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Collaborating Authors
SPE/PAPG Annual Technical Conference
Abstract It is seen that gas wells if produced without planned rates may produce waterpre-maturely. Production of water basically loads the subject well bygenerating hydrostatic head within the well tubing. Secondly the waterproduction alters the in-situ gas saturation in near well bore region resultingchange in the relative permeability. Both these reasons make the subject wellproblematic due to decrease in well productivity and increase in the welloperating cost. Also the handling of produced water is uneconomical in manycases. The work done for this study is general in nature, though the essence ofthis work comes from data collected from different gas wells having waterproduction problem. This study gives an overview of all the methods andtechniques, which can be used for, expel-out such problems and optimize gasproduction. Main stress has been given on Tubing Performance Curve study inorder to select best tubing size and calculation of the optimum rates againstselected tubing size. General tubing performance curve are also presentedshowing the behavior of the well before and after water production. On the basis of study of different techniques related to the Gas wellproduction optimization and water production control we became, able to give asolution of interchanging the well tubing strings without purchasing any newstring pertaining to large gas fields where different tubing sizes are used indifferent wells. Introduction It is considered that wells producing dry gas have usually lower flowingbottom-hole pressure [1]. Liquid loading happens when the gas does not haveenough energy to carry the water out of the wellbore. Water accumulates at thebottom of the well, generating backpressure in the wellbore and blocking gasinflow [2]. For the optimization of the production of the gas it is necessaryto unload that water from the wellbore so that there should occur a decrease inthe backpressure of the static water column.
- Well Completion > Completion Installation and Operations (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Well performance, inflow performance (1.00)
- Production and Well Operations > Well Operations and Optimization > Produced water management and control (1.00)
- (2 more...)
Abstract Thick Mesozoic sedimentary rocks are exposed over a wide area in the Lower andUpper Indus Basin of Pakistan, particularly along the western margin of theIndian Plate. The Mesozoic sequence is generally comprised of clastic facies inthe lower part, carbonate facies dominate in the upper part. In the SurgharRange the Datta Formation represents the lower part of the early Jurassicsequence. The formation is comprised dominantly of clastic facies withcarbonate interbeds at places. The Datta Formation of early Jurassic wasmeasured and described in the Chichali and Pannu gorge, Surghar Range. Thetotal thickness of Datta sediments at Chichali section is 161m while thicknessof the Pannu section is 225m. Sections were measured for sedimentologicalstudies and sand bodies were classified accordingly. On the basis oflithological variation and sedimentary structures eight lithofacies have beenrecognized. These lithofacies are; LF 8: Clay lithofacies, LF 7: Cross beddedsandstone lithofacies, LF 6: Siltstone lithofacies, LF 5: Interbedded limestoneand shale lithofacies, LF 4: Sandstone with intercalations of clay lithofacies, LF 3: Carbonaceous shale lithofacies, LF 2: Channelized sandstone lithofacies, LF 1: Interbedded sandstone and shale lithofacies. Three kinds of sand bodies were identified, these are mostly multistoreychannels but some simple ribbons as well as sheets are also present. Fossilsidentified are gastropods and pelecypodes. After collecting and interpreting the data acquired from the measuredsections and sandstone bodies' geometry analysis, it is interpreted that theDatta Formation was deposited along the delta plain and delta front setting bya fluvial-wave dominated delta. Continental, transitional to oceanic conditionsprevailed at the time of deposition of the Datta Formation and all the faciesshow prograding deltaic setting. Cross beds interpretation indicates east towest flowing channels.
- Europe > Norway > Norwegian Sea (0.25)
- Asia > Pakistan > Arabian Sea (0.25)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.71)
- Oceania > Australia > South Australia > Cooper Eromanga Basin > Tirrawarra Field (0.99)
- Asia > Pakistan > Upper Indus Basin (0.99)
- Asia > Pakistan > Punjab > Upper Indus Basin > Potwar Basin > Dhulian Field > Chorgali-Sakesar Formation (0.99)
- (2 more...)
Abstract This paper presents a methodology to analyze sanding potential on clasticreservoirs by determining the critical drawdown pressure required to on-setsand production. The critical drawdown pressures are obtained from ananalytical model that describes the mechanical stability of a perforationcavity in a Mohr-Coulomb material under Darcy flow regime. The study wasperformed on several wells from different oil fields in South Oman with themain objective to identify the formation intervals with the greatest sandingpotential. The critical drawdown assessment requires geomechanical characterization ofthe formations of interest. Static mechanical properties and strengths wereobtained from a log-based program. This program is based on FORMEL; which is aconstitutive model describing the microscopic processes occurring in a rocksample during triaxial loading. The basic inputs for running the model are welllog information, petrophysical volumes, and the pore fluid properties of theformation. The geomechanical characterization and the pore pressure profilewere used to calculate the maximum drawdown pressure needed before sandingoccurs on foot by foot basics. A clear correlation was found between lowstrength formations and the intervals with low critical drawdown pressurevalues. The analysis allows identification of high sanding potential intervals for aselective perforation program, and it supports gravel pack decisions whererequired. Also, the critical drawdown profiles assist to choose a suitable sandcontrol completion technique, ranging from classic gravel packing tostate-of-the-art expandable sand screen installations. Introduction Knowledge of rock mechanical properties is important for the planning of bothdrilling and production strategies. Traditionally, rock mechanical propertiesare obtained directly from laboratory triaxial tests on core samples. Hence, mechanical properties are typically only defined at discrete depths were thecore samples were taken and lab values can be skewed due to the core handlingprocess. Accurate sand production prediction, however, requires a continuouspresentation of mechanical properties with depth including the cohesivestrength and internal friction angle of the rock.
- Asia > Middle East > Oman (0.73)
- North America > United States > Texas (0.46)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.48)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Sognefjord Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Heather Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Fensfjord Formation (0.99)
- (10 more...)
Fracture Characterization and Their Impact on the Field Development
Jadoon, M. Saeed K. (Oil & Gas Development Company Ltd. Islamabad) | Jadoon, Ishtiaq A.K. (Schlumberger Pakistan) | Bhatti, Abid Husaain (Oil & Gas Development Company Ltd. Islamabad) | Ali, Asghar (Oil & Gas Development Company Ltd. Islamabad)
Abstract Fracture characterization is a biggest challenge for the geoscientists insandstone and carbonate reservoirs. With the advancement of all technicalcapabilities in the acquisition of surface and subsurface Geological data, still it is extremely difficult to understand, characterize, and predict thedistribution of fractures in a field. Image logs can successfully be used tolocate and to provide directional trends of fractures near the wellbore.However, capturing all the fractures in one well and to predict their flowbehavior can still be a challenge. In this paper, a case study of a fracturedcarbonate reservoir will be presented. The field is currently producing about500 bbl of oil per day through fractures. Four wells have been drilled on thestructure to drain the oil reserves. Water flooding is being carried-out in thefield for the last 9 years for pressure maintenance and now 80% water is beingproduced. The reservoir has very low primary porosity and permeability, and theflow is through fractures only. On the basis of the three wells fracture data,a new well was drilled, located ideally at a structurally higher position, increstal area of the field. Image data showed abundance of fractures withdifferent orientation was seen in the well bore but the well didn't flow andthat led to its suspension. In this study, fracture data from image logs iscompared with outcrop analogs and seismic reflection and interpretation data.In this paper, limitation of the available information, importance ofunderstanding the stress regime, integration of G & G data and lessonlearned from the current evaluation of the fracture system and their impact ondevelopment of field in Potwar basin will be presented. Geological and Reservoir Overview Fimkaser oil field was undertaken as a case study for the understanding andcharacterization of the fracture. The field is located in the Himalayanforeland in North Pakistan and represents fault related anticline as shown inFigure-1. It was discovered in 1989 by Gulf Petroleum and later on handed overto the OGDCL. The producing formations are Chorgali and Sakessar limestone ofEocen age. These reservoirs are generally of low/none matrix porosity (1–3.5 %)and may be classified as type-1 of Nelson (1982), in which fractures provideessential porosity and permeability. In these types of carbonate reservoirs, secondary mouldic/vuggy and fracture porosity is important for storage ofhydrocarbons.
- Asia > Pakistan > Punjab (1.00)
- North America > United States > Texas (0.68)
- Geology > Geological Subdiscipline > Geomechanics (0.71)
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (0.67)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.50)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.47)
- Asia > Pakistan > Upper Indus Basin > Potwar Basin (0.99)
- Asia > Pakistan > Punjab > Upper Indus Basin > Potwar Basin > Joya Mair Field (0.99)
- Asia > Pakistan > Punjab > Upper Indus Basin > Potwar Basin > Dakhni Field > Chorgali-Sakesar Formation (0.99)
- (3 more...)
Abstract Carbonate reservoirs in Northern Pakistan are characterized by tight limestone.In these reservoirs, fractures are important for production and reservoirmodeling. This paper addresses problems related to subsurface fracture analysisbased mainly on image logs. Natural fractures occur as systematic and unsystematic sets of definite andrandom orientation respectively. The subsurface analysis of fractures useselectrical and acoustic image logs to characterize fractures as either naturalor induced features. They are classified as conductive or resistive features, representing possibly open or closed (mineralized) fractures, respectively.Using image logs, natural fractures are interpreted and classifieddescriptively to be continuous or discontinuous features representingsystematic fractures or classified as chicken-wire (microfractures) fracturesrepresenting unsystematic sets. Statistical analysis of fractures is used toclassify them into geometrical and genetic sets as longitudinal (extensional), transverse (tensional), and oblique (shear) to the structure. Transversefractures are known generally as most open. They develop parallel to themaximum horizontal in-situ stress and extend deep into the structure.Longitudinal fractures, those parallel to the fold axes, are observed toproduce hydrocarbons in several fields in Northern Pakistan. Fracture densityimpacts production and reserves calculations. However, fracture density isstrongly influenced by the lithology and layer thickness. Widely spacedfractures are observed in massive carbonate reservoirs, and closely spacedfractures of narrower aperture are observed in laminated strata. Thus, individual fractures in massive carbonates require to be identified for theirimpact on production. Fractures are observed to occur as discontinuous featuresof right- or left-stepping geometry and as en echelon features of significantlywider aperture in shear bands. These features together with vugs and leachedfeatures may provide zones of higher porosity, permeability, and storagecapacity with isolated distribution in tight carbonates. Therefore, knowledgeabout fracture occurrence and distribution is important to predict sweet spotsfor drilling and field development.
- Asia > Pakistan (1.00)
- North America > United States > Texas (0.46)
- North America > Canada > British Columbia (0.28)
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (1.00)
- Geology > Rock Type > Sedimentary Rock (1.00)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.66)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (23 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (4 more...)
Abstract An innovation in the methodology of conducting drillstem tests (DSTs) in tightgas reservoirs is presented, along with a simplification in the interpretationof the data obtained. DSTs in tight gas reservoirs are a problem because theflow rates are often too low to be measured by conventional equipment. In thesecases a normal flowing and buildup test should be followed by a closed chambertest to produce usable estimates of flow rates at various times during thepreceding normal flowing and buildup test. This estimated flow rate can then beused to interpret the buildup after the flow testing, which is produced byshutting the downhole valve. In the interpretation of DST data from a tight gas reservoir, factors suchas the following have to be considered:large variation of gas propertiesresulting from the large pressure range involved; flow rate duration thatcan be many times shorter than the buildup period; varying flow rate duringthe flowing part of the test; and impact of boundaries andheterogeneities. We show that a simple interpretation approach with constant flow rates andpseudo-pressure yields results that are within the intrinsic accuracy limitsexpected from such a test. The benefits to the field interpreter of using the methods presented are 1)operational flexibility: if the well flows strongly enough the rate may bemeasured at surface; if it does not, a closed chamber test can be added; 2) thebenefit of the deeper radius of investigation of a test flowing at surface isretained; 3) field interpretation is simpler whether surface measurement ispossible or not. Introduction The two major challenges that face the interpreter in tight gas DSTs are thedifficulty in measuring rate, and the selection of interpretation tools andtechniques.
Abstract Integrity of well structure is a vital factor to produce hydrocarbons fromsubsurface. It is important that well structure along with cement behind thecasings remains intact to get controlled and risk free production during lifeof a well. This objective is achieved by making every effort to ensure goodcement behind pipe and selecting suitable well tubulars honoring reservoirfluid composition and fluid flow rates. In case the criteria of well integrityis not met, flow of fluids behind casing and communication between tubularscreate problems and may lead to uncontrolled flow of well fluid creatingenvironmental and safety hazards. Bagla gas field is located within the Indus Basin with producing horizon inLower Goru Formation of Cretaceous age. This is a single well field, which wasdrilled by Phillips Petroleum Exploration Ltd during 1988. Later on OGDCLacquired this field. The field could not be developed due to its marginalreserves, remote location, non-availability of gas buyer in near vicinity ofthe field and non-attractive economics in case gas is sold to SSGCL due to highcost of pipeline quality gas to SSGCL gas transmission network. During April 2004 gas channeling to surface was observed in the nearby arealocated within a radius of 2–3 km from the Bagla well. This gas channeling wascausing environmental and safety hazards in the area. This paper discusses themeasures taken by OGDCL to diagnose the cause of problem and efforts made tocontrol the well to contain the environmental and safety hazards in thearea. Introduction Bagla is a single well gas condensate field located in Thatta Exploration Lease. The field is located about 150 km East of Karachi and 87 km South ofHyderabad. Nearest OGDCL well Nur # 01 is located at 3.5 km towardssouthwest.
- North America > United States (1.00)
- Asia > Pakistan > Sindh > Karachi Division > Karachi (0.25)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
- Asia > Pakistan > Sindh > Lower Indus Basin > Goru Formation (0.99)
- Asia > Pakistan > Balochistan > Ranikot Formation (0.99)
- Asia > Pakistan > Arabian Sea > Indus Basin (0.99)
Abstract Geochemical studies of Parh Limestone, through major and trace elementanalyses, were made to evaluate its depositional environment. Parh Limestonerepresents Upper Cretaceous period in the Kirthar and Sulaiman provinces ofLower Indus Basin. The Parh Limestone of Turonain-Santonian age is well exposedin NNWSSE trending Pab Range of Balochistan, which merges into Kirthar FoldBelt northwards. The Indian Plate motion, sea-level fluctuations and volcanismwere the main controlling factors responsible for the distribution of elementsduring the deposition of Parh Limestone. During the cycle of deposition of ParhLimestone the distribution of Mn and terrigenous material (clay) revealed HighStand System at the beginning (Turonian, 91m.y.), which latter turned into LowStand System and finally terminated as Transgressive System with a very broadshelf environment (Maximum Flooding Surface). The Al/Mn+Fe+Al ratio of the ParhLimestone revealed slow rate of drifting initially and high rate at latterstages due to high rate of sea-floor spreading. The Ca/Mg, Ca/Fe, Mg/Fe ratiossuggested hemipelagic environment of deposition. The contents of Ba, Zn and Cowere higher than the average abundance in the limestone reflecting partialinfluence of igneous activity at the time of deposition. The composition of anigneous sill, at the base of Parh Limestone demonstrates oceanfloor tholeiites, affiliated with Mid Oceanic Ridge Basalts (MORB). Introduction Present study emphasizes to evaluate different parameters of depositionalenvironment of Parh Limestone on the basis of major and trace elementgeochemistry. Tectonically induced changes in sedimentation patterns, volcanismand other factors within the carbonate system are also discussed. The study andadjoining areas are underlain by sedimentary sequences ranging from Jurassic toOligocene (Table 1). The Middle and Upper Cretaceous sedimentary rocks (Goru, Parh, Moghal Kot, Fort Munro, and Pab Sandstone) are well exposed in the PabRange (Fig. 1) while in the SW mélange zone, exotic blocks of Loralai(Jurassic), Parh (Cretaceous), Jhakar (Eocene) crop out along with ophioliticmélange [1].
- Geology > Sedimentary Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (1.00)
- Asia > Pakistan > Upper Indus Basin (0.99)
- Asia > Pakistan > Punjab > D.G Khan District > Pab Formation (0.99)
- Asia > Pakistan > Lower Indus Basin (0.99)
- (3 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Sedimentology (0.86)
- Reservoir Description and Dynamics > Fluid Characterization > Geochemical characterization (0.86)
Abstract This paper describes the success story of the first water shut off treatmentusing Engineered Micro-cement Slurry (EMS) through Coiled Tubing in Pakistan.The well was an oil well producing from multiple zones, but mainly the lowerzone (C-Sand). Due to high water cut, it was decided to isolate the C-Sand andto produce only from the upper perforations (A/B Sands). Based on economics andtechnical feasibility, water shut off treatment through a cement plug wasselected to isolate the C-Sand zone. 148ft of cement plug was squeezed andspotted across the C-Sand through coiled tubing using conventional cementslurry. After setting the cement plug, water cut was reduced by 23% and thewell initially produced up to 380bopd from the A/B Sand. After 3 monthsproduction, water cut level increased drastically back to 100%. A slickline runconfirmed that the cement plug had failed and top of cement dropped 48ft fromits original depth. It was suspected that the plug failed due to possiblecontamination in the cement, which enabled water to channel up across the plug.A remedial cement plug through coiled tubing was subsequently set, but thistime using EMS slurry to ensure that any channels in the previous plug werecemented and ensuring that the perforations were sealed off completely. The jobwas conducted successfully and the water cut was reduced by 25%, with initialproduction of 500bopd from the A/B Sands. Introduction Excessive water production is a major concern in the production of oil andgas. High water production can contribute surface problems (water handling anddisposal) and downhole problems such as scale deposition, emulsion, asphaltene, sand production, corrosion, etc. In many areas in Pakistan, field waterproduction exceeds hydrocarbon production. The majority of wells with waterproduction problems in Badin are producing through artificial lift. Over time, water production continues to increase until wells cease to produce due to highwater loading or reach their economic limit and are shut it until furtherintervention is decided.
- North America > Trinidad and Tobago > Trinidad > C-Sand Formation (0.99)
- Africa > Middle East > Morocco > North Atlantic Ocean > Rissana License > C Sand Formation (0.99)
- Asia > Pakistan > Sindh > Indus Basin > Badin Block > Badin Field (0.98)
- Well Drilling > Casing and Cementing (1.00)
- Well Completion > Completion Installation and Operations > Coiled tubing operations (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
- Production and Well Operations > Well Operations and Optimization > Produced water management and control (1.00)
Abstract BP Pakistan has been laying cross-country pipelines to produce oil and gas inthe Badin concession for the last 20 years, and has gained considerableexperience with conventional carbon steel material. The average timerequired tolay a 4" diameter × 5000 ft long steel pipeline has been around 4 weeks. Therewas a desire to reduce this time to improve put-on-production (POP) time. Otherfactors driving us to think out of the box were corrosion, high operating andlife cycle cost etc. A project consisting of laying 4" -1500 psig × 5000 ft Spoolable ReinforcedComposite (SRC) pipeline from wellhead to facility was initiated inconsultation with BP Exploration & Production Technology Group (EPTG). EPTGwas actively involved in the development of this new technology in the wider BPworld, and this was seen as an opportunity to test the material in Pakistan.Testing of the material for potential use in high-pressure (HP) gas was alsoenvisaged. In order to ensure rigorous testing of new material and technology, one of the toughest construction location (high water table, collapsing trench, three major crossings, a number of minor crossings, etc.) was selected. Sincemost of the potential risks to delivery were evaluated upfront, the result wasa record laying time of 0.5 km / hr. The project was completed with greatsuccess and learnings for the use of this technology in future, and to sharewith others who choose to use the same material and technology. This paper provides a brief overview of this new material, its physicalproperties, potential use, characteristics, advantages over conventional carbonsteel and installation experience at BP Pakistan and recommendations for futureutilization in oil and gas industry. Introduction BP Pakistan operates the Badin Blocks located in the Lower Indus Basin in SindhProvince. The first oil discovery, Khaskeli oil field, was made in 1981. Sincethen, 59 oil and gas fields have been discovered in Badin Blocks (Fig. 1).
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.48)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.47)
- Asia > Pakistan > Lower Indus Basin (0.99)
- Asia > Pakistan > Sindh > Indus Basin > Badin Block > Badin Field (0.98)