Novel Sand Conglomeration Treatment Prevents Sand Production and Enhances Well Productivity: Offshore Caspian Case Study

Many oil producing wells, globally, experience sand production problems when reservoir rock consists of unconsolidated sand. Several wells in the Dzheitune oil field are experiencing a similar challenge. Production of formation fines and sand has caused accumulation of fill and wellbore equipment failures and has necessitated periodical and costly coiled tubing-assisted wellbore cleanout operations. A novel chemical treatment tested in the oil field to tackle the challenge led to positive results. A well with a relatively short target perforation interval was selected as a candidate for the trial sand conglomeration treatment to avoid any uncertainties related to zone coverage. Pre-requisite sand agglomeration and chemical-crude oil compatibility laboratory studies were carried out to optimize the main system and preflush fluid formulations. Once the laboratory testing was complete, a step-rate test was performed to determine the maximum injection rate below formation fracturing pressure. The chemical systems were prepared using standard blending equipment. The preflush fluid was injected to prepare the treated zone. The main fluid was then injected into the reservoir in several cycles at matrix rate by a bullheading process. Upon completion of the treatment, the well was shut in for several days for optimal agglomeration (conglomeration) before the well was slowly put on production. A long-term increase in the productivity index and sand-free flow rate with no damage to the wellbore or the reservoir were observed. The technology demonstrated its efficiency in preventing and controlling sand production; avoiding frequent, time-consuming, costly wellbore cleanout operations; and producing hydrocarbons at reduced drawdown pressure.

Bringing the Best of Sampling While Drilling in Highly Deviated S-Profile Wells: Case Studies from a Brown Field, Sabah, Offshore Malaysia

Sampling While Drilling has undergone significant changes since its advent early this decade. The continuum of applications has primarily been due to the ability to access highly deviated wellbores, to collect PVT quality and volume of formation fluids. The increased confidence is also a result of numerous applications with varied time-on-wall without ever being stuck. This paper demonstrates the contribution of this technology for reservoir fluid mapping that proved critical to update the resource assessment in a brown field through three infill wells that were a step-out to drill unpenetrated blocks and confirm their isolation from the main block of the field. As a part of the delineation plan, the objective was to confirm the current pressure regime and reservoir fluid type when drilling the S-profile appraisal wells with 75 degrees inclination. Certain sand layers were prone to sanding as evidenced from the field's long production history. Due to the proven record of this technology in such challenges, locally and globally, pipe-conveyed wireline was ruled out. During pre-job planning, there were concerns about sanding, plugging and time-on-wall and stuck tools. Empirical modeling was performed to provide realistic estimates to secure representative fluid samples. The large surface area pad was selected, due to its suitability in highly permeable yet unconsolidated formations. For the first well operation, the cleanup for confirming formation oil began with a cautious approach considering possible sanding. An insurance sample was collected after three hours. For the next target, drawing on the results of the first sampling, the pump rate was increased early in time, and a sample was collected in half the time. Similar steps were followed for the remaining two wells, where water samples were collected. Oil, water, and gas gradients were calculated. Lessons learnt and inputs from Geomechanics were used in aligning the probe face and reference to the critical drawdown pressure (CDP). A total of 4,821 feet (1,469 meters) was drilled. 58 pressures were acquired, with six formation fluid samples and five cleanup cycles for fluid identification purpose. The pad seal efficiency was 95%. The data provided useful insights into the current pressure regime and fault connectivity, enabling timely decisions for well completion. The sampling while drilling deployment was successful in the highly deviated S-profile wells and unconsolidated sand, with no nonproductive time. Because of the continuous circulation, no event of pipe sticking occurred, thereby increasing the confidence, especially in the drilling teams. The sampling while drilling operations were subsequent, due to batch drilling, with minimal time in between the jobs for turning the tools around. The technology used the latest generation sensors, algorithms, computations and was a first in Malaysia. The campaign re-instituted the clear value of information in the given environment and saving cost.

Extreme Well Electrical Submersible Pump: Altering Perception in Artificial Lift Selection

Electrical Submersible Pump (ESP) is an artificial lift that often associated with big production rate, which is at least 300 bbls/day. ESP also has limitation in handling unconsolidated sand reservoir, high GOR wells, and minimum casing ID. As technology flourished, these handicaps for an ESP well are no longer valid. A breakthrough was established for ESP utilization. However people's perception of ESP persists. Extreme well ESP is changing that perception. There are three types of extreme well ESP: high solid content, high GOR, and slim-line ESP. High solid content ESP has open impellers. This type of impeller creates no space between impeller and diffuser, hence no solids accumulation. Multiphase pump (MPP) is used to handle high GOR problem. MPP stage design has axial screw type impeller and gas handling diffuser. Gas from reservoir fluid will be compressed and broken into smaller bubbles resulting in homogenous gas-liquid mixture, hence no gas lock during production. For well with small casing ID e.g., 4-1/2" casing, slim-line ESP with 3.19" outside diameter is utilized. These three types of extreme well ESP were all utilized in Central Sumatera Asset of Pertamina EP. High solid content ESPs were installed in five wells (MJ-134, MJ-132, MJ-128, STT-25, and KTT-23) in four different structures with production range of 30 to 1200 bbls/day. Basic Sediment (BS) number in this asset varies from 0.1% up to 40%, which results in suspending wells and repeating well services. In wells MJ-134, high solid content ESP was able to produce up to 50% BS number at the beginning of production. It showed excellent lifting capability in severe sand problem condition. While in wells STT-25 and KTT-23, utilizing high solid content ESP increases well's lifetime and generates gain in production. High GOR ESPs were installed in wells PPS-01 and SGC-15. Both wells has around 2000 scf/stb GOR. Conventional ESP would have a hard time producing these gassy wells. By using MPP, well PPS-01 produced smoothly and even later optimized to have bigger production. Producing well SGC-15 faced another handicap in form of scale deposition. Scale preventer was also installed for this well. Slim-line ESP was installed in well BJG-01 that has 4-1/2" casing. Grossing up the wells with slim-line ESP contributes production gain. Since October 2019 this project has produced cumulative production of 56,199 bbls oil and counting, and been considered successful in solving extreme well problems. Being proven able to handle high BS number, high GOR, and produce well with small casing size, extreme well ESP is altering old mindset in ESP utilization. All of handicaps mentioned above were redeemed obsolete. This breakthrough starts the dawn of new perception in artificial lift selection.

Big Entrance Hole Perforation as New Alternative Approach to Optimize Thru-Tubing Sand Control Technique While Maintaining Reservoir Deliverability for Tunu Gas Reservoir in Unconsolidated Sand Formation

Mahakam block with one of its gas fields, Tunu, has been developed for decades. Hundreds of wells were drilled to unlock layered sand reservoirs ranging from unconsolidated to consolidated reservoirs. Through field experience, well architecture is actively developing. The latest architecture, targeting shallow reservoirs only, is called Shallow Light Architecture (SLA). The well is completed with 3.5in production tubing cemented inside a 8.5in open-hole reservoir section. SLA is the default architecture for chemical sand consolidation (SCON) or thru-tubing screens as subsurface sand control. Perforation is performed by deep penetration (DP) hollow-carrier guns deployed with double-density to maximize open area and reduce sand production risk. DP charges were used based on the requirement to bypass near-wellbore damage, which is the same practice used in consolidated sand reservoir perforating. As more marginal reservoirs need to be unlocked, big entrance hole (BEH) perforation was initiated for the current sand control optimization alternative by SCON chemical reduction with shorter perforation intervals; and for thru-tubing metal screen performance improvement by placement in front of perforation entrance tunnels with minimum erosion risk. BEH was then studied as it has never been used previously in Mahakam with thru-tubing applications. Simulation and pilot well trials were explored to ensure that a short penetration would not significantly impact reservoir delivery on SLA wells. Inflow performance relationship (IPR) analysis resulted in slight additional drawdown compared to the calculated drawdown using DP at 2.5 MMscfd as an average gas rate in current thru-tubing sand control, which was considered acceptable from the operating envelope perspective. In total, BEH perforation was executed on ten wells with reservoir permeability range from 220 millidarcy (mD) to an extreme case of 3000 mD. Various SCON treatments were injected at optimized perforation lengths by cutting chemical costs up to 60% with sand-free production at a particular parameter and chemical type. On the other hand, in the application using screens, evaluation was not conclusive due to screen sizing issues for some installations. However, in-situ gas velocity could be reduced to the theoretical erosion velocity limit for a metal screen. This new approach to BEH charges utilization has a potential solution optimizing current SCON costs while also reducing erosion risk for the through tubing screen application to improve its performance. By using short penetration of charges, this approach was successfully implemented without jeopardizing reservoir's deliverability.

Pore Volume Compressibility of Unconsolidated Sand Reservoirs: Insights Gained Using Laboratory-Created Sand Pack Analogs

Pore volume compressibility is a fundamental driver of production for unconsolidated sand reservoirs. Prediction of compressibility is desirable when direct measurements on core are not available. Many characteristics of reservoir sands change simultaneously. For this reason, the controls on compressibility are difficult to isolate and interpret. We present the results of compaction experiments using laboratory-created, unconsolidated sands. In these analog sands, we change one textural or mineralogical parameter at a time to investigate the influence of that parameter on the measured compaction properties. Initially, simple quartz grain packs of varying grain sizes were used. Subsequently, additional parameters were investigated, including grain packing, angularity, sorting, feldspar content, ductile grain content, small volumes of dispersed clay, and initial sample preconditioning at stress. Multiple samples of each type were created and tested. This allowed the testing to be halted at several intermediate stresses and the samples to be examined using 2D and 3D imaging and image analysis techniques. For monomineralic quartz sand packs, grain size is a principal control on compressibility. As mean size increases from 150 to 450 μm, peak compressibility increases from 6 to 24 microsips. The depletion stress at which peak compressibility occurs decreases from 8,000 to 2,500 psi. Increasing grain angularity also increases compressibility but with smaller effect. For 150-μm quartz sands, increasing the angularity resulted in an increase in compressibility from 6 microsips for round quartz to 10 microsips for angular quartz and decreased the depletion stress required to achieve peak compressibility from 8,000 to 7,000 psi. As sorting varies from well to moderately poorly sorted, compressibility decreases, and the curve broadens as a function of depletion stress. Adding small volumes of feldspar (or other minerals that cleave) increases the compressibility more than the change resulting from changes in grain size, illustrating the importance of framework grain composition. Adding similar volumes of ductile grains results in a similar increase in compressibility to that observed for feldspar. However, when the size of the ductile grains is larger than that of the associated quartz (e.g., locally derived rip-up clasts), the increase in compressibility is significantly larger. To validate the experimental work, we compare the results of uniaxial pore volume compressibility tests on laboratory-created sands with measurements made on subsurface samples of similar texture and mineralogy. Both the shape of the compressibility curves as well as the magnitude of the compressibility are successfully reproduced. We conclude that laboratory-created sands can provide reasonable proxies for estimating the compressibility of subsurface reservoirs when intact subsurface samples are not available for measurement (e.g., only percussion sidewall samples are acquired) as long as mineralogy and texture are known.

Development of Flood Defense Alternaives for the Beach of Deir El Balah Camp, Palestine

The development along the coastal zone has led to the host of problems such as erosion, siltation, flooding, loss of coastal resources and the destruction of the fragile marine habitats. The erosion threatens the coastal zone, which affects people's economic, tourist, and recreational life. The main reason of the erosion is due to Khan Younis breakwater and the sea waves working on empty the beachy sand, thereby flooding and scouring the area as it ebbs and removing part of the unconsolidated sand. This study uses Geographic Information System to detect changes in the coastline along Deir El Balah coast during the 1972–2020 period. Shoreline change rates in the form of erosion and accretion patterns are quantified. In addition, four alternatives are proposed to to mitigate the current problems raised by repeated flooding and erosion through reefballs, cubes, geotubes and seawalls and analyze their impacts on coastal protection to provide the best possible mitigations in environmental, economical and engineering terms. Multi criteria analysis is used to assess the alternatives with respect to criteria that capture the key dimensions of the selection process. Multi criteria have been selected and addressed the most important factors when planning, designing, financing, and implementing coastal protection measures. Based on the analysis, the best alternative of three-row reefballs submerged breakwaters is recommended.

Archaeological and Natural Indicators of Sea-Level and Coastal Changes: The Case Study of the Caesarea Roman Harbor

Archaeological and geomorphological features, as well as traces left by tsunamis, earthquakes, and vertical earth-crust displacements, are used to identify sea-level and coastal changes. Such features may be displaced, submerged or eroded by natural processes and human activities. Thus, identifying ancient sea levels and coastal changes associated with such processes may be controversial and often leads to misinterpretations. We exemplify the use of sediment deposits and sea-level and coastline indicators by discussing the enigmatic demise of the Roman harbor of Caesarea, one of the greatest marine constructions built in antiquity, which is still debated and not fully understood. It was suggested that the harbor destruction was mainly the result of either tectonic subsidence associated with a local, active fault line, or as a result of an earthquake/tsunami that struck the harbor. Here we examine and reassess the deterioration of the harbor in light of historical records, and geological, geomorphological and archaeological studies of natural and man-made features associated with the harbor. We show that the alleged evidence of an earthquakes or tsunami-driven damage to the outer breakwaters is equivocal. There is no supporting evidence for the assumed tectonic, active fault, nor is there a reliable historic account of such a catastrophic destruction. It is suggested that geo-technic failure of the breakwater’s foundations caused by a series of annual winter storms was the main reason for the destruction and ultimate collapse of the western basin of the harbor. The breakwaters were constructed on unconsolidated sand that was later washed away by storm waves and sea currents that frequently hit the Israeli coast and undercut the breakwaters. The pounding effect of the waves could have contributed to the destruction by scouring and liquefying the sandy seabed underlying the foundations. Tsunamis that may have hit Caesarea could have added to the deterioration of the breakwaters, but did not constitute the main cause of its destruction.