New Completion Methodology To Improve Oil Recovery and Minimize Water Intrusion in Reservoirs Subject to Water Injection

SPE Journal ◽  
2011 ◽  
Vol 16 (03) ◽  
pp. 648-661 ◽  
Author(s):  
Leopoldo Sierra ◽  
Loyd East ◽  
M.Y.. Y. Soliman ◽  
David Kulakofsky
Keyword(s):  
Saudi Arabia ◽  
Oil Recovery ◽  
Potential Risk ◽  
Early Stage ◽  
Water Injection ◽  
Recovery Efficiency ◽  
Injection Wells ◽  
Water Intrusion ◽  
The World

Summary Implementing water injection during the early stage of a new reservoir's development is a process that is gaining popularity around the world. This is especially true in Saudi Arabia, where water injection is used both to improve oil recovery and to maintain pressure by placing short or long horizontal water-injection wells around the reservoir flanks. For cases where water-injection wells are placed in reservoir flanks, some of the producing wells are perforated transverse to the water-injection wells to improve the oil recovery around the involved areas. For this specific exploitation strategy, there is a potential risk of water channeling from the injector to the producing well toe, which, once it happens, might jeopardize recovery efficiency. For the referenced exploitation strategy, a new completion methodology is proposed that considers the placement of a fracture barrier at the toe of the producing well to delay water intrusion and improve recovery efficiency. This paper discusses the use of nonconductive barrier fractures and the benefits of the completion methodology, supported with extensive simulations for the different scenarios.

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.

scholarly journals Polymer gels for controlling water thief zones in injection wells

2012 ◽  
Vol 5 (1) ◽  
pp. 37-44 ◽  
Author(s):  
Gustavo-Adolfo Maya-Toro ◽  
Rubén-Hernán Castro-García ◽  
Zarith del Pilar Pachón-Contreras. ◽  
Jose-Francisco Zapata-Arango
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Injection Wells ◽  
Recovery Processes ◽  
Injection Water ◽  
Secondary Oil Recovery ◽  
High Concentrations ◽  
Low Efficiency ◽  
Hydrolyzed Polyacrylamide ◽  
Positive Results

Oil recovery by water injection is the most extended technology in the world for additional recovery, however, formation heterogeneity can turn it into highly inefficient and expensive by channeling injected water. This work presents a chemical option that allows controlling the channeling of important amounts of injection water in specific layers, or portions of layers, which is the main explanation for low efficiency in many secondary oil recovery processes. The core of the stages presented here is using partially hydrolyzed polyacrylamide (HPAM) cross linked with a metallic ion (Cr+3), which, at high concentrations in the injection water (5000 – 20000 ppm), generates a rigid gel in the reservoir that forces the injected water to enter into the formation through upswept zones. The use of the stages presented here is a process that involves from experimental evaluation for the specific reservoir to the field monitoring, and going through a strict control during the well intervention, being this last step an innovation for this kind of treatments. This paper presents field cases that show positive results, besides the details of design, application and monitoring.

Research of Improving Water Injection Effect by Using Active SiO2 Nano-Powder in the Low-Permeability Oilfield

2010 ◽  
Vol 92 ◽  
pp. 207-212 ◽  
Author(s):  
Ke Liang Wang ◽  
Shou Cheng Liang ◽  
Cui Cui Wang
Keyword(s):  
Oil Recovery ◽  
Pore Volume ◽  
Water Injection ◽  
Field Tests ◽  
Injection Pressure ◽  
Rock Surface ◽  
Low Permeability ◽  
Injection Wells ◽  
Decompression Rate ◽  
Nano Powder

SiO2 nano-powder is a new type of augmented injection agent, has the ability of stronger hydrophobicity and lipophilicity, and can be adsorbed on the rock surface so that it changes the rock wettability. It can expand the pore radius effectively, reduce the flow resistance of injected water in the pores, enhance water permeability, reduce injection pressure and augment injection rate. Using artificial cores which simulated geologic conditions of a certain factory of Daqing oilfield, decompression and augmented injection experiments of SiO2 nano-powder were performed after waterflooding, best injection volume of SiO2 nano-powder under the low-permeability condition was selected. It has shown that SiO2 nano-powder inverted the rock wettability from hydrophilicity to hydrophobicity. Oil recovery was further enhanced after waterflooding. With the injection pore volume increasing, the recovery and decompression rate of SiO2 nano-powder displacement increased gradually. The best injected pore volume and injection concentration is respectively 0.6PV and 0.5%, the corresponding value of EOR is 6.84% and decompression rate is 52.78%. According to the field tests, it is shown that, in the low-permeability oilfield, the augmented injection technology of SiO2 nano-powder could enhance water injectivity of injection wells and reduce injection pressure. Consequently, it is an effective method to resolve injection problems for the low-permeability oilfield.

Qualification and Application of All Electric and Topside Less Subsea Multiphase Pump Technology in Subsea Factory Mission to Minimise the Life Cycle Cost

2021 ◽  
Author(s):  
Karthik Ilangovan ◽  
Mazlan Dindi ◽  
Alexander Fuglesang ◽  
Bastiaen Van Der Rest
Keyword(s):  
Life Cycle ◽  
Oil Recovery ◽  
Life Cycle Cost ◽  
Technology Development ◽  
Water Injection ◽  
Development Project ◽  
Monitoring And Control ◽  
Field Development ◽  
Multiphase Pump ◽  
The World

Abstract In recent years, various operating companies have been working on the processes of "Simplification, Standardization, Automation, Digitalization, and Optimization in several elements". To achieve this, there are tremendous subsea technology developments going on all over the world in many areas such as; design in terms of size and weight, improvement in reliability, advanced materials, flow assurance, digital tools, real time condition monitoring and control, installation and operation. The development of Subsea technology continues to be an important part of subsea field development projects to reduce the life cycle costs, increase recovery, provide solution to long tieback problems and challenges. PETRONAS ("the Company") is pursuing an Upstream Life Cycle Cost (CAPEX/OPEX) reduction approach under the Facilities of Future (FOF) program and mission called "Subsea Factory". The FOF target is to reduce Upstream life cycle cost by 40% starting from 2025 and Subsea Factory is one of the enablers to contribute to the reduction. There are four primary technologies focused on Subsea Factory: Subsea Separation, Subsea Multiphase Pump, Water Injection and Subsea Storage. The Subsea Multiphase Pump is one of the prioritized technologies for Subsea Factory to contribute to a 40% reduction. Subsea multiphase pump technology has great potential to reduce the CAPEX/OPEX and increase oil recovery, but due to the high equipment cost, huge topside space requirement, reliability and operating issues become very challenging and limit its application to operating companies. The Company collaborates with FASTsubsea AS on a Joint Industry Project to develop and qualify "the World first All Electric & Topside-less Subsea Multiphase Pump Technology". The uniqueness about this technology compared to commonly installed subsea pump is that it requires much less topside space as there is no need for variable speed drives or barrier fluid hydraulic power units. This paper describes the qualification and application of All-electric & Topside-less subsea multiphase pump technology in the Company - Subsea Factory mission, including: pain point with conventional subsea multiphase pumpthe Joint Industrial Project initiative with respect to technology development to pilot test to maturityimplementation of this technology and value creation in upcoming field development projectthe case study and potential of this technology for the Company future field development project

The Triangle "U" Sussex Unit - A Case History Comparing Two Chemical Enhanced Waterflood Methods

1998 ◽  
Vol 1 (06) ◽  
pp. 545-550 ◽  
Author(s):  
J.E. Smith ◽  
Dan Larsen
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Rocky Mountain ◽  
Water Source ◽  
Cationic Polymer ◽  
Injection Wells ◽  
Recovery Method ◽  
Secondary Recovery ◽  
Permeable Rock

Summary The Triangle "U" unit is located in Campbell County, Wyoming, in the Powder River basin. The field produces mainly from the Sussex A sandstone, with completions and limited production from the Sussex B. The flood recovered 12.8% original oil in place (OOIP) on primary before the waterflood, which began in March 1981. The Sussex A is relatively tight, with an average permeability of 15 md and porosity of 13.5%. The rock contains swelling and migrating clays, and the initial injection water source was fresh, leading to concerns about long-term injectivity. To stabilize clays, two different processes were applied. Earlier injection wells were treated with a combination of potassium chloride (KCl) and cationic polymer. Later injection wells were treated with potassium hydroxide (KOH). A recent comparison of long-term performance of the two groups of injection wells shows that the wells treated with KOH injected 476,437 bbls/porosity-ft more water than the wells treated with cationic polymer, in 1.4 years less time. This is an 83% increase in cumulative water injection. After KOH, all injection wells were put on a low concentration of imbibition agent to maximize in-depth penetration of water into low permeable rock. Cumulative oil recovery through March 1997 is 36.4% OOIP, compared to the original waterflood projection of 26.6% OOIP. A total of 37.7% pore volume (PV) water has been injected, and the water/oil ratio (WOR) is currently 0.71, for a fairly efficient flood in this tight, dirty sandstone. Introduction The Triangle "U" unit produced 12.8% OOIP on primary before initiation of a waterflood. Several methods of secondary recovery were considered for this reservoir. Gas injection was not feasible because of limited supplies, and micellar injection was too expensive and risky. Waterflood susceptibility testing in cores showed favorable displacement of oil by water, making this the most appropriate secondary recovery method. The waterflood was projected to recover an additional 13.8% OOIP. Polymer flooding was not considered, because the mobility ratio was favorable and the reservoir was relatively tight, with an average permeability of 15 md. There were two basic challenges to waterflooding. First, there was concern that clays would limit injectivity over time. Also, the rock exhibited a permeability variation of 0.65, which could lead to bypassing of recoverable oil as water tended to establish channels through more permeable rock. Clays can exacerbate channeling. SPE 53007 was revised for publication from paper SPE 39937, first presented at the 1998 SPE Rocky Mountain Regional/Low Permeability Reservoirs Symposium, Denver, Colorado, 5-8 April.

Evaluation of Acid Treatment Results for Water-Injection Wells in Saudi Arabia

2006 ◽  
Author(s):  
Mesaad Samer Al-Harbi ◽  
Abdullah M. Al-Dhafeeri ◽  
Yousef Ahmed Al-Rufaie ◽  
Safwat Korani Mohammed
Keyword(s):  
Saudi Arabia ◽  
Acid Treatment ◽  
Water Injection ◽  
Treatment Results ◽  
Injection Wells

Lessons Learned From Applications of a New Organic-Oil-Recovery Method That Activates Resident Microbes

2012 ◽  
Vol 15 (06) ◽  
pp. 688-694 ◽  
Author(s):  
R.L.. L. Zahner ◽  
S.J.. J. Tapper ◽  
B.W.G.. W.G. Marcotte ◽  
B.R.. R. Govreau
Keyword(s):  
Oil Recovery ◽  
Microbial Growth ◽  
Water Injection ◽  
The United States ◽  
Lessons Learned ◽  
Injection Wells ◽  
Recovery Method ◽  
Scientific Analysis ◽  
Wide Range

Summary Using a breakthrough process, which does not require microbes to be injected, more than 100 microbial enhanced-oil-recovery (MEOR) treatments were conducted from 2007 to the end of 2010 in oil-producing and water-injection wells in the United States and Canada. On average, these treatments increased oil production by 122%, with an 89% success rate. This paper reviews the MEOR process, reviews the results of the first 100+ treatments, and shares what has been learned from this work. Observations and conclusions include the following: Screening reservoirs is critical to success. Identifying reservoirs where appropriate microbes are present and oil is movable is the key. MEOR can be applied to a wide range of oil gravities. MEOR has been applied successfully to reservoirs with oil gravity as high as 41° API and as low as 16° API. When microbial growth is appropriately controlled, reservoir plugging or formation damage is no longer a risk. Microbes reside in extreme conditions and can be manipulated to perform valuable in-situ "work." MEOR has been applied successfully at reservoir temperatures as high as 200°F and salinities as high as 140,000 ppm total dissolved solids (TDS). MEOR can be applied successfully in dual-porosity reservoirs. A side benefit of applying MEOR is that it can reduce reservoir souring. An oil response is not always observed when treating producing wells. MEOR can be applied to many more reservoirs than thought originallys with little downside risk. This review of more than 100 MEOR well treatments expands the types of reservoirs in which MEOR can be applied successfully. Low-risk and economically attractive treatments can be accomplished when appropriate scientific analysis and laboratory screening are performed before treatments.

scholarly journals Deep Learning and Holt-Trend Algorithms for predicting COVID-19 pandemic

2020 ◽  
Author(s):  
Theyazn H.H Aldhyani ◽  
Melfi Alrasheed ◽  
Ahmed Abdullah Alqarni ◽  
Mohammed Y. Alzahrani ◽  
Ahmed H. Alahmadi
Keyword(s):  
Saudi Arabia ◽  
Deep Learning ◽  
Short Term Memory ◽  
Learning Algorithm ◽  
Early Stage ◽  
World Health ◽  
Time Data ◽  
Empirical Results ◽  
The World ◽  
Death Cases

AbstractAccording to WHO, more than one million individuals are infected with COVID-19, and around 20000 people have died because of this infectious disease around the world. In addition, COVID-19 epidemic poses serious public health threat to the world where people with little or no pre-existing human immunity can be more vulnerable to the effects of the effects of the coronavirus. Thus, developing surveillance systems for predicting COVID-19 pandemic in an early stage saves millions of lives. In this study, the deep learning algorithm and Holt-trend model is proposed to predict coronavirus. The Long-Short Term Memory (LSTM) algorithm and Holt-trend were applied to predict confirmed numbers and death cases. The real time data have been collected from the World Health Organization (WHO). In the proposed research, we have considered three countries to test the proposed model namely Saudi Arabia, Spain and Italy. The results suggest that the LSTM models showed better performance in predicting the cases of coronavirus patients. Standard measure performance MSE, RMSE, Mean error and correlation are employed to estimate the results of the proposed models. The empirical results of the LSTM by using correlation metric are 99.94%, 99.94% and 99.91 to predict number of confirmed cases on COVID-19 in three countries. Regarding the prediction results of LSTM model to predict the number of death on COVID-19 are 99.86%, 98.876% and 99.16 with respect to the Saudi Arabia, Italy and Spain respectively. Similarly the experimented results of Holt-Trend to predict the number of confirmed cases on COVID-19 by using correlation metrics are 99.06%, 99.96% and 99.94, whereas the results of Holt-Trend to predict the number of death cases are 99.80%, 99.96 and 99.94 with respect to the Saudi Arabia, Italy and Spain respectively. The empirical results indicate the efficient performance of the presented model in predicting the number of confirmed and death cases of COVID-19 in these countries. Such findings provide better insights about the future of COVID-19 in general. The results were obtained by applying the time series models which needs to be considered for the sake of saving the lives of many people.

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