An Innovative Well Intervention for Production Optimization in Depleted Gas Reservoirs Thru Coil Tubing

2020 ◽  
Author(s):  
D. Wijayanto
Keyword(s):  
Cost Effective ◽  
Production Optimization ◽  
Well Test ◽  
Gas Reservoirs ◽  
Well Productivity ◽  
Optimum Result ◽  
Coiled Tubing ◽  
Well Stimulation ◽  
Depleted Gas Reservoirs ◽  
Head Pressure

Coil Tubing operated in NL wells, South Sumatera because of depleted reservoir pressure. Objective of coiled tubing operation are sand clean-out and acid stimulation to restore well productivity. Previously in NL wells has used a snubbing unit in intervention well but the results were not good. Formation damage was suspected due to packer fluid introduced into formation during snubbing job. Production optimization in brownfield is required to extend the economic producing life of the field using cost-effective and low-risk technologies. Well stimulation is generally proposed to enhance well productivity by acidizing treatment. Acidizing in sandstone applied in Medco to improve well productivity. But loss problem got in conventional rig operation during killing well in low reservoir gas well. Coiled tubing (CTU) can solve the problem and can operate without killing the well. Recipe acid HCl 15% get optimum in solubility test around 28-31%. Coiled Tubing Operation applied pulsonic method to get optimum result. After CTU Job (clean sand out & acidizing), well productivity improved refer to gas rate and flowing well-head pressure (FWHP) monitoring. Initial gas gain was more than 2.5 MMSCFD from 2 wells (NL-X1 and NL-X2) that were treated with CTU acid stimulation. Gas cumulative is around 176 MMSCF (3 months production) and still counting. Further evaluation will be conducted by performing complete well test (transient analysis). As conclusion, coiled tubing operation has proven to become effective well intervention in depleted gas wells to improve production optimization and open the opportunity to unlock potential in other wells which experiencing similar challenges. This paper shares case study, how to develop acid stimulation strategy covering guideline in acid selection and deploy acid without killing well in South Sumatra.

No Need for Radio Active Tracer When Mother Nature Helps Detecting the Effective Hydraulic Fracture Height

2022 ◽  
Author(s):  
Rinat Lukmanov ◽  
Said Jabri ◽  
Ehab Ibrahim
Keyword(s):  
Hydraulic Fracture ◽  
Natural Radioactivity ◽  
Gamma Ray ◽  
Fracture Propagation ◽  
Radioactive Isotopes ◽  
Main Element ◽  
Tight Gas ◽  
Well Test ◽  
Gas Reservoirs ◽  
Fracture Height

Abstract The tight gas reservoirs of Haima Supergroup provide the majority of gas production in the Sultanate of Oman. The paper discusses a possibility of using the anomalies from natural radioactivity to evaluate the fracture height for complex tight gas in mature fields of Oman. The standard industry practice is adding radioactive isotopes to the proppant. Spectral Gamma Ray log is used to determine near wellbore traced proppant placement. Spectral Noise log in combination with Production logs helps to identify the active fractures contributing to production. These methods complement each other, but they are obviously associated with costs. Hence, majority of wells are fracced without tracers or any other fracture height diagnostics. However, in several brown fields, an alternative approach to identify fracture height has been developed which provides fit-for-purpose results. It is based on the analysis of naturally occurring radioactive minerals (NORM) precipitation. The anomalies were observed in the many gas reservoirs even in cases when tracers were not used. At certain conditions, these anomalies can be used to characterize fracture propagation and optimize future wells hydraulic Fracture design. A high number of PLTs and well test information were analyzed. Since tight formations normally don't produce without fracturing, radioactive anomalies flag the contributing intervals and hence fracture propagation. The main element of analysis procedure is related to that fact that if no tracers applied, the discrepancy between normalized Open Hole Gamma Ray and Gamma Ray taken during PLT after 6-12 months of production can be used instead to establish fracture height. This method cannot be applied for immediate interpretation of fracture propagation because time is required to precipitate NORM and using the anomalies concept. The advantage of this method is that it can be used in some fields to estimate the frac effectiveness of wells without artificial tracers. It is normally assumed that the Natural radioactivity anomalies appear mainly due to co-production of the formation water. However, in the fields of interest the anomalies appear in wells producing only gas and condensate. This observation provides an opportunity for active fracture height determination at minimum cost.

Asphaltene Mitigation in Giant Carbonate Abu Dhabi Fields: A Techno-Economic Comparison Between Continuous Injection and Formation Squeeze

2021 ◽  
Author(s):  
Mark Grutters ◽  
Sameer Punnapala ◽  
Dalia Salem Abdallah ◽  
Zaharia Cristea ◽  
Hossam El Din Mohamed El Nagger ◽  
...  
Keyword(s):  
Cost Effective ◽  
Threshold Value ◽  
Field Trials ◽  
Mitigation Strategy ◽  
Operating Conditions ◽  
Mitigation Strategies ◽  
Production Cycle ◽  
Asphaltene Precipitation ◽  
Coiled Tubing ◽  
Continuous Injection

Abstract Asphaltene deposition is a serious and re-occurring flow assurance problem in several of the ADNOC onshore oilfields. Fluids are intrinsically unstable with respect to asphaltene precipitation, and operating conditions are such that severe deposition occurs in the wellbore. Wells in ADNOC are generally not equipped with downhole chemical injection lines for continuous inhibition, and protection of the wells require frequent shut-in and intervention by wireline and coiled tubing to inspect and clean up. Since some of the mature fields are under EOR recovery strategies, like miscible hydrocarbon WAG and CO2 flood, which exacerbates the asphaltene precipitation and deposition problems, a more robust mitigation strategy is required. In this paper the results of two different mitigation strategies will be discussed; continuous injection of asphaltene inhibitor via a capillary line in the tubular and asphaltene inhibitor formation squeeze. Three asphaltene inhibitors from different suppliers were pre-qualified and selected for field trial. Each inhibitor was selected for a formation squeeze in both one horizontal and one vertical well, and one of the inhibitors was applied via thru-tubing capillary string. The field trials showed that continuous injection in remote wells with no real-time surveillance options (e.g. gauges, flow meters) is technically challenging. The continuous injection trial via the capillary string was stopped due to technical challenges. From the six formation squeezes four were confirmed to be effective. Three out of fours squeezes significantly extended the production cycle, from approximately 1.4 to 6 times the normal uninhibited flow period. The most successful squeezes were in the vertical wells. The results of the trial were used to model the economic benefit of formation squeeze, compared to a ‘do-nothing’ approach where the wells are subject to shut-in and cleanup once the production rates drop below a threshold value. The model clearly indicates that the squeezes applied in ADNOC Onshore are only cost-effective if it extends the normal flow period by approximately three times. However, a net gain can be achieved already if the formation squeeze extends the flow cycle by 15 to 20%, due to reduction of shut-in days required for intervention. Therefore, the results in this paper illustrate that an asphaltene inhibitor formation squeeze can be an attractive mitigation strategy, both technically and economically.

Production Optimization in Mature Field Through Scenario Prediction Using a Representative Network Model: A Rapid Solution Without Well Intervention

2021 ◽  
Author(s):  
Edwin Lawrence ◽  
Marie Bjoerdal Loevereide ◽  
Sanggeetha Kalidas ◽  
Ngoc Le Le ◽  
Sarjono Tasi Antoneus ◽  
...  
Keyword(s):  
Network Model ◽  
Test Data ◽  
Production Optimization ◽  
Operating Conditions ◽  
Fine Tuning ◽  
Well Test ◽  
Production Rates ◽  
Mature Field ◽  
Gas Lift ◽  
Field Production

Abstract As part of the production optimization exercise in J field, an initiative has been taken to enhance the field production target without well intervention. J field is a mature field; the wells are mostly gas lifted, and currently it is in production decline mode. As part of this optimization exercise, a network model with multiple platforms was updated with the surface systems (separator, compressors, pumps, FPSO) and pipelines in place to understand the actual pressure drop across the system. Modelling and calibration of the well and network model was done for the entire field, and the calibrated model was used for the production optimization exercise. A representative model updated with the current operating conditions is the key for the field production and asset management. In this exercise, a multiphase flow simulator for wells and pipelines has been utilized. A total of ∼50 wells (inclusive of idle wells) has been included in the network model. Basically, the exercise started by updating the single-well model using latest well test data. During the calibration at well level, several steps were taken, such as evaluation of historical production, reservoir pressure, and well intervention. This will provide a better idea on the fine-tuning parameters. Upon completion of calibrating well models, the next level was calibration of network model at the platform level by matching against the platform operating conditions (platform production rates, separator/pipeline pressure). The last stage was performing field network model calibration to match the overall field performance. During the platform stage calibration, some parameters such as pipeline ID, horizontal flow correlation, friction factor, and holdup factor were fine-tuned to match the platform level operating conditions. Most of the wells in J field have been calibrated by meeting the success criterion, which is within +/-5% for the production rates. However, there were some challenges in matching several wells due to well test data validity especially wells located on remote platform where there is no dedicated test separator as well as the impact of gas breakthrough, which may interfere to performance of wells. These wells were decided to be retested in the following month. As for the platform level matching, five platforms were matched within +/-10% against the reported production rates. During the evaluation, it was observed there were some uncertainties in the reported water and gas rates (platform level vs. well test data). This is something that can be looked into for a better measurement in the future. By this observation, it was suggested to select Platform 1 with the most reliable test data as well as the platform rate for the optimization process and qualifying for the field trial. Nevertheless, with the representative network model, two scenarios, reducing separator pressure at platform level and gas lift optimization by an optimal gas lift rate allocation, were performed. The model predicts that a separator pressure reduction of 30 psi in Platform 1 has a potential gain of ∼300 BOPD, which is aligned with the field results. Apart from that, there was also a potential savings in gas by utilizing the predicted allocated gas lift injection rate.

Increasing Operational Efficiency in Extended Reach, Offshore Wells – A Case Story from Middle East

2016 ◽  
Author(s):  
Anthony MacLeod
Keyword(s):  
System Integration ◽  
Cost Effective ◽  
Lessons Learned ◽  
Operating Efficiency ◽  
Coiled Tubing ◽  
Electric Line ◽  
Release Device ◽  
Integration Test ◽  
Closed Position ◽  
Shifting Profile

ABSTRACT Objective A case story from ME will be presented covering an extreme extended reach, offshore well. Any increase to operating efficiency can save time and increase production. In this case story two SSD's were opened in a single run on e-line, an outstanding achievement due to the ID restrictions and extended reach of the well. The paper will discuss the planning, the operation, the achievements and the lessons learned. Methods, Procedures, Process This well was recently worked over, retrieval and new installation of upper and lower completion. Due to the well going on total losses during the workover, a closed system was deployed to enable the operator to set the hydraulic packers. The packer is utilized for isolation between two zones, with each zone having two SSD's in which one SSD per zone was required to be opened to allow access to the formation. From day one of planning the primary solution for this intervention was an electric over hydraulic toolstring made up of five tools, a 218 electric release device, 218 CCL for correlation, a 218 tractor for conveyance, a 218 stroker for the mechanical manipulation and a 218 key to address the shifting profile in the SSD (toolstring). A slimhole toolstring was required due to the packer ID of 2.81" The operator was using the service provider for other interventions on this workover campaign and decided to challenge them with opening two SSD's in one run while not shifting the adjacent SSD's. The challenging underlying economics of the industry today has created a powerful driver for operators to find more efficient, cost effective and safer intervention methodologies. The operation covered in this case provided just such improvements to the client: by utilizing electric line intervention tools the operator negated the requirement for a large footprint coiled tubing intervention. Results, Observations, Conclusions A System Integration Test (SIT) was completed onshore prior to mobilization, where multiple shifts were successfully executed on a 90° deviated pipe using a single set of shifting key pads. Test results were then repeated offshore, completing two interventions in a single run. The SSD's were successfully opened at ~12,000 ft MDRT and ~8,000 ft MDRT, respectively while leaving the two adjacent SSD's in the closed position. Results, client objective was 100% achieved using only electric line, enabling the client to move forward with similar well designs having the confidence that a safe, reliable electric line solution is locally available. Additional results include reduced HSE risks as the e-line approach eliminated the use of a heavier CTU. Further contributing to the HSE benefits on this operation, only 6 persons were needed on site and no heavy lifts were required. The paper will also cover some lessons learned as debris in the profile and tubing caused some challenges. Novel/Additive Information This operation shows how the industry is constantly trying to improve on existing methods in order to be more efficient, safe and cost effective.

Short-Term Production Optimization Under Water-Cut Uncertainty

SPE Journal ◽  
2020 ◽  
pp. 1-21
Author(s):  
Gabriela Chaves ◽  
Danielle Monteiro ◽  
Maria Clara Duque ◽  
Virgílio Ferreira Filho ◽  
Juliana Baioco ◽  
...  
Keyword(s):  
Latin Hypercube Sampling ◽  
Stochastic Approach ◽  
Injection Rate ◽  
Production Optimization ◽  
Support Vector ◽  
Well Test ◽  
Short Term ◽  
Stochastic Solution ◽  
Water Cut ◽  
Gas Lift

Summary Short-term production optimization is an essential activity in the oil/gasfield-development process because it allows for the maximization of field production by finding the optimal operational point. In the fields that use gas lift as an artificial-lift method, the gas-lift optimization is a short-term problem. This paper presents a stochastic approach to include uncertainties from production parameters in gas-lift optimization, called the uncertain-gas-lift-optimization problem (UGLOP). Uncertainties from production variables are originated from the measurement process and the intrinsic stochastic phenomena of the production activity. The production variables usually obtained from production tests play an important role in the optimization process because they are used to update reservoir and well models. To include the uncertainties, the strategy involves representing the well-test data using nonlinear regression [support-vector regression (SVR)] and using the Latin-hypercube-sampling (LHS) method. The optimization gives a stochastic solution for the operational point. In the solved problem, this operational point is composed of the individual wells’ gas-lift-injection rate, choke opening, and well/separator routing. The value of the stochastic solution is computed to evaluate the benefit of solving the stochastic problem over the deterministic. The developed methodology is applied to wells of a Brazilian field considering uncertainty in water-cut (WC) values. As a result, an up-to-4.5% gain in oil production is observed using this approach.

scholarly journals Earthquakes and depleted gas reservoirs: which comes first?

2015 ◽  
Vol 15 (10) ◽  
pp. 2201-2208 ◽  
Author(s):  
M. Mucciarelli ◽  
F. Donda ◽  
G. Valensise
Keyword(s):  
Statistical Tests ◽  
Northern Italy ◽  
Relative Distribution ◽  
Gas Wells ◽  
Gas Reservoirs ◽  
Earthquake Sources ◽  
Hydrocarbon Traps ◽  
Depleted Gas Reservoirs ◽  
Production History ◽  
The Impact

Abstract. While scientists are paying increasing attention to the seismicity potentially induced by hydrocarbon exploitation, so far, little is known about the reverse problem, i.e. the impact of active faulting and earthquakes on hydrocarbon reservoirs. The 20 and 29 May 2012 earthquakes in Emilia, northern Italy (Mw 6.1 and 6.0), raised concerns among the public for being possibly human-induced, but also shed light on the possible use of gas wells as a marker of the seismogenic potential of an active fold and thrust belt. We compared the location, depth and production history of 455 gas wells drilled along the Ferrara-Romagna arc, a large hydrocarbon reserve in the southeastern Po Plain (northern Italy), with the location of the inferred surface projection of the causative faults of the 2012 Emilia earthquakes and of two pre-instrumental damaging earthquakes. We found that these earthquake sources fall within a cluster of sterile wells, surrounded by productive wells at a few kilometres' distance. Since the geology of the productive and sterile areas is quite similar, we suggest that past earthquakes caused the loss of all natural gas from the potential reservoirs lying above their causative faults. To validate our hypothesis we performed two different statistical tests (binomial and Monte Carlo) on the relative distribution of productive and sterile wells, with respect to seismogenic faults. Our findings have important practical implications: (1) they may allow major seismogenic sources to be singled out within large active thrust systems; (2) they suggest that reservoirs hosted in smaller anticlines are more likely to be intact; and (3) they also suggest that in order to minimize the hazard of triggering significant earthquakes, all new gas storage facilities should use exploited reservoirs rather than sterile hydrocarbon traps or aquifers.

Sign in / Sign up

Export Citation Format

Share Document