contact does not by itself guarantee uniform reservoir drainage. Premature breakthrough of water or gas occurs due to: Reservoir permeability heterogeneity. Variations in the distance between the wellbore and fluid contacts e.g. due to multiple fluid contacts an inclined wellbore a tilted oil-water contact etc. Variations in reservoir pressure in different regions of the reservoir penetrated by the wellbore. The heel-toe effect that leads to a difference in the specific influx rate between the heel and the toe of the well especially when the reservoir is homogeneous."OnePetroCONOCOSPE114011Well DeliverabilityCompletion OptimisationBig Bore DesignRevised Big Bore Well Design Recovers Original Bayu-Undan Production TargetsL. B. Ledlow, W. W. Gilbert, N. P. Omsberg, G. J. Mencer and D. P. Jamieson, ConocoPhillipsAbstract The Bayu-Undan gas recycling project is located north of Australia in the East Timor Sea and is designed to produce 1 100 MMscf/D of wet gas strip out 110 000 B/D of condensate/LPG initially reinject 950 MMscf/D of lean gas and later export up to 700 MMscf/D of lean gas to a LNG plant in Darwin. The initial development called for 16 North Sea-style 7 in. monobore wells (11 producers and 5 gas injectors). By May of 2003 it became apparent that the original well design would not achieve the 1.1 Bcf/D production target because of well construction problems. Three wells on the remotely located wellhead platform were abandoned because of wellbore instability. Without the production contribution from these wells the first years production target would not be met. To meet the production targets a complete well redesign was undertaken. First the tubing was upsized from 7 in. to 9-5/8 in. Then semi-openhole completions with pre-drilled liners and openhole packers were selected instead of the conventional cased and perforated design to reduce installation time. Finally oil based drill-in fluid was selected to provide lubricity temperature stability and low liftoff pressure of the filter cake for rapid cleanup. Utilizing the Big Bore design the production capacity of +1.1 Bcf/D and injection capacity of 1.1 Bcf/D was achieved in June of 2004 ahead of schedule. The well count was also reduced from 16 to 12 wells (8 producers and 4 gas injectors.) Two producers had capacities in excess of 300 MMscf/D and three gas injectors had injection capacities in excess of 350 MMscf/D. The increased production resulted in 19 MMstb of condensate/LPGs produced in the first year some 7-8 MMstb more than would otherwise have been the case. Introduction The Bayu-Undan Field is a retrograde gas-condensate field with a raw Gas-Initially-In-Place (GIIP) of 8-9 Tcf including 700 MMstb propane plus (C3+). The field is located in the Timor Sea and straddles the Joint Petroleum Development Area JPDA. The Production Sharing Contracts PSCs 03-12 and 03-13 in the Timor Gap area are administered jointly by the countries of East Timor and Australia as seen in Figure 1. The Bayu-Undan gas recycling project was originally planned to be developed from two platforms with eight - 7 in. monobore wells and eight 7-5/8 in. monobore wells consisting of 11 producers and five gas injectors. The planned well depths ranged from 4000 m (11 972 ft) to 6341 m (20 798 ft). This design would require well rates up to 220 MMscf/D to meet the design premise of producing 1100 MMscf/D while re-injecting 950 MMscf/D of lean gas by July 2004. By 2006 when the LNG plant and pipeline were available 475 MMscf/D would be transported to the LNG plant in Darwin and the remaining 475 MMscf/D of lean gas reinjected into the formation.1 The Bayu-Undan formation structure is a broad east-west trending horst with a number of culminations set up by internal eastwest and north-south trending faults as seen in Figure 2. The predominant hydrocarbon-bearing section of the Bayu-Undan Field occurs in the upper part of the Early to Middle Jurassic Plover Formation and throughout the Later Jurassic Elang Formation. In addition a thin interval belonging to the Frigate and the Flamingo Formations forms a minor part of the pay zone along the margins of the field. One distinct feature is a common gas-water-contact (GWC) interpreted across the field at 3109 mSS TVD (10 198 ft). Figure 3 presents a generalized stratigraphic column and reservoir characterization for Bayu-Undan.TOTALSPE102550Well DeliverabilityCompletion OptimisationBig Bore DesignBig Bore Completion and Sand Control for High Rate Gas WellsAlain BOURGEOIS, Sebastien BOURGOIN, and Pierre PUYO, TOTAL AUSTRALAbstract This paper outlines and discusses the issues surrounding the TOTAL AUSTRAL Carina and Aries field development project and the engineering issues addressed to facilitate achieving the project goals of producing gas at high rates from the shallow unconsolidated sand stone reservoirs. The main challenge in terms of completion architecture was to maximize the well head flowing pressure while insuring long term integrity of wells. This was addressed through implementation of limited - or even not - proven technologies. Introduction TOTAL AUSTRAL operates the Carina and Aries fields located in offshore Tierra del Fuego in the most southern region of Argentina (Figure 1). These fields are prolific gas fields and are being developed with a reduced number of wells with departures of up to 4 Km @ 1500 m TVD/RKB. The drilling scenario for Carina/Aries phase 1 included two horizontal wells to be drilled from the platform CARINA-1 (85 m water depth) and two horizontal wells from the platform ARIES (65 m water depth) for a targeted production plateau of 12 MSm3/d of gas with 3 to 4 MSm3/d by well at relatively low pressure (80 bars WHFP). Maximizing the Wellhead Pressure The surface project includes the two platforms respectively located at 80 Km and 30 Km from shore one 24 main multi-phase sea line from CARINA-1 to Rio-Cullen production facility and one secondary 18 line from ARIES jacket to the main pipe. The production scheme does not include offshore compression (Figure 2). In this context limiting pressure drop from the sandy reservoirs up to the wellhead was paramount. Productivity oriented sand control technique and a 95/8 production tubing was then selected to maximize and ensure sustained wellhead pressure while minimizing the CAPEX. Flow Insurance Well longevity was another key word for the following reasons: Limited number of wells. Huge cost of work-over linked with rig and service equipment availability/mobilization because of extreme remoteness of the location (rig not scheduled in the area before five years after the end of current Total Austral drilling campaign). A Challenging Context Developmental problems to fulfill the above well requirements included: No or few case history for 95/8 completion and high velocity gas well horizontal sand control. The Extended Reach Departure nature of wells (Figure 3). A tight schedule between the drilling go ahead and the request for first gas delivery (18 months). A harsh environment location remote from any offshore oilfield over a days sailing time to reach the operational base (Punta Quilla) in a tax free area with associated administrative issues making logistics critical (Figure 4). Build/Re-build a learning curve (last Tierra del Fuego offshore campaign in 1997) with limited number of wells. Minimizing Technical Risk This was done through several actions: Purchase best in class products. Perform detailed and extensive Factory Acceptance Tests (FAT). Setup a workshop in the operational base including a mobile test bunker and bucking machine to re-test all the critical assemblies before sending offshore.CHEVRONSPE89753Well DeliverabilityCompletion OptimisationGas CondensateExploring Reservoir Engineering Aspects of Completion in Gas/Condensate Reservoirs: West African ExamplesC.S. Kabir, SPE, Chevron Energy Technology Co.; M.-M. Chang, SPE, Chevron Intl. E&P; and O. Taghizadeh, SPE, U. of Texas at AustinSummary This paper explores multiple completion options in gas/condensate reservoirs with compositional simulations. Besides intelligent-well completion (IWC) options included commingling two reservoirs of contrasting conductivity (permeability-thickness product) and selectively perforating zones or reservoirs to offset the permeability contrast. At the outset a value-of-information exercise suggested probing downhole sensing and completion issues in a stacked-reservoir situation. The ultimate objective of this study was to ascertain economic completion strategy so that depletion of reservoirs occurs evenly at the projects termination. Single-well compositional simulations formed the backbone for our evaluation of three completion options. Each reservoir was characterized by history matching drillstem tests (DSTs). Experimental design (ED) reduced the large number of simulation runs to a manageable few for probabilistic forecasting. Comparison of three options suggested that all of them nearly produced the desired results of maximum liquid recovery despite a 10-fold difference in permeability between the two horizons. Results further showed that condensate banking was a nonissue in this high-kh system of reservoirs as far as the gas deliverability is concerned. In other words although 40 to 60% degradation in the gas productivity index (PI) occurred gas deliverability remained intact. In contrast both the liquid PI and rate declined with time owing to phase-behavior and relative permeability issues. Finally we learned that the net income generated by IWC is no better than the specific-perforation completion (SPC). Introduction IWC is primarily about proactive on-time intervention through monitoring and control of flow in and out of the well. Economic imperatives particularly in deepwater settings have generated intense interest in IWC technology. Of course the ability to commingle marginal reservoirs in any situation is another attractive application of IWC. To underscore IWCs importance various papers have appeared in the literature describing instrumentation and control (Robinson and Mathieson 1998; Rundgren et al. 2001; Tourillon et al. 2001) reservoir modeling (Ostvik et al. 2001; Borch 2001; Yu et al. 2000; Akram et al. 2001; Nielsen et al. 2001; Jalali 1998) and field implementations (Lau et al. 2001; Erlandsen 2000; Glandt 2003). Most papers describe the well-centric benefits of IWC in horizontal and/or multilateral wells in complex lithologies with the exception of Jalali (1998) and Glandt (2003). In fact Glandt provides a comprehensive review of this technology particularly from the viewpoint of reservoir engineering. The use of probabilistic analysis (van der Poela and Jansen 2004) to assess the value of IWC in a complex reservoir scenario was also explored for oil wells. This body of work demonstrates the promise of IWC because the technology is in growth mode with 5 or so years of collective industry experience. The main motivation of this study stemmed from understanding the local regulatory bodys completion philosophy. Derived primarily from the oilwell analog the current regulation prevents layer commingling when production occurs from different geologic horizons. This regulation does not preclude commingling layers of contrasting properties separated by shales so long as they are within the same geologic unit. Therefore our incentive was to learn how one should approach the completion issue within a single geologic unit and in multiple geologic units. In this study we probe the benefits of IWC or its analog in a depletion-drive system where primary production dominates. Three completion scenarios were considered: (1) commingling with downhole control (2) commingling without downhole control by selective interval perforating and (3) conventional commingled completion. Our objective was to eliminate reservoir crossflow without differential depletion among the reservoirs in the first two completion options.BPSPE106854Well DeliverabilityCompletion OptimisationHigh Rate Gas WellsA Critical Review of Completion Techniques for High-Rate Gas Wells Offshore TrinidadS.D. Cooper, S. Akong, K.D. Krieger, A.J. Twynam, F. Waters, and R. Morrison, BP; G. Hurst, Consultant; and B. Lanclos and M. Parlar, SchlumbergerAbstract BP Trinidad and Tobago (bpTT) has been developing highrate gas fields in Trinidad & Tobago since 1999 and has six high rate gas fields currently on production with several more in planning stages. All of the wells require sand control and this has resulted in five sandface completion types (Open Hole Gravel Pack Cased Hole Frac Pack Cased Hole Gravel Pack Stand Alone Screen and Orientated Perforating). Based on the experience and field performance open-hole gravel packing has become the preferred option. The techniques used in completing these high rate gas wells as open-hole gravel packs have included both water-packs and shunt-packs. The experiences gained from these operations have now become part of BPs open-hole gravel pack best practices. The paper details the completion evolution in BPs offshore Trinidad and Tobago high rate gas fields and the relative performance of these completion types from sand control and well productivity standpoints. Characteristics of bp Trinidad & Tobagos High-Rate Gas Fields Currently there are six high rate gas fields that are being operated by bpTT in Trinidad & Tobago: Amherstia Flamboyant Immortelle Kapok Mahogany and Cannonball. There are three other fields in the planning phase. The six producing gas fields contain multiple stacked and faultsegmented reservoirs with recoverable reserves ranging from 80 bcf to 1.5 tcf.1 Detailed discussions of the reservoir characteristics for most of these fields can be found in several earlier publications.2 3 The reservoirs in these fields are generally characterized as fine sand with D50 varying from 50 to 125 microns uniformity coefficient (D40/D90) of 4.5 to 15 sorting coefficient (D10/D95) of 23 to 95 and fines content (D < 44 microns) of 14 to 47%. From a sand size distribution standpoint based on available guidelines in the literature gravel packing and frac packing are the preferred sand control techniques.4 5 As of mid 2006 approximately 50 high-rate gas wells were completed in these six fields with 10 cased and perforated (no sand control) 2 standalone screens 8 casedhole frac-packs 9 cased-hole gravel packs and 23 open-hole gravel packs. These completions are reviewed below with some examples for each in detail. Additional relevant information to BP Trinidad & Tobago field developments maybe found in the literature.6-14 Cased and Perforated (C&P) Completions This technique was applied in deeper reservoirs with relatively high strength UCS in the range of 1 600 to 2 000 psi. A total of ten C&P completions were performed in high rate gas wells four in Amherstia four in Flamboyant and two in Immortelle fields. C&P-1 Well: This well was completed in June 2002 targeting 23U/L & 24U-sands in Amherstia at a measured depth of 12 290-13 566-ft (9 834-10 292-ft TVD) with 9-5/8-inch casing set at 14 350-ft. The reservoir section was drilled with a water-based fluid. Sand prediction models from the operator and the service company teams had independently confirmed that this well was a good candidate for a cased and perforated completion with oriented perforating. Tubing conveyed perforating (TCP) assembly consisted of a gross length of 1 301-ft with a net perforation length of 460-ft 4-spf and 180o phased 4-1/2-in guns and a packer. The guns were run with weighted spacers and swivels to orient the guns to perforate on the high and low sides of the casing. The upper completion string consisted of a production seal assembly (stung inside the packer) 7-in tubing string downhole pressure gauge and a subsurface safety valve. Four intervals varying from 60 to 240-ft were perforated with ~800 psi underbalance with a total perforated interval length of 460-ft across the 1 276-ft interval with 76o inclination. The initial reservoir pressure was 4 260-psi with a bottomhole static temperature of 177oF.SCHLUMBERGERSPE102544Well DeliverabilityCompletion OptimisationHorizontal WellsSelection of an Adequate Completion Type is the Key to Successful Reserves Recovery. Case History of Horizontal Drilling in the Reservoirs With Different Depositional Settings (by the Example of the Sporyshevskoye Oil Field)Sergey Ryzhov, SPE, Vladimir Malyshev, SPE, Shlumberger, and Tatyana Kruchkova, SPE, Anna Zubareva, Andrey Vasiliev, Yulia Maslennikova, Sergey Selemenev and Marina Kolesova, Gazprom neftAbstract The Sporyshevskoye oil field development started in 1995. In 2002 by the time when all the designed vertical wells had been drilled practically all the reserves of the main reservoirs within the production targets were put into production. There emerged a necessity to develop the oil-water zones and marginal areas zones with poor reservoir properties and minor reservoirs in order to maintain the production rates. Application of horizontal drilling allowed achievement of the above tasks. Horizontal completions resulted in not only enhancement of individual well production rates but also significantly improved the oil recovery. This goal was achieved through optimization of the development system and improved development of oil-water zone reserves and the reserves contained in the zones with poor reservoir properties. The use of the horizontal completion allows development of the reserves which would have never been possible to produce with vertical wells because of poor economics. Another crucial achievement resulting from horizontal completions was the more efficient use of existing wells. Poor vertical producers were sidetracked; the vertical wells released due to drilling of horizontal boreholes were recompleted; the number of shut-in wells reduced. Introduction Use of the vertical wells is a traditional and well-known method of hydrocarbon field development. However application of horizontal completions can significantly enhance the efficiency of the hydrocarbon recovery. Horizontal drilling is particularly attractive when it comes to produce reserves from oil-water zones and marginal zones that are nor economic when drilled out by vertical wells. Horizontal well drilling brings about the improved productivity and therefore enhanced recovery for low-permeability reservoirs. Horizontal completion in the oil-water zones reduces the rate of watering out and leads to longer economic life of the wells. By and large drilling of horizontal wells as an element of the field development system ensures increase of recoverable reserves enhances production of marginal reserves and improves economics of the hydrocarbon reservoirs which cannot be developed at a profit by vertical completions. Today the use of horizontal completion is widely spread in the Sibneft fields. The Sporyshevskoye oil field has been one where horizontal wells are in massive use and have been recognized as a key enhanced recovery method in the field. Specifics of the geology and development history of the Sporyshevskoye field The Sporyshevskoye field is a multiple reservoir field comprising 26 stacked pays which belong to Cretaceous and Jurassic systems (groups of PK AS BS and JS reservoirs). It contains more than 50 distinct oil pools. The reservoirs consist of terrigenous rocks of continental and shallow-water marine origin. The productive reservoirs formed in different facial settings. Genetically three types of sediments can be recognized including highly permeable sandstones deltaic distributary channels that incise the flood valley; massive thick mouth bar sandstones and sheet-type shore terraces reservoirs. The PK group of reservoirs deposited in the deltaic coastal setting. AS reservoirs are associated with the delta tributaries and crevasse splays while the BS reservoirs consist of coastal-deltaic sediments and crevasse splay sandstones. JS11 reservoir is represented all over the entire area by thin marine sands intercalated with shoreface top carbonate streaks. Most part of the field reserves (over 60%) is associated with oil-water zones. Productive reservoirs show mostly good lateral continuity and are underlain by vast aquifers.SCHLUMBERGERIPTC12364Well DeliverabilityCompletion OptimisationManati Gas FiledThe Challenges and Advantages of Openhole Completions in the Manati Gas FieldA. Calderon, SPE, A.F. Arago, SPE, and C.M. Chagas, SPE, PETROBRAS, and C. Guimares, SPE, and R. Barbedo, SPE, SchlumbergerAbstract The offshore northeast Brazil Manati field is located in the Camamu Bay with water depths less than 50 m. The sandstone gas reservoirs in this field have net pays with a thickness greater than 300 m and an average true vertical depth (TVD) of 1 400 m. The original development project for this field did not include sand control for the initially forecasted production rates. However the possibility of expanding the gas production rates of each well to more than 1 MMm3/D increased the associated sand production risk and led to the need for evaluating the best sand-control solution while considering the cost/benefit ratio. This paper explains why an openhole gravel-pack completion was the best option in spite of some challenges such as large vertical net pays and high hydrostatic pressures of the sodium formate-based reservoir drill-in fluid and the sodium-potassium formate completion brine. Compared with other alternatives such as cased hole gravel-pack or frac-pack completions the openhole gravel-pack option has several advantages such as eliminating the need to run a liner which requires good cementing isolation at the top; eliminating the cost of perforating long intervals; reducing the number of operations; and saving more than 10 days of rig time. Introduction The Manati field is located in the southern portion of the Bahia state and approximately 10 km offshore where water depth varies from 35 to 50 m.. This area is extremely environmental sensitive (Fig. 1) The field was discovered in 2000 through a prospect based on the seismic interpretation The reservoir is constituted by the tabular fluvial sands of the Sergi Formation caped by the shales of Itape Formation and sealed laterally at north and east by the shales of Morro do Barro Formation which were deposited in the space created by the erosive unconformity of the Tinhar Canyon of Rio da Serra age. At east and south the Mut fault (north-south) and yet another northeast-southwest fault seal the accumulation through the contact with the same shales of Morro do Barro Formation (Filho 2005). During the drilling of a pilot well a 187-m free-gas reservoir was initially identified. Perforating other exploratory wells showed a gas/water contact at 1 570 m vertical depth and net pay from 230 to 370 m in a reservoir with very good petrophysics proprieties. The evaluation of those data increased the initial reserves forecast for the Manati field making it the largest gas reservoir in the north-northeast Brazilian region.Heriot Watt UniversitySPE108173Well DeliverabilityCompletion OptimisationMarginal WellsMultiple-Zone Completion in Marginal Production WellsGuillermo Pitrelli and Maximiliano Giraldo, Repsol-YPFAbstract Concepts on well multiple zone completion systems applied in marginal wells in Los Perales Oil Field located in the Gulf of San Jorge Basin Santa Cruz province Argentina. The field is fully operated by Repsol-YPF. The paper narrates the challenge and experience of completing three marginal production wells (LP-2384 LP-2354 and Hue.xp-10) using concepts on well zone isolation flow control capability production management and easy well access in future workovers. The field is characterized by a stratified reservoir which is created by changes in depositional condition therefore each layer has different rock properties and flow characteristics (fluvial type reservoir). Gas oil and water are being produced commingle from different layers. The traditional method used to avoid production of a specific layer was cementing the layer or leaving it below a drillable plug (type N-plug). Despite difficulties three wells were completed based on these concepts: LP-2354: Selective zone completions allowing reservoir and production management of three different gas sand beds. LP-2384: Selective isolation of gas and water sand layers. Oil zone was put into production allowing for ultimate gas recovery using pulling rig and a wireline unit instead of a workover recompletion. Hue.xp-10: Gas ultimate recovery increased with a rig less workover completion. Killing the well thus damaging the formation was avoided. Each well completion and intervention was designed based on a cost effective and fit for purpose criteria. Different arrays of tools (straddle retrievable packers side pockets mandrels mandrel valves and tubing screens) were run into the wells. The main enhancements were the following: Cost-effective rig less workover. Higher artificial lift performance by avoiding commingled flow using multiple zone isolation (no gas pound on the pump no unwanted producing fluids). Cross flow and formation damage prevention due to commingled production. Easy well access to increase gas ultimate recovery using a pulling rig instead of a workover recompletion. Recompletion of gas wells by means of wireline conveyed casing guns and wireline setting packers without killing the well in order to pull down tubing string and therefore preventing formation damage. Introduction This paper presents the experience of completing three marginal well in Los Perales Oil Field. In 1936 the well was drilled. Los Perales is being operated at 100% by Repsol-YPF and is located in the western section of the Gulf of San Jorge basin in Argentina (figure 1). Actual Los Perales oil production is 4100 m3/d and gas production is 1.9 Mm3/d. Los Perales is considered to be a marginal field because average well oil production is 2.5 m3/d (14 STB/d) this fact makes cost effective solutions a paramount in Los Perales field. Geologically Los Perales is characterized as a multilayer fluvial type reservoir. Average sand beds thickness is 3 m and they can produce water oil gas or all of them together. A typical well completion is perforating every layer that is considered by logs interpretation and then swabbing each of them. Upon the results of the swabbing engineers and geologists decide which layer will be put in production cementing or isolating the ones that are out of interest. Finally a rod sucker pump is run in hole and the well starts producing with a commingle flow of oil gas and water.OnePetroOnePetroSCHLUMBERGERSPE112476Well DeliverabilityCompletion OptimisationMultilayered ReservoirsMultiple-Layer Completions for Efficient Treatment of Multilayer ReservoirsGary Rytlewski, SchlumbergerAbstract A new method of completing multiple-layer formations has been successfully tested in the United States and Canada. This new method places sliding sleeve valves in the casing string and completes the well with normal cementing operations. The sliding sleeve valves are opened one at a time to fracture layers independently without perforating. Completions using these casing valves are called Treat And Produce (TAP) Completions and have a unique design feature in the valves that allows a theoretically unlimited number of valves to be placed in a single well without incremental reductions to the internal diameter (ID). This near full bore feature allows normal cementing operations to be preformed with a special cement wiper plug. A control line is connected between sequential valves. When the bottom valve opens the control line becomes pressurized and transfers the bore pressure to a piston in the valve immediately above. This piston squeezes a Cring and makes the ID smaller. At the end of the fracture treatment to the lower valve a dart is dropped during the flushing operation. This dart lands on the squeezed C-ring and seals the bore inside the sliding sleeve. Pressure is then increased until the next valve is pumped open. When this valve opens the next control line is pressurized squeezing the next C-ring. The main feasibility issue with this cemented sliding sleeve concept was fracture initiation pressure through the cement and into the formation without perforated holes. Significant laboratory testing was conducted which predicted fracture initiation pressure to be similar to that encountered in openhole or even lower. Fracture initiation pressures were closely monitored during several field installations and confirmed that perforations were not needed to initiate fractures in the formations. This paper describes TAP Completions how the TAP valves work and how the valves performed. Information on a TAP Completion with 6 layers is presented in detail and an overview of all installations to date. Introduction The US and Canada tight gas market is deploying new methods to efficiently stimulate multiple-layer reservoirs but the most common method remains the same. Most wells are completed with cemented casing. To stimulate the reservoir a plug is set one or more layers are perforated and then the layer(s) are stimulated as a stage. This practice is repeated multiples times until all the layers are stimulated. Most wells are flowed within 24 hours to remove the treating fluids from the reservoir. Operators seek to balance the quality and the cost of the stimulations vs. potential well production. One of the most important parameters affecting production is the number of layers fractured during a single stage. Stimulating multiple layers in a single stage is not ideal since layers with lower fracture gradients or formation pressure may take more of the treatment than planned leaving the higher pressure layers only partially treated. This is becoming more of an issue as development wells are being drilled in more dense spacing increasing the chances of treating some depleted layers. The Treat And Produce (TAP) Completion system has been developed to allow the efficient treatment of individual layers in cemented casehole completions. TAP Completions use special casing valves that isolate individual layers one at a time without any interventions. The TAP valves are near full bore and do not require incremental reductions of ID and thus allow normal cementing operations. The TAP valves also have unique helical ports that align to any preferential fracture plane regardless of the orientation of the valve in the casing string. These ports ensure a single bi-wing fracture plane is initiated from the well bore and the fracture initiation pressure is kept to a minimum.SCHLUMBERGERSPE112862Well DeliverabilityCompletion OptimisationNear Wellbore StressDipole Radial Profiling and Geomechanics for Near Wellbore Alteration Detection to Improve Productivity in a Matured FieldSurej Subbiah/Schlumberger; Wielemaker.E/Schlumberger; Joia P/Petrom SA; Hopper.L/Schlumberger; Fernandez LI/Schlumberger; Kongslien.M /Schlumberger; Edwards N/Petrom SAAbstract Cartojani is a mature oil field with depleted reservoir pressure supported by an aquifer in the deeper Cretaceous horizon. The Cartojani structure is located in the central alignment of the Moesic Platform. It is a monocline with large dimensions and low layer inclinations. The main hydrocarbon accumulation is found in the Sarmatian formation (Base Cretaceous Paleorelif) at the depth of 1100 to 1150 m. Currently the main productive horizons are sands from the lower Sarmatian (Basal Sarmatian). The facies variation can be seen both vertically and horizontally on a well-to-well basis even though the wells are very closely spaced. Sands have different oil retainer capacity and flow from clean to dirtier sands. The lower most units comprise of unconsolidated sands that are thinly distributed. These unconsolidated sands are normally completed using cased hole gravel pack. In order to select optimal completions it required both identification and estimation of the radial extent of the near-wellbore mechanical alteration that might cause near-wellbore permeability impairment. The near-wellbore alteration characterized by radial profiling of formation shear can be correlated with the skin effect and reservoir productivity index. Due to the nature of the formation formation damage is expected to be one of the main challenges to counter the observed decreasing production. A new dimension has been added to sonic measurements providing measurements in several dimensions: axial radial azimuthal. The radial measurements provide now the opportunity to determine whether the near wellbore experienced any alteration. The sonic data was processed to extract a very reliable compressional shear and Stoneley. Dispersion analysis confirmed the presence of alteration to the formation. Dipole radial profiling then demonstrated that in fact a 5 inch altered zone was present in the unconsolidated sands. Using the sonic data mechanical properties and stresses were calculated. The unconfined compressive strength (approximately 200 to 300 psi) values demonstrated that in fact it concerned very unconsolidated sand. Using the mechanical properties together with the possibilities for perforation design detailed analysis was performed. The analysis showed that the traditional gun selection would not surpass the skin and that in fact if would require deep penetrating charges with big hole (to minimize sand production). A proper gun system was selected based on the analysis. To improve the wells productivity deeper penetration and high shot density guns were selected as a perforating method to pass the radial extent of near - well bore mechanical alteration. After perforation the production test showed a 3-fold increment in production compared to the previous best producers in the field. The skin estimation based on the model compared very well to the measured values during production tests.SHELLSPE99921Well DeliverabilityCompletion OptimisationOpenholeOpenhole Completion Options: The Niger Delta ExperienceJ. Arukhe, SPE, Petro-Canada; L. Nwoke, SPE, Shell; C. Uchendu, SPE, BJ Services Co.; and S. Imie, SPE, U. of StavangerAbstract Within the Niger Delta clastic environment horizontal well completions have been widely used with success. Although conventional wells have been applied to drain reservoirs in Niger-Delta extensively in recent years horizontal wells have also gained acceptance as a proven reservoir management and well completion method. Production improvement factors (compared to conventional wells) of two or higher is not uncommon. To make decisions on the correct completion type to select it is important to be aware of the many sand control issues and the relative strengths/weaknesses of the systems available. Production hotspots arising from partially plugged screens are often a problem giving rise to the challenge of installing rugged sand face completions which again could also compromise production. When it comes to selecting a sand face completion strategy several operators have a number of concerns. This paper examines sand control options (barefoot standalone pre-drilled liner / screens or slotted liners gravel pack and expandables) for the Niger-Delta a high activity region in openhole applications. Typical key learning is presented. The openhole completions are preffered over casedhole completions in the relatively high transmissibility reservoirs of the Niger Delta as they will allow higher well productivity to be attained and their greater inflow area is also advantageous in solutions where scaling can occur like in water injection for pressure maintenance. Wells drilled and completed with a fully integrated study were profitable emphasing that planning drilling and completion as a discrete system performing drill-in-fluids QA/QC ensuring a stable hole and that all engineers take active roles to make proactive decisions / choices that can impact operations are keys to success for a typical completion method. Small independents that operate marginal oil wells will find openhole completion on horizontal wells useful to enhance production rates. Even the majors will agree that prevention based on experience and sound engineering practices is better than cure for most sand control problems. A common score card item irrespective of the category of well owner is to deliver best-in class producers that quickly pay back investment capital. Introduction Openhole completions (Figure 1) are the most basic completion types in Niger Delta and are only used in very competent formations which are unlikely to cave in. These formations are often found deeper than 6000 although each reservoir is different. In the strict sense an openhole completion consists of simply running the casing directly down into the formation leaving the end of the piping open without any other protective filter. In a broader context the well completion options in open hole can be barefoot with a slotted liner screens or gravel pack (Fig. 1 & 3). Standalone screens appear to be well suited to prevent sand ingress in high permeability clean formations. For more poorly sorted sands openhole horizontal gravel packs can be used to surround the screen and stabilize the wellbore in a horizontal well. Advantages of horizontal wells over vertical ones have been well documented. Specifically in the Niger Delta horizontal wells have been found to have the potential to dramatically enhance the economics of projects. Horizontal wells are placed in the reservoirs precisely to maximize hydrocarbon (oil and gas) production. They provide added wellbore exposure to the reservoirs in geometries that allows operators in Niger Delta to maximize hydrocarbon recovery rates and project economics spread out the pressure drop across a longer interval of wellbore minimizing water coning repenetrate a reservoir to get away from historical water coning and recover reserves that would otherwise be stranded. Some operators have also taken advantage of horizontal well geometry for secondary recovery projects. The obvious disadvantages of horizontal wells include that only one zone at a time may be drained. If the reservoir has multiple pay-zones especially with large differences in vertical depth or permeabilities draining all the layers using a single horizontal well could pose a challenge. There also appears to be an extra initial risk for most horizontal well projects that they will be commercially successful.SHELLSPE100495Well DeliverabilityCompletion OptimisationOpenholeMechanistic Understanding of Rock/Phosphonate Interactions and the Effect of Metal Ions on Inhibitor RetentionMason B. Tomson, Amy T. Kan, Gongmin Fu, and Dong Shen, Rice University; and Hisham A. Nasr-El-Din,* SPE, Hamad Al-Saiari, SPE, and Musaed Al-Thubaiti, Saudi Aramco * now with Texas A&M UniversitySummary This paper discusses the effects of Ca2+ Mg2+ and Fe2+ on inhibitor retention and release. Better understanding of phosphonate reactions during inhibitor squeeze treatments has direct implication on how to design and improve scale inhibitor squeeze treatments for optimum scale control. Putting various amounts of metal ions in the inhibitor pill adds another degree of freedom in squeeze design especially in controlling return concentrations and squeeze life. Phosphonate reactions during squeeze treatments involve a series of self-regulating reactions with calcite and other minerals. However excess calcite does not improve the retention of phosphonate due to the surface poisoning effect of Ca2+. The squeeze can be designed so that maximum squeeze life is achieved by forming a low solubility phase in the formation. Addition of Ca2+ Mg2+ and Fe2+ in the pill solution at 0.1 to 1 molar ratios significantly improves the retention of phosphonate. Alternatively these metal ions can be dissolved from the formation while an acidic inhibitor pill is in contact with the formation minerals. Both BHPMP and DTPMP returns were significantly extended by the addition of metal ions (e.g. Ca2+ and Fe2+). The addition of Mg2+ may increase the long-term return concentration which is important for some wells where a higher inhibitor return concentration is needed. The laboratory squeeze simulations were compared to return data obtained from squeeze treatments performed on two wells located in a sandstone reservoir in Saudi Arabia. The sandstone formation contains significant amounts of iron-bearing minerals. Introduction Mineral scale formation is a persistent problem in oil and gas production especially in older reservoirs with increased water production and drawdown. Inhibitor squeezes are commonly used to deposit a suitable scale inhibitor in the formation. During an inhibitor squeeze treatment a predetermined volume of the inhibitor solution is pumped into the formation and followed by injecting another volume of brine or diesel to place the inhibitor further away from the wellbore and allowing it to react with the existing rock. During production following a squeeze treatment the inhibitor is slowly desorbed or dissolved into the formation water. Earlier efforts have focused on describing what happens and when to resqueeze (Hong and Shuler 1988; Rogers et al. 1990). More recent papers have advanced the knowledge of inhibitor reactions under various production conditions (Benton et al. 1993; Sweeney and Cooper 1993; Lawless et al. 1993; Sorbie et al. 1994; Jordan et al. 1994; Jordan et al. 1995; Jordan et al. 1997; Lawless and Smith 1998; Smith et al. 2000; Collins 2003). The primary conclusions from several previous studies (Al-Thubaiti et al. 2004; Kan et al. 2004a; Kan et al. 2004b; Tomson et al. 2006) of NTMP(aminotri(methylene phosphonic acid))-calcite reaction are: (1) The extent of NTMP retention by carbonate-rich formation rock is limited by the amount of calcite that can dissolve prior to inhibitor-induced surface poisoning; (2) calcite-surface poisoning effect is observed after approximately 20 molecular layers of phosphonate surface coverage that retards further calcite dissolution; and (3) the consequence of retarded calcite dissolution is that less basic ion CO2- 3 is released into solution leaving the solution more acidic; therefore more soluble calcium phosphonate solid phases form. The inhibitor return concentration can be altered by changing the inhibitor concentration in the pill. The ability to control the high inhibitor return may be useful in initial water breakthrough where high inhibitor return is desired. Kan et al. (2005) also compared the retention of NTMP DTPMP (diethylenetriamine penta (methylene phosphonic acid)) BHPMP (bis-hexamethylenetriamine penta (methylene phosphonic acid)) and PPCA (phosphinopolycarboxylic acid) with pure calcite a calcite-rich chalk rock a calcite and clay-rich formation rock from Guerra Ranch McAllen Texas and a quartz sandstone with very little calcite from Frio formation Galveston County Texas. Similar inhibitor returns were observed in both calcite-rich and low-calcite rock suggesting that calcite is the primary solid responsible for phosphonate retention. Clays or other minerals play a secondary role in phosphonate retention. The retention of the polymer-based inhibitors is much lower than phosphonates. The data show that BHPMP provides the highest squeeze life at MIC > 50 mg/L. DTPMP is the preferred inhibitor at MIC between 1 and 50 mg/L and NTMP is the preferred inhibitor at MIC < 0.3 mg/L. Calcium ion (Ca2+) is the predominant divalent metal ion in most oilfield produced waters. Previously several reports indicated that Ca2+ and Mg2+ have a strong effect on inhibition of barite by common inhibitors (Fernandez-Diaz et al. 1990; Boak et al. 1999; Collins 1999). Collins (1999) observed a clear change in crystal habit between barite growth in the presence and absence of Ca. Xiao et al. (2001) noted that Ca significantly enhanced the inhibitor efficiency; however Ca had no effect on barite nucleation time in the absence of scale inhibitor. Collins (1999) reported a similar effect of Ca with polyaspartate as a barite inhibitor. The enhanced inhibition efficiency may be attributed to the reduction of net negative charge of the polyion due to complexation of the polyaspartate with divalent cations (Tomson et al. 2003). In the present paper the influence of metal ions e.g. Ca2+ Mg2+ and Fe2+ on the inhibitor retention and release was evaluated in both laboratory simulation and field case studies. These metal ions were either originally added to the inhibitor pill solutions or generated in-situ because of the dissolution of reservoir minerals by acidic inhibitors.SCHLUMBERGERSPE101720Well DeliverabilityCompletion OptimisationProduction Tubing String Design for Optimum Gas RecoveryB.D. Poe Jr., SPE, SchlumbergerAbstract This paper presents the results of an investigation of the design of production tubing string setting depths in gas wells to optimize gas recovery in wells that produce free liquids in conjunction with the gas. Particularly important in this work has been the evaluation of the conditions for which the well outflow velocity is less than that which would be required to continuously transport and unload liquids from the well. Sub-critical velocities are often e