GEOLOGICAL AND RESERVOIR ENGINEERING CONSIDERATIONS FOR THE NORTH RANKIN GAS RECYCLING PROJECT

1988 ◽  
Vol 28 (1) ◽  
pp. 54
Author(s):  
C. Barker ◽  
P. Vincent
Keyword(s):  
Development Project ◽  
Reservoir Engineering ◽  
Recycling Rate ◽  
Well Testing ◽  
Well Performance ◽  
Sweep Efficiency ◽  
Spare Capacity ◽  
Injection Wells ◽  
The North ◽  
Gas Recycling

The North Rankin Field, situated in the Dampier Sub-basin offshore north-western Australia, is being developed as part of the North West Shelf Development Project. Substantial excess production capacity from the field exists until liquified natural gas exports to Japan plateau in late 1993. A recycling project was proposed to utilise this spare capacity. Gas produced in excess of current sales volumes is stripped of its condensate, and the lean gas is reinjected into the reservoir thereby increasing condensate production and the total recovery.The North Rankin A Gas Recycling Project was commissioned in June 1987 and its performance to date has been better than original expectations. The average recycling rate during the first few months of operation was approximately 13 x 106sm3/d (450 MMscfd) with associated condensate production of 1600 m3/d (10,000 STB/d). Studies suggest that the total recycled volume for the project, up until late 1993, may be in the order of 19 x 109sm3 (0.7 Tcf) with additional condensate recovery of approximately 2 million cubic metres (13 MMSTB).The design and implementation of subsurface aspects of the recycling project required close co-operation between the geological and reservoir engineering disciplines. Detailed studies were undertaken to determine reservoir extent and communication within the field in order to identify likely paths for lateral and vertical gas movement. Estimates of swept reservoir volumes were used to determine injected lean gas distributions. These gas distributions, in conjunction with operational aspects, formed the basis for the production and injection policy developed to maximise sweep efficiency and optimise condensate recovery from the recycling project.Multiple zone through tubing perforation was needed in most injection wells. The initial perforation was performed with an optimal underbalance pressure. Subsequent perforation was neutrally balanced. The degree of underbalance while perforating has a significant effect on perforation efficiency and simple models were used to predict this.Accurate estimates of well injectivity must be made to ensure that the perforation design allows well target rates to be met. Numerical reservoir and wellbore models were constructed to evaluate well injection potentials and gas distributions.To verify the design procedures and well performance, well testing and production logging was carried out before and after the start up of gas recycling. Production logging surveys in the injection wells and measuring condensate gas ratios in the producers are essential in monitoring the performance of gas recycling.

Mechanism Analysis of Indigenous Microbial Enhancement for Residue Oil Recovery

2011 ◽  
Vol 365 ◽  
pp. 305-311
Author(s):  
Fu Chang Shu ◽  
Yue Hui She ◽  
Zheng Liang Wang ◽  
Shu Qiong Kong
Keyword(s):  
Oil Recovery ◽  
Mechanism Analysis ◽  
Sweep Efficiency ◽  
Injection Wells ◽  
The North ◽  
Physico Chemical ◽  
Production Wells ◽  
Microbial Enhancement ◽  
Filtration Properties ◽  
Technological Treatment

Biotechnological nutrient flooding was applied to the North block of the Kongdian Oilfield during 2001-2005. The biotechnology involved the injection of a water-air mixture made up of mineral nitrogen and phosphorous salts with the intent of stimulating the growth of indigenous microorganisms. During monitoring of the physico-chemical, microbiological and production characteristics of the North block of the Kongdian bed, it was revealed significant changes took place in the ecosystem as a result of the technological treatment. The microbial oil transformation was accompanied by an accumulation of carbonates, lower fatty acids and biosurfactants in water formations, which is of value to enhanced oil recovery. The microbial metabolites changed the composition of the water formation, favored the diversion of the injected fluid from closed, high permeability zones to upswept zones and improved the sweep efficiency. The results of the studies demonstrated strong hydrodynamic links between the injection wells and production wells. Microbiological monitoring of the deep subsurface ecosystems and the filtration properties of the fluids are well modified, producing 40000 additional tons of oil in the test areas.

NORTH RANKIN 'A' GAS RECYCLING PROJECT — DESIGN, CONSTRUCTION AND COMMISSIONING

1988 ◽  
Vol 28 (1) ◽  
pp. 68
Author(s):  
D.J. Holt ◽  
C. de Jong ◽  
D.G. Rowell
Keyword(s):  
Gas Turbine ◽  
Production Capacity ◽  
Injection Wells ◽  
Total Recovery ◽  
The North ◽  
Start Up ◽  
Excess Production ◽  
Major Incidents ◽  
Early Production ◽  
Gas Recycling

Gas recycling, to increase early production and total recovery of hydrocarbon condensate, was implemented on the North Rankin 'A' platform to take advantage of excess production capacity prior to the commencement of the LNG export phase. By recycling excess 'dry' gas back into the reservoir, condensate production has been doubled, to around 3 000 kl per day (19 000 barrels) per day and ultimate recovery increased.The additional facilities installed included five injection wells, an additional production well, and a 23 MW gas turbine driven gas recompression facility that was retrofitted within existing facilities on the platform. Designed in-house, the facility involved relocation of some operating plant and piecemeal installation of a new 400 tonne module containing a 23 MW aero-derivative gas turbine driven high pressure (30 MPa) centrifugal compressor and ancillary equipment. The compressor set was extensively tested under full load conditions at the manufacturer's works in France before delivery.Offshore construction was complicated by the congested working area and the difficulties of working in and integrating with live production facilities but was completed without major incidents or causing undue interference to platform production. Commissioning proceeded quite smoothly. Full operation was achieved within ten days of initial start-up, and the facility has continued to yield impressive production results.

The New Generation of Outflow Control Devices Autonomously Controlling the Conformance of Water Injection Well- A Case Study with ADNOC Onshore

2021 ◽  
Author(s):  
Sultan Ibrahim Al Shemaili ◽  
Ahmed Mohamed Fawzy ◽  
Elamari Assreti ◽  
Mohamed El Maghraby ◽  
Mojtaba Moradi ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Dynamic Properties ◽  
Short Circuit ◽  
Water Injection ◽  
Performance Outcomes ◽  
Injection Well ◽  
Well Performance ◽  
Injection Wells ◽  
Horizontal Section ◽  
Control Devices

Abstract Several techniques have been applied to improve the water conformance of injection wells to eventually improve field oil recovery. Standalone Passive flow control devices or these devices combined with Sliding sleeves have been successful to improve the conformance in the wells, however, they may fail to provide the required performance in the reservoirs with complex/dynamic properties including propagating/dilating fractures or faults and may also require intervention. This is mainly because the continuously increasing contrast in the injectivity of a section with the feature compared to the rest of the well causes diverting a great portion of the injected fluid into the thief zone which ultimately creates short-circuit to the nearby producer wells. The new autonomous injection device overcomes this issue by selectively choking the injection of fluid into the growing fractures crossing the well. Once a predefined upper flowrate limit is reached at the zone, the valves autonomously close. Well A has been injecting water into reservoir B for several years. It has been recognised from the surveys that the well passes through two major faults and the other two features/fractures with huge uncertainty around their properties. The use of the autonomous valve was considered the best solution to control the water conformance in this well. The device initially operates as a normal passive outflow control valve, and if the injected flowrate flowing through the valve exceeds a designed limit, the device will automatically shut off. This provides the advantage of controlling the faults and fractures in case they were highly conductive as compared to other sections of the well and also once these zones are closed, the device enables the fluid to be distributed to other sections of the well, thereby improving the overall injection conformance. A comprehensive study was performed to change the existing dual completion to a single completion and determine the optimum completion design for delivering the targeted rate for the well while taking into account the huge uncertainty around the faults and features properties. The retrofitted completion including 9 joints with Autonomous valves and 5 joints with Bypass ICD valves were installed in the horizontal section of the well in six compartments separated with five swell packers. The completion was installed in mid-2020 and the well has been on the injection since September 2020. The well performance outcomes show that new completion has successfully delivered the target rate. Also, the data from a PLT survey performed in Feb 2021 shows that the valves have successfully minimised the outflow toward the faults and fractures. This allows achieving the optimised well performance autonomously as the impacts of thief zones on the injected fluid conformance is mitigated and a balanced-prescribed injection distribution is maintained. This paper presents the results from one of the early installations of the valves in a water injection well in the Middle East for ADNOC onshore. The paper discusses the applied completion design workflow as well as some field performance and PLT data.

Evaluating the Lower Cruse and Navet Formations Within the Wd-8 Lease Operatorship Block

2021 ◽  
Author(s):  
Mark Emmanuel Bishop ◽  
Wilson Lalla ◽  
Xavier Ravi Moonan
Keyword(s):  
Well Testing ◽  
Geological Model ◽  
The South ◽  
Forest Reserve ◽  
The North ◽  
Well Spacing ◽  
Northern Portion ◽  
Channel Deposits ◽  
Sand Bodies ◽  
Slope Channel

Abstract Lease Operatorship block WD-8, lies within the Forest Reserve oilfield. Forest Reserve is known for having the ENE-WSW trending, south easterly verging Forest Reserve anticline which plunges into NW-SE trending Los Bajos Fault. Regionally to the south of the Forest Reserve anticline lies the south westerly plunging Siparia syncline and to the north of the Forest Reserve anticline is the Morne L′ Enfer syncline. WD-8 is situated on the northern flank of the Forest Reserve anticline with the axis of the anticline occurring within the southern part of the block. Prior to 2018, TETL last drilled within the WD-8 block in the year 2014. Drilling within the WD-8 block pre-2018 was mainly in the southern portion of the block. The year 2018 saw TETL drill five wells in the northern part of the WD-8 block. The results from these wells prompted an evaluation within the Northern portion of the WD-8 block to determine the structure and extent of the Lower Cruse and Navet reservoirs. Field wide mapping post 2018 drills within the block highlighted the sand trend at the Cruse level is in a WSW-ENE direction and that these sands in northern WD-8 are very narrow with maximum widths ranging between 100 ft – 150 ft. Additionally, it showed that by using a smaller well spacing, wells would encounter different producing sand bodies not seen in adjacent wells. Differences in the sand character between wells in the Southern part of the block to wells in the northern part of the block at the Lower Cruse level were also seen. The Lower Cruse section in the southern part of the WD-8 block tends to have thick stacked slope channel sand deposits, while the northern part of WD-8 has relatively thin stacked slope/base of slope channel deposits. Structurally, the presence of an ENE-WSW fault which separates the southern wells from the northern wells was also revealed. Abnormal stratigraphy was also found in Northern WD-8 where the Eocene Navet formation was encountered below the Late Miocene Lower Cruse formation. Two (2) wells in the northern portion of the block found the Navet formation resistive with only one well testing this reservoir. This then presents a new under exploited target reservoir with the block. Mapping of the Navet Formation indicates that this reservoir trends in a WSW-ENE direction. This updated geological model for the WD-8 block resulted in six infill developmental wells being identified to further exploit the remaining reserves within the Lower Cruse and Navet Formations in the WD-8 block.

Downhole Monitoring of Fractures in a Waterflood Development – Part 1

2021 ◽  
Author(s):  
Abhinandan Kohli ◽  
Oscar Kelder ◽  
Maxim Volkov ◽  
Rita-Michel Greiss ◽  
Natalia Kudriavaya ◽  
...  
Keyword(s):  
High Pressures ◽  
Integrated Approach ◽  
Fracture Network ◽  
Acoustic Monitoring ◽  
Well Performance ◽  
Regulatory Requirements ◽  
Injection Wells ◽  
Significant Saving ◽  
Initiation Point ◽  
Seal Integrity

Abstract When an oilfield is exploited by simply producing oil and gas from a number of wells, the reservoir pressure in many circumstances drops quicker than normal impacting the production rates (Koning, 1988) and well performance. To maintain the pressures in the oil producing formations, waterflooding enhancement method is implemented by the Operators. This is achieved by drilling injection wells or converting the oil producing wells into injectors. The injection wells are located at carefully selected points in the oilfield so that the water displaces as much oil as possible to the production wells before the water starts to break through. A significant saving in an oilfield development can be obtained by reducing the actual number of injecting wells and increasing each of the injector wells' capacity for injection. Balancing the injection and produced volumes often involves injecting at high pressures leading to the fracture of the reservoir rocks along a plane intersecting the wellbore. This happens when injection pressure overcomes the rock stress and its tensile strength, thereby creating an induced fracture network. With continuous injection, these fractures start propagating into the reservoir and may reach the reservoir caprock. Continuing to inject further in such a fracture system may breach the top seal integrity of the caprock leading to uncontrolled out of zone injection. The study of evaluation of downhole fracture monitoring is divided into two parts. In this paper a downhole verification approach to identify the fracture initiation point(s) is the focus. It describes the planning, execution and interpretation of the downhole data. This includes spectral acoustic monitoring and modelling of the temperature responses to quantify the injectivity profile. In paper (Kohli, Kelder, Volkov, Castelijns, & van Eijs, 2021), the direct business impact and regulatory requirements are discussed by further integration of acoustic monitoring and temperature modeling data with detailed results from downhole measurements of fracture dimensions by means of pressure fall off tests. Combined, both studies form the integrated approach that the Operator took to meet the regulatory requirements proving that the fracture network propagation remains within the reservoir and that the top seal integrity is maintained.

Field-Proven Well Surveillance Techniques Designed for an Early Well Scaling Diagnosis and Timely Well Performance Reinstatement: Case Study from the Kashagan Field

2021 ◽  
Author(s):  
Aktoty Kauzhanova ◽  
Lyudmila Te ◽  
John Reedy ◽  
Thaddeus Ivbade Ehighebolo ◽  
Mirko Bastiaan Heinerth ◽  
...  
Keyword(s):  
Surveillance Program ◽  
Successful Implementation ◽  
Well Testing ◽  
Well Performance ◽  
Root Cause ◽  
Operating Environments ◽  
Initial Stage ◽  
Calcite Deposition ◽  
Time Required

Abstract Some wells in the Kashagan field did not perform as well as expected. Despite producing virtually no water, calcite deposition was found to be the root cause of the problem. A comprehensive well surveillance program, which was proven to be very efficient for an early scaling diagnosis, was developed by the operator, North Caspian Operating Company (hereafter NCOC). As a result, well scaling is currently well managed and prevented from reoccurring. The objective of this paper is to share an early experience with well scaling in the Kashagan field, as well as to describe the developed set of well surveillance techniques. The aim of the various well surveillance techniques discussed in this paper is to improve an Operator's ability to identify the very first signs of scale accumulation. This, in its turn, enables to introduce timely adjustments to the well operating envelope and to schedule a scale remediation / inhibition treatment with the intention to prevent any potential scaling initiation from further development. The approach is quite extensive and incorporates continuous BHP/BHT monitoring, routine well testing, PTA analysis, and fluid/water sampling. Developed approach experienced multiple revisions and modifications. Further optimization continues, however, the described well surveillance techniques represent the latest Operator's vision on the most efficient way for well scaling monitoring and identification. In the Kashagan field, BHP/BHT readings have proved to be the most direct and instantaneous indication of any early signs of potential deterioration in well performance (qualitative analysis) while well testing and PTAs are considered as the most essential techniques in confirming and quantifying scaling severity (quantitative analysis). It is important to mention that BHT increase is explained by Joule-Thomson heating effect being specific for the Kashagan fluid (happening during increased pressure drawdown). This, in turns, enables to predict future well performance, design well operating envelop accordingly and, most importantly, develop a yearly schedule for proactive well treatments with SI. In conclusion, it shall be highlighted that discussed complex of well surveillance techniques has been concluded to be very efficient and reliable tool in identifying any scaling tendencies at its initial stage. Due to successful implementation of this approach in the Kashagan field, scale development is now well-managed and kept under control. To mention, that utilization of well surveillance techniques and methods outlined in this paper may reduce the time required to identify and ultimately mitigate well scale accumulation in any active assets with similar operating environments.

Field Implementation of In-Depth Conformance Gel Treatment Prior to Starting an ASP Flooding Pilot

2021 ◽  
Author(s):  
Mohammed T. Al-Murayri ◽  
Abrahim Hassan ◽  
Naser Alajmi ◽  
Jimmy Nesbit ◽  
Bastien Thery ◽  
...  
Keyword(s):  
Polymer Solution ◽  
Injection Pressure ◽  
High Viscosity ◽  
Production Well ◽  
Sweep Efficiency ◽  
Injection Wells ◽  
Appreciable Change ◽  
Well Pattern ◽  
Gel Treatment ◽  
Viscosity Polymer

Abstract Mature carbonate reservoirs under waterflood in Kuwait suffer from relatively low oil recovery due to poor volumetric sweep efficiency, both areal, vertically, and microscopically. An Alkaline-Surfactant-Polymer (ASP) pilot using a regular five-spot well pattern is in progress targeting the Sabriyah Mauddud (SAMA) reservoir in pursuit of reserves growth and production sustainability. SAMA suffers from reservoir heterogeneities mainly associated with permeability contrast which may be improved with a conformance treatment to de-risk pre-mature breakthrough of water and chemical EOR agents in preparation for subsequent ASP injection and to improve reservoir contact by the injected fluids. Each of the four injection wells in the SAMA ASP pilot was treated with a chemical conformance improvement formulation. A high viscosity polymer solution (HVPS) of 200 cP was injected prior to a gelant formulation consisting of P300 polymer and X1050 crosslinker. After a shut-in period, wells were then returned to water injection. Injection of high viscosity polymer solution (HVPS) at the four injection wells showed no increase in injection pressure and occurred higher than expected injection rates. Early breakthrough of polymer was observed at SA-0561 production well from three of the four injection wells. No appreciable change in oil cut was observed. HVPS did not improve volumetric sweep efficiency based on the injection and production data. Gel treatment to improve the volumetric conformance of the four injection wells resulted in all the injection wells showing increased of injection pressure from approximately 3000 psi to 3600 psi while injecting at a constant rate of approximately 2,000 bb/day/well. Injection profiles from each of the injection well ILTs showed increased injection into lower-capacity zones and decreased injection into high-capacity zones. Inter-well tracer testing showed delayed tracer breakthrough at the center SA-0561 production well from each of the four injection wells after gel placement. SA-0561 produced average daily produced temperature increased from approximately 40°C to over 50°C. SA-0561 oil cuts increased up to almost 12% from negligible oil sheen prior to gel treatments. Gel treatment improved volumetric sweep efficiency in the SAMA SAP pilot area.

INTEGRATED TECHNOLOGY OF BROWN FIELD STUDY TO INCREASE PRODUCTION AND OIL RECOVERY

2020 ◽  
pp. 61-66
Author(s):  
I.A. Zhdanov ◽  
E.S. Pakhomov ◽  
A.M. Aslanyan ◽  
R.R. Farakhova ◽  
D.N. Gulyaev ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Field Studies ◽  
Development Planning ◽  
Reservoir Modeling ◽  
Integrated Analysis ◽  
Well Testing ◽  
Reservoir Model ◽  
Scenario Development ◽  
Sweep Efficiency ◽  
High Level

Paper presents the results of integrated analysis of historically available data and additional field studies at the brown field. The results of the analysis increase the reliability of the geological and hydrodynamic reservoir model, current recovery and identification of areas, which are most promising for production enhancement operations for production increase and recovery increase. The integrated analysis of available data includes such tools as prelaminar data analysis of production and pressure changes (Prime) for high level reserves localization, multiwell retrospective testing (MRT) and pulsecode testing (PCT) for evaluation of reservoir geology, sweep efficiency and current reservoir saturation, geological and hydrodynamic reservoir modeling including petrofacies and model adaptation to the production logging, MRT, PCT and well-testing findings, multi-scenario development planning (MSDP) for the most economically profitable operations recommendation and supervision of their implementation. MSDP is based on the usage by several teams of reservoir engineers web-facility PloyPlan, which automatically translates the field activities (like drilling, workover, conversion, surveillance, etc.) into the model runs and reverts back with production and surveillance results and financial statements, based on which it is easy to choose the most profitable field operations. Up to today Prime analysis, field studies and reservoir model calibration on their results are finished.

Natural Seismicity in and around the Rome Trough, Eastern Kentucky, from a Temporary Seismic Network

2020 ◽  
Vol 91 (3) ◽  
pp. 1831-1845 ◽  
Author(s):  
N. Seth Carpenter ◽  
Andrew S. Holcomb ◽  
Edward W. Woolery ◽  
Zhenming Wang ◽  
John B. Hickman ◽  
...  
Keyword(s):  
New York ◽  
Oil And Gas ◽  
Seismic Network ◽  
Earthquake Activity ◽  
Seismic Zone ◽  
Injection Wells ◽  
Eastern Kentucky ◽  
The North ◽  
Horizontal Compressive Stress ◽  
Natural Seismicity

Abstract The Rome trough is a northeast-trending graben system extending from eastern Kentucky northeastward across West Virginia and Pennsylvania into southern New York. The oil and gas potential of a formation deep in the trough, the Rogersville shale, which is ∼1  km above Precambrian basement, is being tested in eastern Kentucky. Because induced seismicity can occur from fracking formations in close proximity to basement, a temporary seismic network was deployed along the trend of the Rome trough from June 2015 through May 2019 to characterize natural seismicity. Using empirical noise models and theoretical Brune sources, minimum detectable magnitudes, Mmin, were estimated in the study area. The temporary stations reduced Mmin by an estimated 0.3–0.8 magnitude units in the vicinity of wastewater-injection wells and deep oil and gas wells testing the Rogersville shale. The first 3 yr of seismicity detected and located in the study area has been compiled. Consistent with the long-term seismicity patterns in the Advanced National Seismic System Comprehensive Catalog, very few earthquakes occurred in the crust beneath the Rome trough—only three events were recorded—where the temporary network was most sensitive. None of these events appear to have been associated with Rogersville shale oil and gas test wells. Outside of the trough boundary faults, earthquakes are diffusely distributed in zones extending into southern Ohio to the north, and into the eastern Tennessee seismic zone to the south. The orientations of P axes from the seven first-motion focal mechanisms determined in this study are nearly parallel with both the trend of the Rome trough and with the orientation of maximum horizontal compressive stress in the region. This apparent alignment between the regional stress field and the strikes of faults in the trough at seismogenic depths may explain the relative lack of earthquake activity in the trough compared with the surrounding crust to the north and south.

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